<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
____________________________
FORM 10-K
AMENDMENT NO. 1
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [Fee Required]
For fiscal year ended December 31, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [No fee Required]
Registrant; State of
Incorporation or
Commission Organization; Address; I.R.S.Employer
File Number and Telephone Number Identification No
- ------------ ---------------------- ------------------
1-3446 NEW ENGLAND ELECTRIC SYSTEM 04-1663060
(A Massachusetts voluntary
association)
25 Research Drive
Westborough, Massachusetts 01582
Telephone: 508-389-2000
1-6564 NEW ENGLAND POWER COMPANY 04-1663070
(A Massachusetts corporation)
25 Research Drive
Westborough, Massachusetts 01582
Telephone: 508-389-2000
0-5464 MASSACHUSETTS ELECTRIC COMPANY 04-1988940
(A Massachusetts corporation)
25 Research Drive
Westborough, Massachusetts 01582
Telephone: 508-389-2000
1-7471 THE NARRAGANSETT ELECTRIC COMPANY 05-0187805
(A Rhode Island corporation)
280 Melrose Street
Providence, Rhode Island 02907
Telephone: 401-784-7000
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
(X) Yes ( ) No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. (X)
<PAGE>
The purpose of this Amendment is to file electronically with
the Commission those exhibits to the Form 10-K for the year ended
December 31, 1994, previously supplied in paper format. New
exhibit indexes are supplied for each filing company.
<PAGE>
NEW ENGLAND ELECTRIC SYSTEM
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this Amendment No. 1 to Form 10-K to be signed on its behalf, by
the undersigned thereunto duly authorized.
NEW ENGLAND ELECTRIC SYSTEM
s/John G. Cochrane
____________________________
John G. Cochrane
Attorney-in-fact
Date: June 22, 1995
The name "New England Electric System" means the trustee or
trustees for the time being (as trustee or trustees but not
personally) under an agreement and declaration of trust dated
January 2, 1926, as amended, which is hereby referred to, and a
copy of which as amended has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation or
liability made, entered into or incurred by or on behalf of New
England Electric System binds only its trust estate, and no
shareholder, director, trustee, officer or agent thereof assumes
or shall be held to any liability therefor.
<PAGE>
NEW ENGLAND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this Amendment No. 1 to Form 10-K to be signed on its behalf, by
the undersigned thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters
having reference to such company.
NEW ENGLAND POWER COMPANY
s/John G. Cochrane
____________________________
John G. Cochrane
Attorney-in-fact
Date: June 22, 1995
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this Amendment No. 1 to Form 10-K to be signed on its behalf, by
the undersigned thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters
having reference to such company.
MASSACHUSETTS ELECTRIC COMPANY
s/John G. Cochrane
____________________________
John G. Cochrane
Attorney-in-fact
Date: June 22, 1995
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this Amendment No. 1 to Form 10-K to be signed on its behalf, by
the undersigned thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters
having reference to such company.
THE NARRAGANSETT ELECTRIC COMPANY
s/John G. Cochrane
____________________________
John G. Cochrane
Attorney-in-fact
Date: June 22, 1995
<PAGE>
NEES
EXHIBIT INDEX
---------------
Exhibit No. Description Page
- ----------- ----------- ----
(3) Agreement and Declaration of Filed herewith
Trust dated January 2, 1926,
as amended through April 28,
1992
(4)(a) Massachusetts Electric Company Previously
First Mortgage Indenture and filed
Deed of Trust, dated as of
July 1, 1949, and twenty
supplements thereto
(4)(b) The Narragansett Electric Previously
Company First Mortgage Indenture filed
and Deed of Trust, dated as of
September 1, 1944, and twenty-one
supplements thereto
(4)(c) The Narragansett Electric Previously
Company Preference Provisions, filed
as amended, dated March 23, 1993
(4)(d) New England Power Company General Previously
and Refunding Mortgage Indenture filed
and Deed of Trust dated as of
January 1, 1977 and nineteen
supplements thereto
(10)(a) Boston Edison Company et al. and Previously
New England Power Company: filed
Amended REMVEC Agreement dated
August 12, 1977
(10)(b) The Connecticut Light and Power Previously
Company et al. and New England filed
Power Company: Sharing Agreement
for Joint Ownership, Construction
and Operation of Millstone Unit No.
3 dated as of September 1, 1973, and
Amendments thereto; Transmission
Support Agreement dated August 9,
1974; Instrument of Transfer to NEP
with respect to the 1979 Connecticut
Nuclear Unit, and Assumption of
Obligations, dated December 17, 1975
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(c) Connecticut Yankee Atomic Power Previously
Company et al. and New England filed
Power Company: Stockholders
Agreement dated July 1, 1964;
Power Purchase Contract dated
July 1, 1964; Supplementary
Power Contract dated as of
April 1, 1987; Capital Funds
Agreement dated September 1,
1964; Transmission Agreement
dated October 1, 1964;
Agreement revising Transmission
Agreement dated July 1, 1979;
Guarantee Agreement dated as of
November 13, 1981; Guarantee
Agreement dated as of August 1,
1985
(10)(d) Maine Yankee Atomic Power Company Previously
et al. and New England Power filed
Company: Capital Funds Agreement
dated May 20, 1968 and Power
Purchase Contract dated May 20,
1968; Amendments dated as of
January 1, 1984, March 1, 1984,
October 1, 1984, and August 1,
1985; Stockholders Agreement
dated May 20, 1968; Additional
Power Contract dated as of
February 1, 1984; Guarantee
Agreement dated as of September 23,
1985
(10)(e)(i) New England Energy Incorporated Previously
Capital Funds Agreement with filed
NEES dated November 1, 1974 and
Amendments thereto
(10)(e)(ii) New England Energy Incorporated Previously
Loan Agreement with NEES dated filed
July 19, 1978 and effective
November 1, 1974, and Amendments
thereto
(10)(e)(iii) New England Energy Incorporated Previously
Fuel Purchase Contract with filed
New England Power Company dated
July 26, 1979, and Amendments
thereto
(10)(e)(iv) New England Energy Incorporated Previously
Partnership Agreement with filed
Samedan Oil Corporation as
Amended and Restated on
February 5, 1985 and Amendment
thereto
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(e)(v) New England Energy Incorporated Previously
Credit Agreement dated as of filed
April 28, 1989 and Amendments
thereto
(10)(e)(vi) New England Energy Incorporated Previously
Capital Maintenance Agreement filed
dated November 15, 1985, and
Assignment and Security Agreement
dated November 15, 1985 and
Amendment thereto
(10)(f) New England Power Company and Previously
New England Electric Transmission filed
Corporation et al.: Phase I
Terminal Facility Support
Agreement dated as of December 1,
1981 and Amendments thereto;
Agreement with respect to Use
of the Quebec Interconnection
dated as of December 1, 1981
and Amendments thereto; Agreement
for Reinforcement and Improvement
of New England Power Company's
Transmission System dated as of
April 1, 1983; Lease dated as of
May 16, 1983; Upper Development -
Lower Development Transmission
Line Support Agreement dated as
of May 16, 1983
(10)(g) New England Electric Transmission Previously
Corporation and PruCapital filed
Management, Inc. et al: Note
Agreement dated as of
September 1, 1986; Mortgage,
Deed of Trust and Security
Agreement dated as of
September 1, 1986; Equity
Funding Agreement with New
England Electric System dated
as of December 1, 1985
(10)(h) Vermont Electric Transmission Previously
Company, Inc. et al. and New filed
England Power Company: Phase I
Vermont Transmission Line
Support Agreement dated as
of December 1, 1981 and
Amendments thereto
(10)(i) New England Power Pool Previously
Agreement and Amendments thereto filed
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(j) Public Service Company of New Previously
Hampshire et al. and New England filed
Power Company: Agreement for
Joint Ownership, Construction
and Operation of New Hampshire
Nuclear Units dated as of
May 1, 1973 and Amendments
thereto; Transmission Support
Agreement dated as of May 1,
1973; Instrument of Transfer
to NEP with respect to the
New Hampshire Nuclear Units
and Assumptions of Obligations
dated December 17, 1975;
Agreement Among Participants
in New Hampshire Nuclear Units,
certain Massachusetts Municipal
Systems and Massachusetts
Municipal Wholesale Electric
Company dated May 28, 1976;
Seventh Amendment To and Restated
Agreement for Seabrook Project
Disbursing Agent and Amendments
thereto; Seabrook Project
Managing Agent Operating
Agreement dated as of June 29,
1992, and Amendment to Seabrook
Project Managing Agent Agreement
dated as of June 29, 1992
(10)(k) Vermont Yankee Nuclear Power Previously
Corporation et al. and New filed
England Power Company: Capital
Funds Agreement dated
February 1, 1968, Amendment
dated March 12, 1968, and Power
Purchase Contract dated
February 1, 1968 and Amendments
thereto; Additional Power
Contract dated as of February 1,
1984; Guarantee Agreement dated
as of November 5, 1981
(10)(l) Yankee Atomic Electric Company Previously
et al. and New England Power filed
Company: Amended and Restated
Power Contract dated April 1,
1985 and Amendments thereto
(10)(m) New England Electric Companies' Previously
Deferred Compensation Plan as filed
amended dated December 8, 1986
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(n) New England Electric System Previously
Companies Retirement Supplement filed
Plan as amended dated April 1,
1991
(10)(o) New England Electric Companies' Previously
Executive Supplemental Retirement filed
Plan as amended dated April 1,
1991
(10)(p) New England Electric Companies' Previously
Incentive Compensation Plan as filed
amended dated January 1, 1992
(10)(q) New England Electric Companies' Previously
Senior Incentive Compensation filed
Plan as amended dated November 26,
1991
(10)(r) New England Electric Companies' Previously
Incentive Compensation Plan II filed
as amended dated September 3,
1992
(10)(s) New England Electric System Previously
Directors Deferred Compensation filed
Plan as amended dated
November 24, 1992
(10)(t) Forms of Life Insurance Program Previously
and Form of Life Insurance filed
(Collateral Assignment)
(10)(u) New England Power Company and Previously
New England Hydro-Transmission filed
Electric Company, Inc. et al:
Phase II Massachusetts
Transmission Facilities Support
Agreement dated as of June 1,
1985 and Amendments thereto
(10)(v) New England Power Company and Previously
New England Hydro-Transmission filed
Corporation et al: Phase II
New Hampshire Transmission
Facilities Support Agreement
dated as of June 1, 1985 and
Amendments thereto
(10)(w) New England Power Company et Previously
al: Phase II New England Power filed
AC Facilities Support Agreement
dated as of June 1, 1985 and
Amendments thereto
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(x) New England Hydro-Transmission Previously
Electric Company, Inc. and New filed
England Electric System et al:
Equity Funding Agreement dated
as of June 1, 1985 and Amendments
thereto
(10)(y) New England Hydro-Transmission Previously
Corporation and New England filed
Electric System et al: Equity
Funding Agreement dated as of
June 1, 1985 and Amendments
thereto
(10)(aa) Ocean State Power, et al., and Previously
Narragansett Energy Resources filed
Company: Equity Contribution
Agreement dated as of
December 29, 1988; Amendment
dated as of September 29, 1989
Ocean State Power, et al., and Previously
New England Electric System: filed
Equity Contribution Support
Agreement dated as of
December 29, 1988; Amendment
dated as of September 29, 1989;
Ocean State Power II, et al., Previously
and Narragansett Energy Resources filed
Company: Equity Contribution
Agreement dated as of September 29,
1989
Ocean State Power II, et al., Previously
and New England Electric System: filed
Equity Contribution Support
Agreement dated as of
September 29, 1989
(10)(bb) New England Power Service Previously
Company and Joan T. Bok: filed
Service Credit Letter dated
October 21, 1982
(10)(cc) New England Electric System Previously
and John W. Rowe: Service filed
Credit Letter dated
December 5, 1988
(10)(dd) New England Power Service Previously
Company and the Company: filed
Form of Supplemental Pension
Service Credit Agreement
<PAGE>
NEES
EXHIBIT INDEX
-------------
(10)(ee) New England Electric System Filed herewith
and Frederic E. Greenman:
Service Credit Letter dated
February 23, 1994
(10)(ff) New England Electric System Filed herewith
and John W. Newsham: Pension
Service Credit Agreement dated
February 23, 1994
(13) 1994 Annual Report to Filed herewith
Shareholders
(21) Subsidiary list Previously
filed
(24) Power of Attorney Filed herewith
(27) Financial Data Schedule Filed herewith
<PAGE>
NEP
EXHIBIT INDEX
-------------
Exhibit No. Description Page
- ----------- ----------- ----
(3)(a) Articles of Organization as Previously
amended through June 27, 1987 filed
(3)(b) By-laws of the Company as Previously
amended June 25, 1987 filed
(4) General and Refunding Mortgage Previously
Indenture and Deed of Trust filed
dated as of January 1, 1977
and nineteen supplements
thereto
(10)(a) Boston Edison Company et al. Previously
and the Company: Amended filed
REMVEC Agreement dated
August 12, 1977
(10)(b) The Connecticut Light and Power Previously
Company et al. and the Company: filed
Sharing Agreement for Joint
Ownership, Construction and
Operation of Millstone Unit No. 3
dated as of September 1, 1973,
and Amendments thereto;
Transmission Support Agreement
dated August 9, 1974; Instrument
of Transfer to the Company with
respect to the 1979 Connecticut
Nuclear Unit, and Assumption of
Obligations, dated December 17,
1975
(10)(c) Connecticut Yankee Atomic Power Previously
Company et al. and the Company: filed
Stockholders Agreement dated
July 1, 1964; Power Purchase
Contract dated July 1, 1964;
Supplementary Power Contract
dated as of April 1, 1987;
Capital Funds Agreement dated
September 1, 1964
Transmission Agreement dated Previously
October 1, 1964; Agreement filed
revising Transmission Agreement
dated July 1, 1979; Five Year
Capital Contribution Agreement
dated November 1, 1980;
Guarantee Agreement dated as
of November 13, 1981; Guarantee
Agreement dated as of August 1,
1985
<PAGE>
NEP
EXHIBIT INDEX
-------------
(10)(d) Maine Yankee Atomic Power Previously
Company et al. and the Company: filed
Capital Funds Agreement dated
May 20, 1968 and Power Purchase
Contract dated May 20, 1968;
and Amendments thereto;
Stockholders Agreement dated
May 20, 1968; Additional Power
Contract dated as of February 1,
1984; Guarantee Agreement dated
as of September 23, 1985
(10)(e) Mass. Electric and the Company: Previously
Primary Service for Resale dated filed
February 15, 1974; and Amendments
thereto
Memorandum of Understanding Filed herewith
effective May 22, 1994
(10)(f) The Narragansett Electric Previously
Company and the Company: filed
Primary Service for Resale
dated February 15, 1974
and Amendments thereto;
Memorandum of Understanding
effective May 22, 1994
(10)(g) Time Charter between Previously
Intercoastal Bulk Carriers, filed
Inc., and New England Power
Company dated as of December 27,
1989
(10)(h) New England Electric Previously
Transmission Corporation et al. filed
and the Company: Phase I
Terminal Facility Support
Agreement dated as of
December 1, 1981; Amendments
dated as of June 1, 1982 and
November 1, 1982; Agreement with
respect to Use of the Quebec
Interconnection dated as of
December 1, 1981; Amendments
dated as of May 1, 1982 and
November 1, 1982; Amendment
dated as of January 1, 1986;
<PAGE>
NEP
EXHIBIT INDEX
-------------
(10)(h) Agreement for Reinforcement
(cont.) and Improvement of the Company's
Transmission System dated as
of April 1, 1983; Lease dated
as of May 16, 1983; Upper
Development-Lower Development
Transmission Line Support
Agreement dated as of May 16,
1983
(10)(i) Vermont Electric Transmission Previously
Company, Inc. et al. and the filed
Company: Phase I Vermont
Transmission Line Support
Agreement dated as of
December 1, 1981 and Amendments
thereto
(10)(j) New England Energy Incorporated Previously
and the Company: Fuel Purchase filed
Contract dated July 26, 1979,
and Amendments thereto
(10)(k) New England Power Pool Previously
Agreement and Amendments filed
thereto
(10)(l) New England Power Service Filed herewith
Company and the Company:
Specimen of Service Contract
(10)(m) Public Service Company of New Previously
Hampshire et al. and the filed
Company: Agreement for Joint
Ownership, Construction and
Operation of New Hampshire
Nuclear Units dated as of
May 1, 1973 and Amendments
thereto; Seventh Amendment
as of November 1, 1990;
Transmission Support Agreement
dated as of May 1, 1973;
Instrument of Transfer to the
Company with respect to the New
Hampshire Nuclear Units and
Assumptions of Obligations
dated December 17, 1975 and
Agreement Among Participants
in New Hampshire Nuclear Units,
certain Massachusetts Municipal
Systems and Massachusetts
Municipal Wholesale Electric
Company dated May 28, 1976;
Seventh Amendment To and
Restated Agreement for Seabrook
<PAGE>
NEP
EXHIBIT INDEX
-------------
(10)(m) Project Disbursing Agent dated
(cont.) as of November 1, 1990;
Amendments dated as of
June 29, 1992
Settlement Agreement dated as Previously
of July 19, 1990 between filed
Northeast Utilities Service
Company and the Company
Seabrook Project Managing Previously
Agent Operating Agreement filed
dated as of June 29, 1992;
and Amendment thereto
(10)(n) Vermont Yankee Nuclear Power Previously
Corporation et al. and the filed
Company: Capital Funds
Agreement dated February 1,
1968, Amendment dated March 12,
1968 and Power Purchase Contract
dated February 1, 1968 and
Amendments thereto; Additional
Power Contract dated as of
February 1, 1984; Guarantee
Agreement dated as of November 5,
1981
(10)(o) Yankee Atomic Electric Company Previously
et al. and the Company: filed
Amended and Restated Power
Contract dated April 1, 1985
and Amendments thereto
(10)(p) New England Electric Companies' Previously
Deferred Compensation Plan as filed
amended dated December 8,
1986
(10)(q) New England Electric System Previously
Companies Retirement Supplement filed
Plan as amended dated April 1,
1991
(10)(r) New England Electric Companies' Previously
Executive Supplemental Retirement filed
Plan as amended dated April 1,
1991
(10)(s) New England Electric Companies' Previously
Incentive Compensation Plan as filed
amended dated January 1, 1992;
New England Electric Companies'
Senior Incentive Compensation
Plan as amended dated November 26,
1991
<PAGE>
NEP
EXHIBIT INDEX
-------------
(10)(t) Forms of Life Insurance Program Previously
and Form of Life Insurance filed
(Collateral Assignment)
(10)(u) New England Electric Companies' Previously
Incentive Compensation Plan II filed
as amended dated September 1,
1992
(10)(v) New England Hydro-Transmission Previously
Electric Company, Inc. et al. filed
and the Company: Phase II
Massachusetts Transmission
Facilities Support Agreement
dated as of June 1, 1985
and Amendments thereto
(10)(w) New England Hydro-Transmission Previously
Corporation et al. and the filed
Company: Phase II New Hampshire
Transmission Facilities Support
Agreement dated as of June 1,
1985 and Amendments thereto
(10)(x) Vermont Electric Power Company Previously
et al. and the Company: Phase filed
II New England Power AC
Facilities Support Agreement
dated as of June 1, 1985 and
Amendments thereto
(10)(y) TransCanada Pipelines Limited Previously
and the Company: Firm Service filed
Contract for Firm Transportation
Service for natural gas dated
as of January 6, 1992 and
Amendment dated as of March 2,
1992
Amendment dated as of October 29, Filed herewith
1993
(10)(z) Renaissance Energy Ltd. and Filed herewith
the Company: Temporary Trans-
portation Contract Assignment
(capacity swap) for Firm
Transportation Service for
natural gas dated as of October
27, 1993
Amendment dated as of October 25, Filed herewith
1994
<PAGE>
NEP
EXHIBIT INDEX
-------------
(10)(aa) Algonquin Gas Transmission Previously
Company and the Company: X-38 filed
Service Agreement for Firm
Transportation of natural gas
dated July 3, 1992; Amendment
dated July 31, 1992
Amendment dated as of April 15, Filed herewith
1994
(10)(bb) ANR Pipeline Company and the Previously
Company: Gas Transportation filed
Agreement dated July 18, 1990
(10)(cc) Columbia Gas Transmission Previously
Corporation and the Company: filed
Service Agreement for Service
under FTS Rate Schedule dated
June 13, 1991
(10)(dd) Iroquois Gas Transmission Previously
System, L.P. and the Company: filed
Gas Transportation Contract for
Firm Reserved Service dated as
of June 5, 1991
(10)(ee) Tennessee Gas Pipeline Company Previously
and the Company: Firm Natural filed
Gas Transportation Agreement
dated July 9, 1992
(12) Statement re computation of Previously
ratios for incorporation by filed
reference into NEP registration
statements on Form S-3,
Commission File Nos. 33-48257,
33-48897, and 33-49193
(13) 1994 Annual Report to Filed herewith
Stockholders
(21) Subsidiary list Previously
filed
(24) Power of Attorney Filed herewith
(27) Financial Data Schedule Filed herewith
<PAGE>
Mass. Electric
--------------
EXHIBIT INDEX
-------------
Exhibit No. Description Page
- ----------- ----------- ----
(3)(a) Articles of Organization of the Previously
Company as amended through filed
November 15, 1993
(3)(b) By-Laws of the Company as Previously
amended through September 15, filed
1993
(4) First Mortgage Indenture and Previously
Deed of Trust, dated as of filed
July 1, 1949, and twenty
supplements thereto
(10)(a) Boston Edison Company et al. Previously
and Company: Amended REMVEC filed
Agreement dated August 12,
1977
(10)(b) New England Power Company Previously
and the Company: Primary filed
Service for Resale dated
February 15, 1974; Amendment
of Service Agreement dated
July 22, 1983; Amendment of
Service Agreement effective
November 1, 1993; Memorandum
of Understanding effective
May 22, 1994
(10)(c) New England Power Pool Previously
Agreement and Amendments filed
thereto
(10)(d) New England Power Service Previously
Company and the Company: filed
Specimen of Service Contract
(10)(e) New England Telephone and Previously
Telegraph Company and the filed
Company: Specimen of Joint
Ownership Agreement for Wood
Poles
(10)(f) New England Electric Companies' Previously
Deferred Compensation Plan as filed
amended dated December 8, 1986
(10)(g) New England Electric System Previously
Companies Retirement Supplement filed
Plan as amended dated April 1,
1991
<PAGE>
Mass. Electric
--------------
EXHIBIT INDEX
-------------
(10)(h) New England Electric Companies' Previously
Executive Supplemental Retirement filed
Plan as amended dated April 1,
1991
(10)(i) New England Electric Companies' Previously
Incentive Compensation Plan as filed
amended dated January 1, 1992
(10)(j) New England Electric Companies' Previously
Form of Deferred Compensation filed
Agreement for Directors
(10)(k) New England Electric Companies' Previously
Senior Incentive Compensation filed
Plan as amended dated
November 26, 1991
(10)(l) Forms of Life Insurance Program Previously
and Form of Life Insurance filed
(Collateral Assignment)
(10)(m) New England Electric Companies' Previously
Incentive Compensation Plan II filed
as amended dated September 1,
1992
(10)(n) New England Power Service Previously
Company and the Company: filed
Form of Supplemental Pension
Service Credit Agreement
(13) 1994 Annual Report to Filed herewith
Stockholders
(24) Power of Attorney Filed herewith
(27) Financial Data Schedule Filed herewith
<PAGE>
Narragansett
-------------
EXHIBIT INDEX
-------------
Exhibit No. Description Page
- ----------- ----------- ----
(3)(a) Articles of Incorporation as Previously
amended June 9, 1988 filed
(3)(b) By-Laws of the Company Previously
filed
(4)(a) First Mortgage Indenture and Previously
Deed of Trust, dated as of filed
September 1, 1944, and
twenty-one supplements thereto
(4)(b) The Narragansett Electric Previously
Company Preference Provisions, filed
as amended, dated March 23, 1993
(10)(a) Boston Edison Company et al. Previously
and the Company: Amended REMVEC filed
Agreement dated August 12, 1977
(10)(b) New England Power Company and Previously
the Company: Primary Service for filed
Resale dated February 15, 1974;
Amendment of Service Agreement
dated July 24, 1991; Amendment of
Service Agreement effective November
1, 1993; Memorandum of Understanding
effective May 22, 1994
(10)(c) New England Power Pool Agreement Previously
and Amendments thereto filed
(10)(d) New England Power Service Previously
Company and the Company: filed
Specimen of Service Contract
(10)(e) New England Telephone and Previously
Telegraph Company and the filed
Company: Specimen of Joint
Ownership Agreement for Wood
Poles
(10)(f) New England Electric Companies' Previously
Deferred Compensation Plan for filed
Officers, as amended December 8,
1986
(10)(g) New England Electric System Previously
Companies Retirement Supplement filed
Plan, as amended April 1, 1991
<PAGE>
Narragansett
-------------
EXHIBIT INDEX
-------------
(10)(h) New England Electric Companies' Previously
Executive Supplemental Retirement filed
Plan, as amended dated April 1,
1991
(10)(i) New England Companies' Incentive Previously
Compensation Plan, as amended filed
dated January 1, 1992
(10)(j) New England Electric Companies' Previously
Form of Deferred Compensation filed
Agreement for Directors
(10)(k) New England Electric Companies' Previously
Senior Incentive Compensation filed
Plan as amended dated November 26,
1991
(10)(l) Forms of Life Insurance Program Previously
and Form of Life Insurance filed
(Collateral Assignment)
(10)(m) New England Electric Companies' Previously
Incentive Compensation Plan II filed
as amended dated September 1,
1992
(10)(n) New England Power Service Previously
Company and the Company: filed
Form of Supplemental Pension
Service Credit Agreement
(12) Statement re computation of Previously
ratios for incorporation by filed
reference into the Narragansett
registration statement on Form
S-3, Commission File No. 33-50015
(13) 1994 Annual Report to Filed herewith
Stockholders
(24) Power of Attorney Filed herewith
(27) Financial Data Schedule Filed herewith
<PAGE>
Exhibit 3
CERTIFICATE OF AMENDMENT
of the
AGREEMENT AND DECLARATION OF TRUST
of
NEW ENGLAND ELECTRIC SYSTEM
We, the undersigned, being two of the Directors and the
Secretary of New England Electric System, hereby certify that on
April 28, 1992, at a meeting duly called for the purpose on at
least twenty (20) days' notice, the shareholders of New England
Electric System, by a vote of a majority of the shares present or
represented at the meeting, authorized the following amendment to
the Agreement and Declaration of Trust of New England Electric
System, as previously amended, and that on said day the Board of
Directors of New England Electric System by two-thirds vote
amended said Agreement and Declaration of Trust, in accordance
with the provisions of Article 57 thereof, so that Articles 20,
42, 44, 51, and 54 thereof shall read as follows:
Article 20 (the first four sentences):
20. The action of the Board of Directors in respect of any
matter shall be by vote or resolution passed by the Board at
a meeting. Regular meetings of the Board of Directors may
be held at such places and at such times as the Board may by
vote from time to time determine, and if so determined no
notice thereof need be given. A regular meeting of the
Board may be held without notice immediately after and at
the same place as the annual meeting of the Shareholders or
a special meeting of the Shareholders held in lieu of such
annual meeting. A special meeting of the Board of Directors
may be held at any time and at any place when called by the
president, secretary or two or more Directors, by giving to
each of the Directors reasonable notice thereof, and,
without implied limitation, a notice thereof, sent through
the post-office in a prepaid letter addressed to any
Director, at his usual address, and posted in the United
States, at least forty-eight (48) hours before such meeting,
shall be deemed sufficient notice to such Director, whether
the same be received by him or not, and in computing such
time Sundays and holidays shall be included.
Article 42:
42. An annual meeting of the Shareholders shall be held on
the fourth Tuesday of April in every year, or on such other
date as the Board of Directors may from time to time fix, at
such place designated in the notice, at which meeting the
Board of Directors shall lay before the Shareholders
financial statements for the last financial year preceding
<PAGE>
such meeting, and any question may be presented to them or
any report of the Board of Directors, or any Director,
Trustee, officer, agent or employee of these trusts may be
laid before them by the Trustee or by the Board of
Directors, president or treasurer of the Company. Purposes
for which an annual meeting is to be held additional to
those prescribed by law and by these presents may be
specified by the Trustee or by the Board of Directors,
president or treasurer of the Company. If such annual
meeting is omitted on the day herein provided therefor, a
special meeting may be held in lieu thereof, and any
business transacted or election held at such special meeting
shall have the same effect as if transacted or held at the
annual meeting.
Article 44:
44. The Trustee or the Board of Directors, president or
treasurer of the Company may whenever they think fit, and
the president or secretary of the Company, upon a written
request of the holders of one tenth of all the shares at the
time outstanding and carrying the right to vote, shall, call
or direct any officer of these trusts to call a special
meeting of the Shareholders to be held at such place
designated in the notice. Every such request shall express
the purpose of the meeting and shall be delivered at the
principal office of these trusts addressed to the president
or secretary of the Company, and in case the said president
or secretary shall refuse or fail, for fourteen (14) days
after the request shall have been so delivered, to call such
special meeting to be held within thirty (30) days after the
delivery of the request, the same may be called by the
person or persons signing such request or by any three (3)
of them. And a special meeting may also be called by the
holders of one tenth of the said shares whenever the offices
of the Directors shall be entirely vacant.
Article 51:
51. For the purpose of determining the Shareholders who are
entitled to receive payment of any dividend, or who are
entitled to vote or act at any meeting or any adjourned
session thereof, or who are entitled to receive any offering
pursuant to Article 31 hereof, the Board of Directors may
from time to time close the register and transfer books for
such period, not exceeding sixty (60) days, as the Board may
determine; or, without closing the said register or transfer
books, the Board may fix a time not more than sixty (60)
days before the dividend payment date or the meeting or
adjourned session or the date of the offering, as of which
the Shareholders entitled to such dividend or entitled to
vote or act at any meeting or adjourned session or entitled
to such offering shall be determined.
<PAGE>
Article 54:
54. Every notice to any shareholder required or provided
for in these presents may be given to him personally or by
sending it to him through the post-office in a prepaid
letter addressed to him at his address specified in the
share register, and posted in the United States, and shall
be deemed to have been given at the time when it is so
posted. But in respect of any share held jointly by several
persons notice so given to any one of them shall be
sufficient notice to all of them. And any notice so sent to
the registered address of any Shareholder shall be deemed to
have been duly sent in respect of any such share whether
held by him solely or jointly with others, notwithstanding
he be then deceased or be bankrupt or insolvent, and whether
the Directors or Trustee or any person sending such notice
have knowledge or not of his death, bankruptcy or
insolvency, until some other person or persons shall be
registered as holders. And the certificate of the person or
persons giving such notice shall be sufficient evidence
thereof, and shall protect all persons acting in good faith
in reliance on such certificate.
IN WITNESS WHEREOF we have signed this certificate this 11th
day of May, 1992.
s/ John W. Rowe
______________________________
Director
s/ Joan T. Bok
______________________________
Director
s/ Frederic E. Greenman
______________________________
Secretary
<PAGE>
THE COMMONWEALTH OF MASSACHUSETTS
On this 11th day of May, 1992, at Westborough,
Massachusetts, before me, a Notary Public within and for the
Commonwealth, appeared the above named Joan T. Bok and
acknowledged that she acknowledged that she executed the
foregoing instrument as her free act and deed.
Witness my hand and official seal Westborough,
Massachusetts.
s/ Renee M. Kossuth
___________________________________
Notary Public
My commission expires: April 24, 1998
The foregoing has been duly presented and registered this
____ day of May, 1992.
THE FIRST NATIONAL BANK OF BOSTON
Trustee of New England Electric System
s/ Mark Nelson
By: ___________________________________
Authorized Officer
<PAGE>
Exhibit 10(ee)
NEW ENGLAND ELECTRIC SYSTEMNew England Electric System
25 Research Drive
Westborough, Massachusetts 01582-0001
Telephone: (508) 366-9011
John W. Rowe
President and Chief Executive
Officer
February 23, 1994
Mr. Frederic E. Greenman
25 Research Drive
Westborough, MA 01582
Dear Fred:
This confirms my oral advice to you of the action taken
February 21, 1994, in order to recognize your legal experience
prior to joining New England Power Service Company (NEPSCO). It
is agreed that, for retirement benefit calculation purposes, your
service with NEPSCO will be considered as commencing February 1,
1964; provided, however, your total service for retirement
benefit calculation purposes under this letter will not exceed 30
years.
A copy of this statement will be placed in your personal
file.
Very truly yours,
s/ John W. Rowe
<PAGE>
Exhibit 10(ff)
NEW ENGLAND ELECTRIC SYSTEMNew England Electric System
25 Research Drive
Westborough, Massachusetts 01582-0001
Telephone: (508) 366-9011
John W. Rowe
President and Chief Executive
Officer
February 23, 1994
Mr. John W. Newsham
25 Research Drive
Westborough, MA 01582
Dear John:
This confirms my oral advice to you of the action taken
February 21, 1994, in order to recognize your service for New
England Power Service Company and its affiliates. It is agreed
that upon termination of employment, you will receive in the
January following the year in which you terminate employment, a
payment as follows:
Year of Termination Amount
------------------- ------
1994 $150,000
1995 120,000
1996 90,000
1997 60,000
1998 30,000
Thereafter 0
A copy of this statement will be placed in your personal
file.
Very truly yours,
s/ John W. Rowe
<PAGE>
[ART WORK APPEARS HERE]
Annual Report 1994
[LOGO] NEW ENGLAND ELECTRIC SYSTEM
<PAGE>
In 1994, NEES delivered its sixth consecutive year of superior earnings,
and did so in an increasingly competitive environment, with electric rates
that were the lowest among major electric utility systems in New England.
<PAGE>
[ART WORK APPEARS HERE]
New England Electric System
The NEES subsidiaries include:
Massachusetts Electric Company, The Narragansett Electric Company, and Granite
State Electric Company, retail electric companies that provide electricity and
related services to 1.3 million customers in 197 communities in Massachusetts,
Rhode Island, and New Hampshire;
New England Power Company, a wholesale electric generating company that
operates five thermal generating stations, 14 hydroelectric generating
stations, a pumped storage station, and approximately 2,400 miles of
transmission lines;
New England Electric Resources, Inc., an independent project development and
consulting company that seeks investment opportunities in power plant
modernization, transmission, and environmental improvement;
New England Electric Transmission Corporation, New England Hydro-Transmission
Corporation, and New England Hydro-Transmission Electric Company, Inc.,
electric transmission companies that developed, own, and operate facilities
associated with the high voltage, direct current interconnection between New
England and Quebec;
Narragansett Energy Resources Company, a wholesale electric generating company
that owns 20 percent of the Ocean State Power generating station in Rhode
Island;
New England Energy Incorporated, an oil and gas exploration and development
company;
New England Power Service Company, a service company that provides
administrative, legal, engineering, and other support to the affiliated NEES
subsidiaries.
<PAGE>
Financial Highlights
1994 1993
---- ----
Earnings per average share $ 3.07 $ 2.93
Dividends declared per share $2.285 $ 2.22
Book value per share-year end $24.33 $ 23.55
Market price per share-year end $32-1/8 $39-1/8
Growth in kilowatthour (KWH) sales
billed to ultimate customers 1.6% 1.4%
Cost per KWH to ultimate customers (cents) 9.29 9.50
New England Electric System (NEES) is a public utility holding company
headquartered in Westborough, Massachusetts. The NEES family of companies,
described on the inside page to the left, constitutes the second largest
electric utility system in New England. Core business activities are the
generation, transmission, distribution, and sale of electric energy and the
delivery of related services, including energy efficiency improvements, to
residential, commercial, industrial, and municipal customers. Other business
activities include independent transmission projects and energy management
consultation. The NEES companies are guided by the following commitment: "We
pledge to provide our customers the highest possible value by continuously
improving electric service, managing costs, and reducing adverse environmental
impacts."
Contents
Letter to Shareholders 2
Winning in A Changing Business 4
Improving Our Competitive Position 5
Financial Review 16
Financial Statements 25
Notes to Financial Statements 30
Report of Management 43
Report of Independent Accountants 43
Shareholder Information 44
System Directors and Officers -
System Subsidiaries 45
Return on Common Equity - 1994
New England Electric System 12.7%
Median of U.S. Electric Utilities 11.4%
Median of New England/New York Electric Utilities 11.4%
<PAGE>
To Our Fellow Shareholders
The year 1994 was another good one for the New England Electric System
(NEES). Among our accomplishments:
Earnings per common share increased to $3.07 compared with $2.93 in 1993.
Return on equity was 12.7 percent, placing us in the top one-third of major
electric utility systems in New England and New York for the sixth consecutive
year. This is a record unmatched by any other electric utility in the region
Our return on equity also places us in the top quartile of major electric
utilities across the nation.
Bond ratings for NEES subsidiaries were A+ or higher, reflecting our attention
to the balance sheet as well as the income statement.
Your dividend was increased to $2.30 per share in May 1994. Dividend growth
over the past five years has exceeded both the regional and national averages
for major electric utilities.
Our fossil-fueled power plants set new records for availability and our
demand-side management programs continued to provide both profits for
shareholders and savings for customers.
While our region has higher energy costs than much of the nation, NEES
has consistently performed with superior efficiency. Our current average
retail rate of 9.3 cents per kilowatthour is the lowest among major electric
utility systems in New England, and is slightly lower than our average rate of
each of the past two years.
As you know, our share price dropped during 1994, largely as a result of
rising interest rates. However, the drop was in line with that experienced by
other utilities. Over the past five years, NEES shares have outperformed the
average electric utility stock, and our market performance, as measured by
market to book ratio, continues to lead the region.
During the past year, proposals for increased competition have affected
the structure, operations, and financial position of the electric utility
industry. While competition has been with us in various forms for many years,
the Federal Energy Regulatory Commission (FERC) is now developing ground rules
for wide-open competition in wholesale electricity markets, and many state
commissions, including those that regulate the NEES retail companies, are
evaluating proposals for competition within the traditional retail service
franchise. NEES's response to these trends has been to adapt quickly to
changing market conditions while preserving our focus on business
fundamentals: first, the cost and quality of our service; second, the quality
of our assets and the length of our financial commitments; third, the
environmental impact of our operations; and finally, the fairness of the rules
that regulate our operations. This response has allowed us to continue to
profit in a rapidly evolving regulatory environment.
[PHOTO OF JOAN BOK Joan T. Bok,
APPEARS HERE] Chairman of the Board
<PAGE>
During 1994, we reached important agreements that reinforce our long-term
competitive position. We have signed service extension discount (SED)
contracts with 82 percent of our large commercial and industrial customers in
Massachusetts and Rhode Island. Through these contracts, customers agree to
give us three to five years notice before generating their own electricity or
changing electricity suppliers, and in exchange receive a 5 percent base rate
discount (see page 17 for details.) An agreement reached in December 1994
with certain state agencies, municipal light departments, and large commercial
and industrial customers and approved by the FERC in February 1995 will hold
our wholesale subsidiary New England Power's rates at their present level
until at least 1997. An agreement with more than a dozen environmental,
recreational, and governmental organizations, currently before the FERC for
approval, would expedite the relicensing of our hydroelectric generating
facilities along the Deerfield River, and has enhanced our reputation for
environmental commitment.
While the next few years are likely to be difficult for our industry,
NEES has a track record of prospering in difficult times. We have
continuously been one of the quickest to adapt to new public policies and one
of the most efficient in making these policies work. This flexibility has
helped us receive fair treatment from regulators. We strive to be less
costly, more profitable, more agile, and more green than our competitors. We
have hard working, hard thinking employees who want to win, who have a record
of winning, and who are determined to continue winning. With their support,
we believe our consistent and unequivocal commitment to enhancing shareholder
value will make NEES a rewarding investment in the future as it has been in
the past.
We thank you for your continued investment and confidence in the New
England Electric System.
s/ Joan T. Bok s/ John W. Rowe
Joan T. Bok John W. Rowe
Chairman of the Board President and Chief Executive Officer
February 27, 1995
NEES' Key Financial Goals - 1994 Results
Dividend Growth exceeds
average of electric utilities on
rolling 5-year average.
Return on Equity in top one-third
of major New York and New
England utilities.
Cash Flow coverage of dividend
in top one-third of major electric
utilities.
Investment Quality Auditors'
reports not qualified and bond
ratings A+.
Total Return in top one-third of
major electric utilities on rolling
5-year average.
Achieved goals in blue
Non-achieved goal in gray
John W. Rowe, President [PHOTO OF JOHN W. ROWE
and Chief Executive Officer APPEARS HERE]
<PAGE>
Winning in a Changing Business
Unique responsibilities and commensurate rights have shaped the evolution
of the electric utility industry. In exchange for exclusive rights to supply
electricity within franchise areas, utilities have served all customers under
rates set by regulators, projected long-term needs for electricity, and built
or purchased power from facilities to meet those long-term needs.
Shareholders have backed these large capital commitments required to build the
facilities due to the promise of an opportunity to earn a fair return on their
investments.
Historically, utilities built the generating plants, transmission lines,
and distribution systems needed within their service territories. In the
early 1980s, however, operators of independent generating plants began to
compete with utilities to produce power that could be sold on the "wholesale"
market to utilities. The Energy Policy Act of 1992 established a national
policy favoring more wholesale competition; this policy has been implemented
at both the state and federal levels. As wholesale competition grows and
various states consider new forms of competition, transmission and
distribution wires are likely to remain closely regulated.
With the market for electricity and related services becoming more
competitive, the operating environment for all electric utilities will become
more complex and more risky. A decisive response to these new competitive
pressures is essential to maintain our strong financial performance and our
regional position as a high-value, low-cost provider of electricity and
related services.
Here are some examples of the steps we have taken to improve our
competitive position.
<PAGE>
Improving Our Competitive
Position
Customer Focus 6
Competitive Marketplace 8
Environment 10
New Rules 12
A History of Responding
to Challenges 14
<PAGE>
Customer Focus
We continue to expand the array of energy services we provide directly to
our customers. At Dartmouth College in Hanover, N.H., our programs have
resulted in energy-efficient lighting in the campus library, athletic
facilities, and student cultural center as well as computerized control of
heating, ventilation, and air conditioning in one of the science labs. At the
college's math and computer science building, we are now implementing a pilot
program in which all energy-related equipment and control processes within a
single building-not just those involving electricity-are monitored and
adjusted to make sure they are performing optimally.
A view from the customer's side of the meter led to the development of
EnergyFIT-integrated services for energy conservation, power quality,
cogeneration assessment, and electrotechnology evaluations that are customized
to meet the needs of our largest and most energy-intensive business customers.
EnergyFIT makes business customers more efficient, productive, and profitable,
and helps to strengthen our relationship with them.
EnergyFIT services encouraged Kopin Corporation, a manufacturer of active
matrix liquid crystal displays, to establish a new manufacturing facility in
Westborough, Mass.; developed ways for Nyman Mfg. Co. in East Providence, R.I.
to produce plastic dinnerware at lower energy cost; and helped a 105-year-old
firm, Crown Yarn Dye Co., Inc. in Attleboro, Mass., to continue custom dyeing
operations for companies throughout the U.S.
[ONE HALF OF MORTARBOARD PHOTO
APPEARS HERE]
<PAGE>
In addition to serving existing customers, all of the NEES companies are
participating in efforts to attract new businesses to the region. We recognize
that many businesses are carefully weighing energy costs before choosing new
locations. The Coca-Cola Company chose Northampton, Mass. over two communities
served by other electric companies for a bottling plant for its non-carbonated
products. Massachusetts Electric created a service package that offered
economic development rates and a substantial investment in energy efficiency
as part of the pull to attract the plant and the 150 to 250 associated jobs to
Northampton. Our success and that of the region are well served by working
with customers to get the most for their energy dollars.
[ONE HALF OF MORTARBOARD PHOTO
APPEARS HERE]
Douglas Smith, senior [PHOTO OF DOUGLAS SMITH
technical representative, APPEARS HERE]
is a member of the
Massachusetts Electric
team that created a
service package to help
attract a Coca-Cola
Company bottling plant
to our service territory.
<PAGE>
Competitive Marketplace
We are increasing our efforts to protect the share of the market that we
now serve, increase customer awareness of our new products and services, and
develop new business ventures.
One emerging market in which NEES has already established a strong
position is the construction, operation, and/or ownership of transmission
facilities outside our service territory. During the 1980s, we managed the
construction of the Hydro-Quebec Phase 1 and 2 direct current interconnection,
a large project in which most New England utilities participated. In 1994,
Nantucket Cable Electric Company, Inc., a new company established by NEES, was
selected to design, construct, and maintain a 27-mile-long undersea and
underground transmission cable linking the island of Nantucket to mainland
Massachusetts. This project is expected to be in operation in early 1997, and
will provide Nantucket residents with improved service, more stable
electricity costs, and - because it will replace diesel generators now in use
on the island - a more environmentally-friendly energy supply.
To pursue transmission projects worldwide, the NEES subsidiary New
England Electric Resources, Inc. (NEERI) is teaming up with Sweden's ABB Power
Systems, one of the world's leading suppliers of transmission equipment and
Paul Stasiuk, senior analyst, evaluates
electrotechnologies in the commercial
food-service industry for the NEES
companies. Much of his recent work
involves the electric cooking center at
Johnson & Wales University.
[PHOTO OF PAUL STASIUK APPEARS HERE]
[ONE HALF OF LIGHTHOUSE PHOTO
APPEARS HERE]
<PAGE>
services. NEERI will help provide utility managers worldwide with innovative
options for developing and financing transmission systems. These ventures
will build on our established leadership in large-scale transmission projects.
Promoting clean and efficient electrotechnologies that replace the use of
other energy sources is another way for the NEES companies to be the energy
supplier of choice. NEES's three retail subsidiaries joined to sponsor a new
cooking center at the world's largest college of culinary arts, Johnson and
Wales University in Providence. This cooking center is the focal point for
evaluating newly developed electric cooking equipment that incorporates
features--such as quick temperature adjustment-preferred by many cooks and
readily available in competing gas equipment. Showcased as a "high tech cook-
off," the center is set up to enable detailed, side-by-side comparisons of
commercial gas and electric cooking equipment. Data are being collected to
compare the quality of the finished food, overall labor and energy efficiency,
and health benefits of food handling for competing state-of-the-art gas and
electric cooking technologies. This electric cooking center provides energy-
efficient electrotechnologies for our customer, Johnson and Wales; exposes
future chefs to the best electric cooking equipment available; and can help to
strengthen the market for our core product.
[ONE HALF OF LIGHTHOUSE PHOTO
APPEARS HERE]
<PAGE>
Environment
Cost-effective environmental improvement will continue to be a
fundamental challenge for electric utilities. Success often requires
cooperation among many interested parties. In 1994, we advanced our efforts
to secure a 40-year federal license for New England Power's eight
hydroelectric dams on the Deerfield River with an agreement among
environmentalists, anglers, white water enthusiasts, and state and federal
resource agencies. The agreement was designed to expedite licensing and avoid
litigation. It is the culmination of more than five years of negotiation and
will enhance recreation, fisheries, and conservation in the Deerfield Valley.
New England Power has made substantial reductions in air emissions a
cornerstone of its operational goals. The company remains an industry leader
in using innovative emission controls on existing fossil-fueled power plants.
Our 1994 emissions, compared with 1990 levels, were 45 percent lower for
sulfur dioxide, 23 percent lower for nitrogen oxides, and 11 percent lower for
carbon dioxide. In February 1995, we announced a voluntary commitment to
reduce greenhouse gas emissions by 20 percent below 1990 levels by the year
2000 as part of President Clinton's Climate Challenge Program. This emissions
reduction target is among the most ambitious of the commitments made by
participating utilities.
[ONE HALF OF CANOE PHOTO
APPEARS HERE]
<PAGE>
[ONE HALF OF CANOE PHOTO
APPEARS HERE]
The Manchester Street Station repowering project, scheduled for
completion in late 1995, will use a more efficient and
environmentally-friendly gas-fired power generating technology while more than
tripling this Rhode Island plant's output to 489 megawatts (MW). The station
is located in a densely populated urban area at the head of Narragansett Bay
and across the river from Providence's treasured historic district. Our
activities are closely coordinated with other major projects that are
revitalizing the Providence downtown and waterfront. We have considered the
needs of neighbors in every detail of the plant construction and continue to
receive their enthusiastic support.
The NEES companies' efforts to promote more sustainable energy supplies
include a planned project to produce energy from biomass fuels such as wood
and organic waste. We have also received regulatory approval for energy
purchases from seven projects that will provide 36 MW of capacity through wind
power, waste heat recovery, and the use of landfill methane and municipal
solid waste as fuels.
Paula Hamel, senior
environmental engineer, [PHOTO OF PAULA HAMEL APPEARS HERE]
works with contractors
and city, state, and
federal agencies to ensure
that Manchester Street
Station repowering activities
meet environmental and
safety requirements.
<PAGE>
New Rules
Since non-utilities were allowed to enter the wholesale generation
market, New England Power has relied on all available options to meet its
requirements. During that time, two-thirds of New England Power's new net
generating capability has come from independent generating sources and
Hydro-Quebec. The company is now working on new rules to make wholesale
competition more efficient through reform of the New England Power Pool and
the creation of a Regional Transmission Group.
We now face various proposals to permit retail competition. A common
feature of nearly all such proposals is that utilities would be required to
open both their transmission and distribution systems to competitors and to
customers. If this happens, the goal of producing a more efficient
electricity market will best be accomplished by ensuring that all users of a
utility's wires pay their share of all of the costs committed by utilities to
build the present electric system. Along with the Conservation Law
Foundation, we have proposed a concept, called by some the "Grand Bargain," to
recover these fixed costs through a system access charge.
As part of this Bargain, the NEES companies would be willing to spin off
or sell our transmission system, invest in environmental improvement ahead of
new requirements, and continue investments in conservation and renewable
energy. The new, independent transmission company would then offer comparable
Masheed Hegi, consulting engineer,
negotiates transmission agreements [PHOTO OF MASHEED HEGI
between the NEES companies and other APPEARS HERE]
users and providers of transmission
services. She is currently participating
in the effort to develop a New England
Regional Transmission Agreement.
[ONE HALF OF PEN PHOTO
APPEARS HERE]
<PAGE>
transmission access and pricing to all competing power suppliers. This "Grand
Bargain" would provide benefits to both customers and shareholders. In the
near term, rates could be reduced by lengthening the period over which we
recover certain costs. In the long term, rates should also be reduced by
increased customer responsibility for generation choices and increased market
pressure on suppliers. Shareholders would benefit from clear provisions for
the recovery of the cost of past commitments.
In Massachusetts, the Division of Energy Resources (DOER) recently
proposed that when new generating capacity is needed, retail customers with an
aggregate load equal to the needed capacity be allowed to bid for access to
utility wires. The winning bidders could then choose their electricity
supplier. This proposal would provide customer choice and leave NEES its
existing revenue base to pay for its past commitments. We support the DOER
proposal.
Other proposals for "retail wheeling" would permit access to utility
wires at low cost and force generating prices down to short-run operating
costs. In our view, these proposals would deny all utilities the opportunity
to recover their past commitments to which we believe they are entitled. If
retail competition is permitted, a fair system must permit utilities to charge
a fee for access to their transmission and distribution system which will
enable them to recover all of their fixed costs.
In summary, we are exerting all of our efforts to assure that new rules
are written under which New England Electric System and other well-run utility
systems have an opportunity to succeed in the competitive marketplace.
[ONE HALF OF PEN PHOTO
APPEARS HERE]
<PAGE>
A History of Responding to Challenges
The 1960s brought about tremendous increases in the demand for
electricity, and our wholesale subsidiary expanded its capacity to meet that
demand. The 1970s brought about oil embargoes, and we diversified our fuel
mix. The late 1970s and early 1980s brought inflation and the high costs
associated with the construction of the Seabrook and Millstone 3 nuclear
plants; we responded by diversifying our power purchases and by incorporating
energy conservation into resource planning. In each of these decades, NEES
developed progressive and innovative solutions that allowed us to provide
excellent financial results for our shareholders.
Now, in the 1990s, increased competition is on the minds of executives
and shareholders in the electric utility industry. Our proven ability to
anticipate change and successfully adapt is increasingly important in meeting
today's challenges.
<PAGE>
Financial Report
Financial Review 16
Financial Statements
Selected Financial Data 25
Consolidated Income 26
Consolidated Retained
Earnings 26
Consolidated Balance
Sheets 27
Cash Flow 28
Capitalization 29
Notes to Financial
Statements 30
Report of Management 43
Report of Independent
Accountants 43
Shareholder Information 44
<PAGE>
Financial Review
[GRAPH APPEARS HERE]
Overview
Earnings in 1994 were $3.07 per share compared with $2.93 and $2.85 per
share in 1993 and 1992, respectively. The return on 1994 common equity was
12.7 percent.
The improvement in 1994 earnings reflects increased kilowatthour (KWH)
sales to ultimate customers, decreased purchased power expense and interest
expense, and the amortization of unbilled revenues. In addition, earnings in
1993 were reduced by the one-time effects of an early retirement program and
the establishment of additional gas waste reserves. These factors were
partially offset by increased operation and maintenance expenses and a
temporary rate reduction (see "Retail rate activity" section).
The increase in 1993 earnings over 1992 was primarily the result of
increased KWH sales, reduced interest costs, and lower costs of scheduled
overhauls at wholly-owned thermal generating units, partially offset by the
combined effects of the one-time items described above.
KWH sales billed to ultimate customers in 1994 increased by 1.6 percent
over 1993, reflecting an improved economy. KWH sales in 1993 increased 1.4
percent over 1992 sales, reflecting more normal weather conditions in 1993
compared with 1992, partially offset by the fact that 1992 included an extra
day for leap year. New England Electric System (NEES) retail subsidiaries
currently forecast an increase in KWH sales of less than 1 percent in 1995.
The annual dividend rate was raised by 2.7 percent, or $.06 per share, in
May 1994 and is now $2.30 on an annual basis. In 1993, the annual dividend
rate was increased by 3.7 percent, or $.08 per share. The market price of NEES
common shares at year end 1994 was $32 1/8 per share, compared with $39 1/8
per share and $38 1/2 per share at the end of 1993 and 1992, respectively.
Wholesale rate activity
In February 1995, the Federal Energy Regulatory Commission (FERC)
approved a rate agreement filed by New England Power Company (NEP). Under the
agreement, which is effective January 1995, NEP's base rates will be frozen
until 1997. Before this rate agreement, NEP's rate structure contained two
surcharges which were recovering the costs of a coal conversion project and a
portion of NEP's investment in the Seabrook 1 Nuclear Unit (Seabrook 1).
Under the rate agreement, these two surcharges, which were due to expire in
mid-1995, will be rolled into base rates. The agreement also provides for the
costs resulting from the Manchester Street Station repowering project, which
is expected to be completed in late 1995, to be included in rate base, without
a rate increase (see "Liquidity and capital resources" section). In addition,
the agreement allows NEP to recover approximately $50 million of deferred
costs associated with terminated purchased power contracts and postretirement
benefits other than pensions (PBOPs) over seven years. The agreement also
provides for full current recovery of PBOP costs commencing in 1995. The
agreement further provides for the recovery over three years of $27 million of
costs related to the dismantling of a retired generating station and the
replacement of a turbine rotor at one of NEP's generating units. The
agreement also increases NEP's recovery of depreciation expense by
approximately $8 million annually to recognize costs associated with the
eventual dismantling of its Brayton Point and Salem Harbor generating plants.
Under the agreement, approximately $15 million of the $38 million in
Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement
agreement will be deferred and recovered in 1996. The agreement further allows
for deferral of additional purchased power contract termination costs and any
increases in nuclear decommissioning payments for recovery in future rates.
Yankee Atomic Electric Company, of which NEP is a 30 percent owner, recently
announced a new decommissioning cost estimate, which, if approved by the FERC,
would increase annual billings to NEP by $11 million, beginning in late 1995
and ending in July 2000.
<PAGE>
The settlement rates provide for approximately $24 million in revenues in
1996 to complete the amortization of pre-1988 Seabrook 1 costs and the costs
associated with the cancelled Seabrook 2 nuclear unit. To the extent the
settlement rates stay in effect beyond 1996, the agreement provides that these
revenues be applied first to accelerate recovery of deferred PBOP costs, and
then to additional amortization of NEP's investment in the Millstone 3 nuclear
unit.
The FERC's approval of this rate agreement applies to all of NEP's
customers except the Town of Norwood, Massachusetts and the Milford Power
Limited Partnership (MPLP), who intervened in the rate case. A separate
hearing will be conducted to determine the appropriate rate to charge these
two parties, who represent less than 2 percent of NEP's sales.
Retail rate activity
In 1993, the Massachusetts Department of Public Utilities (MDPU) approved
a rate agreement filed by Massachusetts Electric Company (Massachusetts
Electric), the Massachusetts Attorney General, and two groups of large
commercial and industrial customers.
Under the agreement, effective December 1, 1993, Massachusetts Electric
implemented an 11 month general rate decrease of $26 million (annual basis).
This rate reduction continued in effect through October 31, 1994, at which
time rates increased to the previously approved levels. Massachusetts Electric
also agreed not to further increase its base rates before October 1, 1995.
The agreement also provided for the recognition of unbilled revenues for
accounting purposes. Unbilled revenues at September 30, 1993 of approximately
$35 million were amortized to income over 13 months commencing December 1993.
The agreement further provided for rate discounts for large commercial
and industrial customers who signed agreements to give a five-year notice to
Massachusetts Electric before they purchase power from another supplier or
generate any additional power themselves. The notice provision may be reduced
from five to three years under certain conditions. The aggregate amount of
these service extension discounts (SEDs) was $4 million during 1994 but will
increase in 1995 to approximately $10 million per year under the terms of the
agreement.
The agreement also resolved all rate recovery issues associated with
environmental remediation costs of Massachusetts manufactured gas waste sites
formerly owned by Massachusetts Electric and its affiliates, as well as
certain other Massachusetts Electric environmental cleanup costs (see
"Hazardous waste" section).
Effective October 1992, the MDPU authorized a $45.6 million annual
increase in rates for Massachusetts Electric.
In July 1994, the Rhode Island Public Utilities Commission (RIPUC)
approved a rate agreement between The Narragansett Electric Company
(Narragansett) and the Rhode Island Division of Public Utilities and Carriers
that provides for SEDs to large commercial and industrial customers under
terms similar to the Massachusetts Electric program described above. The
aggregate amount of Narragansett's discounts was $1.5 million in 1994 and is
expected to be approximately $3 million per year thereafter. The agreement
also provides for Narragansett to recognize unbilled revenues for accounting
purposes. Unbilled revenues at December 31, 1993 of approximately $14 million
are being amortized to income over a 21 month period that began in April 1994.
Each of the NEES retail subsidiaries is likely to file a rate case with
its respective state regulatory agency during 1995.
Demand-side management
The retail companies regularly file their demand-side management (DSM)
programs with their respective regulatory agencies and have received approval
to recover DSM program expenditures in rates on a current basis. These
expenditures were $70 million, $62 million, and $58 million in 1994, 1993, and
[GRAPH APPEARS HERE]
<PAGE>
1992, respectively. Since 1990, the retail companies have been allowed to
earn incentives based on the results of their DSM programs. The retail
companies must be able to demonstrate the electricity savings produced by
their DSM programs to their respective state regulatory agencies before
incentives are recorded. The retail companies recorded before-tax incentives
of $7.7 million, $7.3 million, and $10.5 million in 1994, 1993, and 1992,
respectively. The retail companies have received regulatory orders that will
give them the opportunity to continue to earn incentives based on 1995 DSM
program results.
[GRAPH APPEARS HERE]
Operating revenue
Operating revenue increased $9 million in 1994, primarily reflecting
increased KWH sales and amortization of unbilled revenues by retail
subsidiaries, partially offset by the temporary rate reduction at
Massachusetts Electric. KWH sales billed to ultimate customers in 1994
increased by 1.6 percent over 1993, reflecting an improved economy.
Operating revenue increased by $52 million in 1993, primarily due to
increased KWH sales, retail rate increases, and beginning in the fourth
quarter of 1993, the recognition by Massachusetts Electric of unbilled
revenues. KWH sales billed to ultimate customers in 1993 increased 1.4
percent over 1992. More normal weather conditions in 1993 compared with 1992
were largely offset by the fact that 1992 included an extra day for leap year.
Operating expenses
Total operating expenses increased by $15 million in 1994 over 1993,
reflecting increases in generating plant maintenance costs associated with
overhauls of wholly-owned generating units in part to achieve compliance with
the Clean Air Act. Operating expenses in 1994 also reflected cost increases
in DSM, computer system development, pension and other retiree benefits, and
general increases in other areas. These increases were partially offset by
decreases in fuel and purchased power expense due to overhauls and refueling
shutdowns of partially-owned nuclear power suppliers in 1993. In addition,
1993 operating expenses included a net amount of $30 million associated with
an early retirement and special severance program and the establishment of
additional gas waste reserves, partially offset by the effects of a rate
settlement that allowed recovery of amounts previously charged to expense.
Depreciation and amortization increased $4 million in 1994, reflecting
increased amortization of the net investment in Seabrook 1, increased charges
for dismantlement of a previously retired generating station, and depreciation
of new plant expenditures. These increases were partially offset by decreased
oil and gas amortization due to decreased production.
Taxes charged to operations in 1994 increased by approximately $12
million, reflecting increased income taxes and municipal property taxes.
Total operating expenses increased by $55 million in 1993, reflecting a
$28 million charge associated with the early retirement offer referred to
above, $10 million due to the adoption of two new accounting standards for
postemployment benefits, increased computer systems development costs, and
general increases in other areas. These increases were partially offset by a
decrease in generating plant maintenance costs and reduced winter
storm-related costs.
Depreciation and amortization decreased $6 million in 1993, reflecting
reduced amortization of oil and gas properties due to decreased production.
NEP's expense also declined as a result of new lower depreciation rates
established in its 1992 rate case. These decreases were partially offset by
increased amortization of Seabrook 1 as part of NEP's 1988 rate settlement and
increased depreciation on new plant expenditures.
Taxes charged to operations in 1993 increased by approximately $17
million, reflecting higher municipal property taxes and increased income
taxes, including the effects of the increase in the federal income tax rate in
1993 from 34 percent to 35 percent.
<PAGE>
Interest expense
Interest expense decreased $6 million and $9 million in 1994 and 1993,
respectively, due to significant refinancings of corporate debt at lower
interest rates during 1993 and 1992.
Allowance for funds used during construction (AFDC)
AFDC increased in 1994 and 1993 by $11 million and $2 million,
respectively, due to increased construction work in progress associated with
the repowering of the Manchester Street Station (see "Liquidity and capital
resources" section).
Oil and gas operations
New England Energy Incorporated (NEEI) participates in a rate-regulated
domestic oil and gas exploration, development, and production program
consisting of prospects acquired prior to December 31, 1983. NEEI is not
acquiring any new prospects. Due to precipitate declines in oil and gas
prices, NEEI has incurred operating losses since 1986, and expects to incur
substantial additional losses in the future. These losses are being passed on
to NEP under an intercompany pricing policy approved by the Securities and
Exchange Commission. NEP is allowed to recover these losses from its
customers under NEP's 1988 FERC rate settlement, which covered all costs
incurred by or resulting from commitments made by NEEI through March 1, 1988.
Other subsequent costs incurred by NEEI are subject to normal regulatory
review.
Hazardous waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. NEES
subsidiaries currently have in place an environmental audit program intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
NEES and/or its subsidiaries have been named as a potentially responsible
party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 22 sites at which
hazardous waste is alleged to have been disposed. Private parties have also
contacted or initiated legal proceedings against NEES and certain subsidiaries
regarding hazardous waste cleanup. The most prevalent types of hazardous
waste sites with which NEES and its subsidiaries have been associated are
manufactured gas locations. (Until the early 1970s, NEES was a combined
electric and gas holding company system.) NEES is aware of approximately 40
such locations (including seven of the 22 locations for which NEES companies
are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are
currently aware of other sites, and may in the future become aware of
additional sites, that they may be held responsible for remediating.
NEES has been notified by the EPA that it is one of several PRPs for
cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, at
which coal tar and other materials were deposited. Between 1931 and 1951,
NEES and its predecessor owned all of the common stock of Green Mountain Power
Corporation (GMP). Prior to, during, and after that time, gas was
manufactured at the Pine Street Canal site by GMP. In 1989, NEES was one of 14
parties required to pay the EPA's past response costs related to this site.
NEES remains a PRP for ongoing and future response costs. In November 1992,
the EPA proposed a cleanup plan estimated by the EPA to cost $50 million. In
June 1993, the EPA withdrew this cleanup plan in response to public concern
about the plan and its cost. It is uncertain at this time what the cost of
any ultimate cleanup plan will be or what NEES's share of such cost will be.
<PAGE>
In 1993, the MDPU approved a rate agreement filed by Massachusetts
Electric (see "Retail rate activity" section) that allows for remediation
costs of former manufactured gas sites and certain other hazardous waste sites
located in Massachusetts to be met from a non-rate recoverable
interest-bearing fund of $30 million established on Massachusetts Electric's
books. Rate recoverable contributions of $3 million, adjusted for inflation,
are added to the fund annually in accordance with the agreement. Any
shortfalls in the fund would be paid by Massachusetts Electric and be
recovered through rates over seven years.
[GRAPH APPEARS HERE]
[GRAPH APPEARS HERE]
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
NEES or its subsidiaries. Where appropriate, the NEES companies intend to
seek recovery from their insurers and from other PRPs, but it is uncertain
whether and to what extent such efforts would be successful. At December 31,
1994, NEES had total reserves for environmental response costs of $45 million
and a related regulatory asset of $13 million. NEES believes that hazardous
waste liabilities for all sites of which it is aware, and which are not
covered by a rate agreement, will not be material to its financial position.
Electric and magnetic fields (EMF)
In recent years, concerns have been raised about whether EMF, which occur
near transmission and distribution lines as well as near household wiring and
appliances, cause or contribute to adverse health effects. Numerous studies
on the effects of these fields, some of them sponsored by electric utilities
(including NEES companies), have been conducted and are continuing. Some of
the studies have suggested associations between certain EMF and health
effects, including various types of cancer, while other studies have not
substantiated such associations. It is impossible to predict the ultimate
impact on NEES subsidiaries and the electric utility industry if further
investigations were to demonstrate that the present electricity delivery
system is contributing to increased risk of cancer or other health problems.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In any
event, the NEES companies believe that they currently have adequate insurance
coverage for personal injury claims.
Several state courts have recognized a cause of action for damage to
property values in transmission line condemnation cases based on the fear that
power lines cause cancer. It is difficult to predict what the impact on the
NEES companies would be if this cause of action is recognized in the states in
which NEES companies operate and in contexts other than condemnation cases.
Bills have been introduced unsuccessfully in the past in the Rhode Island
legislature to require that transmission lines be placed underground.
Legislation has been introduced in Massachusetts that, if passed, would
require state agencies to study existing EMF-related research and make
recommendations for further legislation.
Clean air requirements
Approximately 45 percent of NEP's electricity is produced at eight older
thermal generating units in Massachusetts. Six are fueled by coal, one by
oil, and one by oil and gas. The federal Clean Air Act requires significant
reduction in utility sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions
that result from burning fossil fuels by the year 2000 to reduce acid rain and
ground-level ozone (smog).
<PAGE>
NEP is reducing SO2 emissions under Phase 1 of the federal acid rain
program that became effective in 1995. NEP is also subject to Massachusetts
SO2 and NOx reduction regulations taking effect in 1995. The SO2 and NOx
reductions that are being made to meet 1995 Phase 1 requirements have resulted
in one-time operation and maintenance costs of $16 million and capital costs
of $88 million through December 31, 1994. Additional expenditures in 1995 are
expected to be less than $10 million and $30 million, respectively. Depending
on fuel prices, NEP also expects to incur up to $5 million annually in
increased costs to purchase cleaner fuels to meet SO2 emission reduction
requirements.
All eight of NEP's thermal units will be subject to Phase 2 of the
federal and state acid rain regulations that become effective in 2000. NEP
believes that the SO2 controls already installed for the 1995 requirements
will satisfy the Phase 2 acid rain regulations.
In connection with the federal ozone emission requirements, state
environmental agencies in ozone non-attainment areas are developing a second
phase of NOx reduction regulations that would have to be fully implemented by
NEP no later than 1999. While the exact costs are not known, NEP estimates
that the cost of implementing these regulations would not jeopardize continued
operation of NEP's units.
The generation of electricity from fossil fuel also emits trace amounts
of certain hazardous air pollutants and fine particulates. An EPA study of
utility hazardous air pollutant emissions will be completed in 1995. The
study's conclusions could lead to new emission standards requiring costly
controls or fuel restrictions on NEP plants. At this time, NEES and its
subsidiaries cannot estimate the impact the findings of this research might
have on NEP's operations.
[GRAPH APPEARS HERE]
Purchased power contract dispute
In October 1994, NEP was sued by Milford Power Limited Partnership
(MPLP), a venture of Enron Corporation and Jones Capital that owns a 149
megawatt (MW) gas-fired power plant in Milford, Massachusetts. NEP purchases
56 percent of the power output of the facility under a long-term contract with
MPLP. The suit alleges that NEP has engaged in a scheme to cause MPLP and its
power plant to fail and has prevented MPLP from finding a long-term buyer for
the remainder of the facility's output. The complaint includes allegations
that NEP has violated the Federal Racketeer Influenced and Corrupt
Organizations Act, engaged in unfair or deceptive acts in trade or commerce,
and breached contracts. MPLP seeks compensatory damages in an unspecified
amount, as well as treble damages. NEP believes that the allegations of
wrongdoing are without merit. NEP has filed counterclaims and crossclaims
against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages
and termination of the purchased power contract.
MPLP also intervened in NEP's rate filing (see "Wholesale rate activity"
section).
Competitive conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of NEP's new generating capability has come from independent
generating sources and Hydro-Quebec.
Electric utilities are also facing increased competition in the retail
market. Currently, retail competition includes competition with alternative
fuel suppliers (including natural gas companies) for heating and cooling,
competition with customer-owned generation to displace purchases from electric
utilities, and direct competition among electric utilities to attract major
new facilities to their service territories. Electric utilities including the
<PAGE>
NEES companies are under increasing pressure from large commercial and
industrial customers to discount rates or face the possibility that such
customers might relocate or seek alternate suppliers. Across the country,
including the states serviced by the NEES companies, there have been an
increasing number of proposals to allow retail customers to choose their
electricity supplier, with utilities required to deliver that electricity over
their transmission and distribution systems. In Massachusetts, the
Massachusetts Division of Energy Resources (DOER) proposed in January 1995
that the MDPU modify its regulations to allow retail utility customers to
choose a supplier and bid for access to the local utility's transmission and
distribution systems in situations where new generating capacity is needed.
The NEES companies have indicated their support for the DOER proposal. Also
in Massachusetts, the MDPU initiated a proceeding in February 1995 regarding
electric industry regulation and structure. In Rhode Island, the RIPUC has
convened a task force of utilities, commercial and industrial customers,
regulators, and other interested parties to prepare a report by May 1995
regarding restructuring the industry. In New Hampshire, the New Hampshire
Public Utilities Commission is considering the proposal of a new company to
sell electricity at retail to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning and
operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could be
substantial, have been referred to by the industry as stranded costs.
[GRAPH APPEARS HERE]
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have taken
the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the FERC
ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility
may recover such stranded costs from a departing wholesale requirements
customer. On appeal, the United States Court of Appeals for the District of
Columbia Circuit has questioned whether allowing utilities to recover stranded
costs is anti-competitive and the Court remanded the case back to the FERC for
further proceedings and development of the competitive issues.
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The wholesale business unit has responded to increased competition by freezing
base rates until at least 1997 (base rates were last raised in March 1992),
terminating certain purchased power and gas pipeline contracts, shutting down
uneconomic generating stations, and accelerating the recovery of uneconomic
assets and other deferred costs. In addition, NEP's wholesale tariff requires
its wholesale customers, including NEES's retail subsidiaries, to provide
seven years notice before they may terminate the tariff.
The retail business unit's response to competition includes the EnergyFIT
program which offers comprehensive value-added services for large business
customers, intensified business development efforts, including economic
<PAGE>
development rates and service packages to encourage businesses to locate in
the retail companies' service territories, and development of new pricing and
service options for customers. Additionally, more than 80 percent of the NEES
companies' large commercial and industrial customers have signed service
extension discount (SED)contracts providing for discounts and requiring three
to five years notice before they may change electricity suppliers (see "Retail
rate activity" section). As part of their long-term planning process, the
NEES companies are from time to time evaluating other strategies, such as
business combinations and other forms of restructuring, to better respond to
the changing competitive environment.
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These accounting
rules require regulated entities, in appropriate circumstances, to establish
regulatory assets and liabilities, which defer the income statement impact of
certain costs that are expected to be recovered in future rates. The effects
of competition could ultimately cause the operations of the NEES companies, or
a portion thereof, to cease meeting the criteria for application of these
accounting rules. In such an event, accounting standards applicable to
enterprises in general would apply and immediate write-off of any previously
deferred costs (regulatory assets) would be necessary in the year in which
these criteria were no longer applicable. In addition, if, because of
competition, utilities are unable to recover all of their costs in rates, it
may be necessary to write off those costs that are not recoverable.
[GRAPH APPEARS HERE]
Liquidity and capital resources
Capital requirements for 1994 and projections for 1995 are shown below:
Year ended December 31 (millions of dollars)1994 1995
---- ----
Cash expenditures for utility plant:
Manchester Street repowering project $176 $125
All other 262 200
Oil and gas exploration and development 28 15
---- ----
Total capital expenditures $466 $340
Maturing debt and prepayment requirements35 66
---- ----
Total capital requirements $501 $406
Cash from utility operations after
payment of dividends $285 $265
Cash from oil and gas operations 57 50
---- ----
Total cash from operations after the
payment of dividends $342 $315
The funds necessary for utility plant expenditures in 1994 were primarily
provided by net cash from operating activities, after the payment of
dividends, and the proceeds of short-term and long-term borrowings.
The financing activities of the NEES subsidiaries for 1994 are summarized
as follows:
Long-term debt
----------------------------
(millions of dollars) Issues Retirements
------ -----------
NEP $28
Massachusetts Electric 36
Narragansett 33
Granite State Electric Company $ 1
Hydro-Transmission Companies 12
NEEI 22
---- ----
$97 $35
Interest rates on the long-term debt issues shown above range from 6.91
percent to 8.85 percent.
<PAGE>
Internally generated funds are expected to meet approximately 75 percent
of the 1995 capital expenditure requirements for utility plant. NEP and the
retail subsidiaries have issued $56 million of long-term debt to date in 1995
at interest rates ranging from 7.79 percent to 8.45 percent. These companies
plan to issue an additional $120 million of long-term debt later in 1995 to
meet maturing long-term debt obligations, reduce short-term debt and fund
capital expenditures.
Net cash from operating activities provided all of the funds necessary
for oil and gas expenditures. NEEI's 1994 oil and gas exploration and
development costs included $10 million of capitalized interest costs.
The NEES subsidiaries' major construction project is the repowering of
Manchester Street Station, a 140 MW electric generating station in Providence,
Rhode Island. Repowering will more than triple the power generation capacity
of Manchester Street Station and substantially increase the plant's thermal
efficiency. NEP owns a 90 percent interest and Narragansett owns a 10 percent
interest in the Manchester Street Station. The total cost for the generating
station, scheduled to be placed in service in late 1995, is estimated to be
approximately $520 million including AFDC. At December 31, 1994, $298
million, including AFDC, had been spent on the generating station. In
addition, related transmission improvements were placed in service in
September 1994 at a cost of approximately $60 million.
At December 31, 1994, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $663 million.
These lines and facilities were used at December 31, 1994 for $2 million of
direct borrowings, and for liquidity support for $232 million of commercial
paper borrowings and $342 million of NEP mortgage bonds in tax-exempt
commercial paper mode. Fees are paid on the lines and facilities in lieu of
compensating balances.
<PAGE>
New England Electric System and Subsidiaries
Selected Financial Data
Year ended December 31 (millions of dollars, except per share data)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating revenue:
Electric sales
(excluding fuel cost recovery)$1,518$1,488 $1,424 $1,358 $1,282
Fuel cost recovery 568 582 597 585 523
Other utility revenue 117 117 118 114 65
Oil and gas sales 40 47 43 37 39
------ ------ ------ ------ ------
Total operating revenue$2,243 $2,234 $2,182 $2,094 $1,909
Net income $ 199 $ 190 $ 185 $ 180 $ 262*
Average common shares
outstanding (000's) 64,970 64,970 64,970 64,917 63,818
Per share data:
Net income $3.07 $ 2.93 $ 2.85 $ 2.77 $ 4.11*
Dividends declared $2.285 $ 2.22 $ 2.14 $ 2.07 $ 2.04
Return on average
common equity 12.73% 12.64% 12.58% 12.64% 20.52%*
Total assets $5,085 $4,796 $4,585 $4,450 $4,408
Capitalization:
Common share equity $1,581 $1,530 $1,487 $1,441 $1,380
Minority interests 55 56 61 63 62
Cumulative preferred stock 147 147 162 162 162
Long-term debt 1,520 1,512 1,533 1,548 1,680
------ ------ ------ ------ ------
Total capitalization $3,303 $3,245 $3,243 $3,214 $3,284
Sales billed to ultimate
customers (millions of KWH)21,155 20,832 20,554 20,470 20,727
Cost per KWH to ultimate
customers (cents) 9.29 9.50 9.43 8.99 8.27
System maximum demand (MW)4,385 4,081 3,964 4,250 4,059
Electric capability
(MW net)-year end 5,533 5,362 5,479 5,645 5,627
Number of employees 4,990 4,969 5,415 5,533 5,666
Number of customers 1,300,1981,288,1841,277,281 1,257,2131,256,656
<FN>
*1990 includes $1.80 per share, resulting from a rate settlement related to Seabrook 1.
</FN>
</TABLE>
<PAGE>
New England Electric System and Subsidiaries
Statements of Consolidated Income
Year ended December 31 (thousands of dollars, except per share data)
1994 1993 1992
---------- ---------- ----------
Operating revenue: $2,243,029 $2,233,978 $2,181,676
Operating expenses:
Fuel for generation 220,956 227,182 237,161
Purchased electric energy514,143 527,307 525,655
Other operation 494,741 492,079 423,330
Maintenance 161,473 146,219 162,974
Depreciation and amortization301,123 296,631 302,217
Taxes, other than income taxes125,840120,493 114,027
Income taxes 128,257 121,124 110,761
--------- --------- ---------
Total operating expenses1,946,533 1,931,035 1,876,125
Operating income 296,496 302,943 305,551
Other income:
Allowance for equity funds used
during construction 10,169 3,795 2,732
Equity in income of generating
companies 9,758 11,016 13,052
Other income (expense)-net(3,856) (1,154) 936
--------- ---------- ---------
Operating and other income312,567 316,600 322,271
Interest:
Interest on long-term debt93,500 100,777 114,182
Other interest 11,298 9,809 5,420
Allowance for borrowed funds
used during construction (7,793) (2,816) (2,204)
--------- --------- ----------
Total interest 97,005 107,770 117,398
Income after interest 215,562 208,830 204,873
Preferred dividends of
subsidiaries 8,697 10,585 10,572
Minority interests 7,439 8,022 9,264
--------- --------- ---------
Net income $199,426 $190,223 $185,037
Common shares outstanding64,969,65264,969,65264,969,652
Per share data:
Net income $ 3.07 $ 2.93 $ 2.85
Dividends declared $ 2.285 $ 2.22 $ 2.14
Statements of Consolidated Retained Earnings
Year ended December 31 (thousands of dollars)
1994 1993 1992
---------- ---------- ----------
Retained earnings at
beginning of year $ 728,075 $ 684,132 $ 638,130
Net income 199,426 190,223 185,037
Dividends declared on common
shares (148,456) (144,233) (139,035)
Premium on redemption of
preferred stock of
subsidiaries (2,047)
---------- --------- ---------
Retained earnings at end
of year $ 779,045 $ 728,075 $ 684,132
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
New England Electric System and Subsidiaries
Consolidated Balance Sheets
At December 31 (thousands of dollars)
1994 1993
---------- ----------
Assets
Utility plant, at original cost $4,914,807 $4,661,612
Less accumulated provisions for depreciation and
amortization 1,610,378 1,511,271
---------- ----------
3,304,429 3,150,341
Net investment in Seabrook 1 under rate settlement
(Note C) 38,283 103,344
Construction work in progress 374,009 228,816
---------- ----------
Net utility plant 3,716,721 3,482,501
Oil and gas properties, at full cost (Note A)1,248,3431,220,110
Less accumulated provision for amortization 964,069 884,837
---------- ----------
Net oil and gas properties 284,274 335,273
Investments:
Nuclear power companies, at equity (Note D) 46,349 46,342
Other subsidiaries, at equity 42,195 44,676
Other investments 50,895 28,836
---------- ----------
Total investments 139,439 119,854
Current assets:
Cash 3,047 2,876
Accounts receivable, less reserves of $15,095
and $14,551 295,627 275,020
Unbilled revenues (Note A) 55,900 43,400
Fuel, materials, and supplies, at average cost94,431 74,314
Prepaid and other current assets 76,718 69,004
---------- ----------
Total current assets 525,723 464,614
Accrued Yankee Atomic costs (Note D) 122,452 103,501
Deferred charges and other assets (Note A) 296,232 290,135
---------- ----------
$5,084,841 $4,795,878
========== ==========
Capitalization and liabilities
Capitalization (see accompanying statements):
Common share equity $1,580,838 $1,529,868
Minority interests in consolidated subsidiaries55,066 55,855
Cumulative preferred stock of subsidiaries 147,016 147,528
Long-term debt 1,520,488 1,511,589
---------- ----------
Total capitalization 3,303,408 3,244,840
Current liabilities:
Long-term debt due within one year 65,920 12,920
Short-term debt 233,970 71,775
Accounts payable 168,937 128,342
Accrued taxes 11,002 10,332
Accrued interest 25,193 23,278
Dividends payable 37,154 36,950
Other current liabilities (Note A) 93,251 153,812
---------- ----------
Total current liabilities 635,427 437,409
Deferred federal and state income taxes 751,855 705,026
Unamortized investment tax credits 94,930 99,355
Accrued Yankee Atomic costs (Note D) 122,452 103,501
Other reserves and deferred credits 176,769 205,747
Commitments and contingencies (Note E) ---------- ----------
$5,084,841 $4,795,878
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
New England Electric System and Subsidiaries
Consolidated Statements of Cash Flows
Year ended December 31 (thousands of dollars)
1994 1993 1992
--------- --------- ---------
Operating activities
Net income $ 199,426 $ 190,223 $ 185,037
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization 305,908 300,444 305,046
Deferred income taxes and
investment tax credits-net 41,741 4,105 11,163
Allowance for funds used during
construction (17,962) (6,611) (4,936)
Amortization of unbilled revenues(38,458) (2,700)
Minority interests 7,439 8,022 9,264
Early retirement program 23,922
Decrease (increase) in accounts
receivable, net and unbilled
revenues (33,107) (27,503) (27,157)
Decrease (increase) in fuel,
materials, and supplies (20,117) 13,786 (8,590)
Decrease (increase) in prepaid and
other current assets (7,714) 5,904 (64,858)
Increase (decrease) in accounts
payable 40,595 (42,967) 34,623
Increase (decrease) in other current
liabilities (25,676) 64,658 (2,447)
Other, net (34,109) (32,632) (2,146)
--------- --------- --------
Net cash provided by operating
activities $ 417,966 $ 498,651 $ 434,999
Investing activities
Plant expenditures, excluding
allowance for funds used during
construction $(438,016) $(304,659) $(241,872)
Oil and gas exploration and
development (28,233) (18,965) (21,262)
Other investing activities (18,830) (107) 2,388
--------- --------- ---------
Net cash used in investing
activities $(485,079) $(323,731) $(260,746)
Financing activities
Dividends paid to minority interests$ (8,416)$ (10,622)$ (15,939)
Dividends paid on NEES common shares(148,063)(142,352)(140,174)
Short-term debt 162,195 29,525 42,250
Long-term debt-issues 97,000 372,500 477,500
Long-term debt-retirements (34,920) (395,820) (585,120)
Preferred stock-issues 55,000
Preferred stock-retirements (512) (70,000)
Premium on reacquisition of long-term
debt (10,996) (16,135)
Premium on redemption of preferred
stock (2,047)
--------- --------- ---------
Net cash provided by (used in)
financing activities $ 67,284 $(174,812) $(237,618)
Net increase (decrease) in cash and
cash equivalents $ 171 $ 108 $ (63,365)
Cash and cash equivalents at beginning
of year 2,876 2,768 66,133
--------- --------- ---------
Cash and cash equivalents at end of
year $ 3,047 $ 2,876 $ 2,768
Supplementary information
Interest paid less amounts capitalized$ 90,500$ 97,518$ 119,146
Federal and state income taxes paid$ 114,597$ 124,853$ 99,935
Dividends received from investments at
equity $ 15,350 $ 14,404 $ 18,405
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
New England Electric System and Subsidiaries
Consolidated Statements of Capitalization
At December 31 (thousands of dollars)
<TABLE>
<CAPTION>
1994 1993
---------- ----------
<S> <C> <C> <C> <C>
Common share equity
Common shares, par value $1 per share
Authorized-150,000,000 shares
Outstanding-64,969,652 shares $ 64,970 $ 64,970
Paid-in capital 736,823 736,823
Retained earnings 779,045 728,075
---------- ----------
Total common share equity $1,580,838 $1,529,868
</TABLE>
<TABLE>
<CAPTION>
Cumulative preferred stock of Shares outstanding
subsidiaries
1994 1993 1994 1993
--------- --------- -------- --------
<S> <C> <C> <C> <C>
$100 Par value-
4.44% to 4.76% 430,140 430,140 $ 43,014 $ 43,014
6.00% to 7.24% 525,020 530,140 52,502 53,014
$50 Par value-
4.50% to 6.95% 730,000 730,000 36,500 36,500
$25 Par value-
6.84% 600,000 600,000 15,000 15,000
--------- --------- -------- --------
Total cumulative preferred stock of
subsidiaries (annual dividend
requirement of $8,690 for 1994
and $8,720 for 1993) 2,285,160 2,290,280 $147,016 $147,528
</TABLE>
<TABLE>
<CAPTION>
Long-term debt (Note H) Maturity Rate 1994 1993
------------------------------------- --------
<S> <C> <C> <C> <C>
Mortgage bonds* 1995 through 19994.730%-8.280%$ 203,500$ 187,500
2000 through 20046.240%-8.520%187,500 152,500
2005 through 20146.110%-6.660%35,000 35,000
2015 through 20247.050%-9.125%422,550 376,550
2018 through 2022 Variable342,000 342,000
Notes
Granite State Electric Company1996 through 20237.370%-12.550%14,40015,800
New England Energy Incorporated 1998 Variable216,000238,000
Hydro-Transmission Companies2001 through 20158.820%-9.410%171,050 182,570
Unamortized discounts and premiums, net (5,592) (5,411)
-------------------
Total long-term debt 1,586,4081,524,509
Long-term debt due in one year (65,920) (12,920)
-------------------
$1,520,488$1,511,589
<FN>
*Includes $382,350 issued to secure tax-exempt pollution control and solid waste disposal
revenue bonds issued by state agencies on behalf of New England Power Company.
</FN>
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
New England Electric System and Subsidiaries
Notes to Consolidated Financial Statements
Note A - Significant accounting policies
1.Basis of consolidation and system of accounts
The consolidated financial statements include the accounts of New England
Electric System (NEES) and all subsidiaries except New England Electric
Transmission Corporation, which is recorded at equity. Presentation of this
subsidiary on the equity basis is not material to the consolidated financial
statements. New England Power Company (NEP) has a minority interest in four
regional nuclear generating companies (Yankees). Narragansett Energy
Resources Company (Resources) has a 20 percent general partnership interest in
the Ocean State Power (OSP) generating facility. NEP and Resources account
for these ownership interests on the equity method.
NEES owns 50.4 percent of the outstanding common stock of both New England
Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission
Corporation (Hydro-Transmission companies). The consolidated financial
statements include 100 percent of the assets, liabilities, and earnings of the
Hydro-Transmission companies. Since NEES is the majority stockholder in these
companies, the ownership interests of the other stockholders are called
minority interests and have been separately disclosed on the NEES consolidated
income statements and balance sheets. The "Minority interests" line on the
statements of consolidated income includes the minority interests' portion of
the net earnings of the Hydro-Transmission companies.
NEP is also a 12 percent and 10 percent joint owner, respectively, of the
Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 megawatts
(MW). NEP's net investment in Millstone 3, included in net utility plant, is
approximately $400 million. (See Note C for a discussion of Seabrook 1.)
NEP's share of the related expenses for these units is included in "Operating
expenses".
The accounts of NEES and its utility subsidiaries are maintained in
accordance with the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction. All significant intercompany transactions between
consolidated subsidiaries have been eliminated.
2.Electric sales revenue
Massachusetts Electric Company (Massachusetts Electric) and The
Narragansett Electric Company (Narragansett), pursuant to rate agreements that
went into effect in 1993 and 1994, respectively, began accruing revenues for
electricity delivered but not yet billed. Unbilled revenues at December 31,
1994 and 1993 were $56 million and $43 million, respectively, of which, $37
million and $11 million were recognized in income in 1994 and the fourth
quarter of 1993, respectively. The remainder of $8 million at December 31,
1994 has been deferred for recognition monthly through December 1995. Accrued
revenues are also recorded in accordance with rate adjustment mechanisms.
3.Allowance for funds used during construction (AFDC)
The utility subsidiaries capitalize AFDC as part of construction costs.
AFDC represents the composite interest and equity costs of capital funds used
to finance that portion of construction costs not eligible for inclusion in
rate base. In 1994, an average of $30 million of construction work in
progress was included in rate base, all of which was attributable to the
Manchester Street Station repowering project. AFDC is capitalized in "Utility
plant" with offsetting non-cash credits to "Other income" and "Interest".
This method is in accordance with an established rate-making practice under
which a utility is permitted a return on, and the recovery of, prudently
incurred capital costs through their ultimate inclusion in rate base and in
the provision for depreciation. The composite AFDC rates were 7.6 percent,
7.4 percent, and 8.6 percent, in 1994, 1993, and 1992, respectively.
<PAGE>
4.Depreciation and amortization
The depreciation and amortization expense included in the statements of
consolidated income is composed of the following:
Year ended December 31 (thousands of dollars) 1994 1993 1992
---------------- --------
Depreciation $136,746$127,428 $130,655
Nuclear decommissioning costs (Note A-5) 1,951 1,951 1,890
Amortization:
Oil and gas properties (Note A-6) 79,232 90,399 99,687
Investment in Seabrook 1 nuclear unit under
rate settlement (Note C) 65,061 58,437 52,443
Oil Conservation Adjustment 11,854 12,137 11,263
Property losses 6,279 6,279 6,279
---------------- --------
Total depreciation and amortization expense$301,123$296,631$302,217
Depreciation is provided annually on a straight-line basis. The provision
for depreciation as a percentage of weighted average depreciable property was
3.1 percent in 1994, 3.0 percent in 1993, and 3.2 percent in 1992.
The Oil Conservation Adjustment is designed to recover expenditures for
coal conversion facilities at NEP's Salem Harbor Station by 1995. At December
31, 1994, such unamortized coal conversion costs included in utility plant
were $4,467,000.
5.Nuclear plant decommissioning and nuclear fuel disposal
NEP is recovering its share of projected decommissioning costs for
Millstone 3 and Seabrook 1 through depreciation expense. NEP records
decommissioning cost expense on its books consistent with its rate recovery.
In addition, NEP is paying its portion of projected decommissioning costs for
all of the Yankees through purchased power expense. Such costs reflect
estimates of total decommissioning costs approved by the Federal Energy
Regulatory Commission (FERC).
Each of the operating nuclear units in which NEP has an ownership interest
has established decommissioning trust funds or escrow funds into which
payments are being made to meet the projected costs of decommissioning its
plant. If any of the units were shut down prior to the end of their operating
licenses, the funds collected for decommissioning to that point would be
insufficient. Listed below is information on each nuclear plant in which NEP
has an ownership interest. (See Note D for a discussion of Yankee Atomic
Nuclear Power Station decommissioning.)
NEP's share of (millions of dollars)
---------------------------------------------------
Estimated
Ownership Decommissioning Fund License
Unit Interest Cost (in 1994 $)Balances**Expiration
- ----------------------------------------------------------------
Connecticut Yankee 15% 53 22 2007
Maine Yankee*** 20% 66 22 2008
Vermont Yankee 20% 66 23 2012
Millstone 3* 12% 53 11 2025
Seabrook 1* 10% 36 4 2026
*Fund balances are included in "Other investments" on the balance sheet
and approximate market value.
**Certain additional amounts are anticipated to be available through tax
deductions.
***A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally
liable for the shortfall.
<PAGE>
In accordance with its recent rate agreement which became effective in
1995, NEP is allowed to defer for later recovery any increases in
decommissioning payments over the level included in rates until its next rate
filing becomes effective.
There is no assurance that decommissioning costs actually incurred by the
Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these
amounts. For example, decommissioning cost estimates assume the availability
of permanent repositories for both low-level and high-level nuclear waste
which do not currently exist.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government is responsible for the disposal of spent nuclear fuel. The federal
government requires NEP to pay a fee based on its share of the net generation
from the Millstone 3 and Seabrook 1 nuclear units. NEP is recovering this fee
through its fuel clause. Similar costs are incurred by Connecticut Yankee,
Maine Yankee, and Vermont Yankee. These costs are billed to NEP and recovered
from customers through NEP's fuel clause.
6.Oil and gas operations
New England Energy Incorporated (NEEI) participates in a rate-regulated
domestic oil and gas exploration, development, and production program through
a partnership with a non-affiliated oil company. This program consists of
prospects acquired prior to December 31, 1983. No new prospects will be
acquired under this program.
However, NEEI continues to incur costs in connection with existing
prospects. Savings and losses from this program are being passed on to NEP
and ultimately to retail customers, under an intercompany pricing policy
(Pricing Policy) approved by the Securities and Exchange Commission (SEC).
NEEI has incurred operating losses since 1986 due to precipitate declines in
oil and gas prices, and expects to incur substantial additional losses in the
future. Such losses were $40 million, $46 million, and $55 million in 1994,
1993, and 1992, respectively. NEP's ability to pass these losses on to its
customers was favorably resolved in NEP's 1988 FERC rate settlement. This
settlement covered all costs incurred by or resulting from commitments made by
NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are
subject to normal regulatory review. NEEI follows the full cost method of
accounting for its oil and gas operations, under which capitalized costs
(including interest paid to banks) relating to wells and leases determined to
be either commercial or non-commercial are amortized using the unit of
production method. The Pricing Policy has allowed NEEI to capitalize all
costs incurred in connection with fuel exploration activities of its
rate-regulated program, including interest paid to banks of which $10 million,
$9 million, and $14 million was capitalized in 1994, 1993, and 1992,
respectively. In the absence of the Pricing Policy, the SEC's full cost
"ceiling test" rule requires non-rate-regulated companies to write down
capitalized costs to a level which approximates the present value of their
proved oil and gas reserves. Based on NEEI's 1994 average oil and gas selling
prices and NEEI's proved reserves at December 31, 1994, application of the
ceiling test would have resulted in a write-down of approximately $120 million
after tax.
7.Cash
NEES and its subsidiaries classify short-term investments with a maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
Outstanding checks are therefore recorded in accounts payable until such time
as the banks present them for payment.
<PAGE>
8.Deferred charges and other assets
The components of deferred charges and other assets are as follows:
At December 31 (thousands of dollars) 1994 1993
---------- ----------
Regulatory assets:
Unamortized losses on reacquired debt $ 56,249 $ 60,333
Deferred SFAS No. 106 costs (see Note F-2)41,009 24,563
Deferred SFAS No. 109 costs (see Note B)74,423 73,760
Purchased power termination costs 29,012 28,400
Deferred gas pipeline charges (see Note E-2)37,562 13,187
Environmental response costs (see Note E-3)13,167 18,752
Deferred storm costs 10,822 14,774
Unamortized property losses 7,373 12,745
Other 5,111 11,892
-------- --------
274,728 258,406
Other deferred charges and other assets:
Intangible asset-pensions (see Note F-1) 4,749 15,103
Other 16,755 16,626
-------- --------
$296,232 $290,135
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These accounting
rules require regulated entities, in appropriate circumstances, to establish
regulatory assets and liabilities, which defer the income statement impact of
certain costs that are expected to be recovered in future rates. The effects
of competition could ultimately cause the operations of the NEES companies, or
a portion thereof, to cease meeting the criteria for application of these
accounting rules. In such an event, accounting standards applicable to
enterprises in general would apply and immediate write-off of any previously
deferred costs (regulatory assets) would be necessary in the year in which
these criteria were no longer applicable. Approximately $150 million of the
regulatory assets at December 31, 1994 listed above are expected to be
recovered within 10 years, with the majority of the remaining balance to be
recovered within the following 20 years. The only items for which the
majority of the balance shown above will not be recovered within the next 10
years are the deferred SFAS No. 109 costs and the deferred gas pipeline
charges.
9.Other current liabilities
The components of other current liabilities are as follows:
At December 31 (thousands of dollars) 1994 1993
---------- ----------
Accrued wages and benefits $26,035 $ 39,756
Deferred unbilled revenues 8,209 32,300
Rate adjustment mechanisms 31,311 31,237
Accrued purchased power termination costs 21,900
Customer deposits 10,951 12,336
Other 16,745 16,283
------- --------
$93,251 $153,812
<PAGE>
Note B - Income taxes
Total income taxes in the statements of consolidated income are as follows:
Year ended December 31 (thousands of dollars) 1994 1993 1992
---------------- --------
Income taxes charged to operations $128,257$121,124 $110,761
Income taxes charged to "Other income" 779 3,147 3,192
---------------- --------
Total income taxes $129,036$124,271 $113,953
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Current income taxes $ 87,295$120,167 $102,790
Deferred income taxes 46,166 7,756 13,475
Investment tax credits-net (4,425) (3,652) (2,312)
---------------- --------
Total income taxes $129,036$124,271 $113,953
Total income taxes, as shown above, consist of federal and state components as
follows:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Federal income taxes $104,136$ 98,529 $ 92,647
State income taxes 24,900 25,742 21,306
---------------- --------
Total income taxes $129,036$124,271 $113,953
Investment tax credits of subsidiaries are deferred and amortized over the
estimated lives of the property giving rise to the credits. Since the Tax
Reform Act of 1986 generally eliminated investment tax credits, the amounts
shown above principally reflect the amortization of investment tax credits
generated in prior years.
With regulatory approval, the subsidiaries have adopted comprehensive
interperiod tax allocation (normalization) for temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal
statutory tax rates to income before taxes. The reasons for the differences
are as follows:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Computed tax at statutory rate $118,006$113,778 $105,251
Increases (reductions) in tax resulting from:
Reversal of deferred taxes recorded at a
higher rate (4,230) (5,099) (7,175)
Amortization of investment tax credits (5,272) (4,697) (5,384)
State income tax, net of federal income
tax benefit 16,185 16,732 14,062
All other differences 4,347 3,557 7,199
---------------- --------
Total income taxes $129,036$124,271 $113,953
<PAGE>
The Financial Accounting Standards Board established Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which
became effective in 1993. The application of this new standard did not have a
significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
At December 31 (millions of dollars) 1994 1993
---------- ----------
Deferred tax asset:
Plant related $ 107 $ 99
Investment tax credits 38 40
All other 108 129
------ ------
253 268
Deferred tax liability:
Plant related (777) (758)
Equity AFDC (52) (57)
All other (176) (158)
------ ------
(1,005) (973)
------ ------
Net deferred tax liability $ (752) $ (705)
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appear on the
income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily include deferred income taxes of $29 million related to utility
plant and $17 million in connection with postretirement benefits, partially
offset by deferred tax credits of $31 million associated with oil and gas
operations.
Federal income tax returns for NEES and its subsidiaries have been examined
and reported on by the Internal Revenue Service through 1991.
Note C - Seabrook Nuclear Unit 1 (Seabrook 1)
NEP owns approximately 10 percent of Seabrook 1, a 1,150 MW nuclear
generating unit that entered commercial service in 1990. NEP's rate recovery
of its investment in Seabrook 1 was resolved through two separate rate
settlement agreements. NEP's pre-1988 investment was being recovered in rates
over a period of seven and one-half years ending in mid-1995. Under NEP's rate
agreement, that was recently approved by the FERC, approximately $15 million
of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to
a 1988 settlement agreement will be deferred and recovered in 1996. This
investment, net of amortization, is shown on a separate line on the
consolidated balance sheets. NEP's net investment in Seabrook 1 since
January 1, 1988, which amounts to approximately $43 million at December 31,
1994, is included under the caption "Utility plant" on the consolidated
balance sheet and is being recovered over 37 years.
<PAGE>
Note D - Yankee Atomic Nuclear Power Station
NEP has a 30 percent ownership interest in Yankee Atomic Electric Company
(Yankee Atomic), which owns a 185 MW nuclear generating station in Rowe,
Massachusetts. The station began commercial service in 1960. At December 31,
1994, NEP's investment in Yankee Atomic was approximately $7 million. In
February 1992, the Yankee Atomic board of directors decided to permanently
cease power operation of, and in time decommission, the facility.
In March 1993, the FERC approved a settlement agreement that allows Yankee
Atomic to recover all but $3 million of its approximately $50 million
remaining investment in the plant over the period extending to July 2000, when
the plant's Nuclear Regulatory Commission (NRC) operating license would have
expired. Yankee Atomic recorded the $3 million before-tax write-down in 1992.
The settlement agreement also allows Yankee Atomic to earn a return on the
unrecovered balance during the recovery period and to recover other costs,
including an increased level of decommissioning costs, over this same period.
Decommissioning cost recovery increased from $6 million per year to $27
million per year for the period 1993 to 1995. In the fourth quarter of 1994,
Yankee announced a new decommissioning cost estimate that, subject to approval
by the FERC, would increase billings to NEP by an additional $11 million per
year through July 2000.
NEP has recorded an estimate of its entire future payment obligations to
Yankee Atomic as a liability on its balance sheet and an offsetting regulatory
asset reflecting its expected future rate recovery of such costs. This
liability and related regulatory asset amounted to approximately $122 million
each at December 31, 1994, and are included on separate lines in the
consolidated balance sheet.
Note E - Commitments and contingencies
1. Plant expenditures
The NEES subsidiaries' utility plant expenditures are estimated to be $325
million in 1995. At December 31, 1994, substantial commitments had been made
relative to future planned expenditures.
2. Natural gas pipeline capacity
In connection with NEP's efforts to reduce sulfur dioxide emissions and
repower generating units, NEP has signed several contracts for natural gas
pipeline capacity and gas supply. These agreements require minimum fixed
payments. NEP's minimum net payments are currently estimated to be
approximately $65 million in 1995 and $70 million per year during 1996 to
1999.
As part of a rate settlement, NEP is recovering 50 percent of the fixed
pipeline capacity payments through its current fuel clause and deferring the
recovery of the remaining 50 percent until the Manchester Street repowering
project is completed. NEP has deferred payments of approximately $38 million
as of December 31, 1994 (see Note A-8). NEP has been using a portion of this
capacity to sell natural gas, the proceeds from which have been passed to
customers through NEP's fuel clause.
3. Hazardous waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. NEES
subsidiaries currently have in place an environmental audit program intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
<PAGE>
NEES and/or its subsidiaries have been named as a potentially responsible
party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the
Massachusetts Department of Environmental Protection for 22 sites at which
hazardous waste is alleged to have been disposed. Private parties have also
contacted or initiated legal proceedings against NEES and certain subsidiaries
regarding hazardous waste cleanup. The most prevalent types of hazardous
waste sites with which NEES and its subsidiaries have been associated are
manufactured gas locations. (Until the early 1970s, NEES was a combined
electric and gas holding company system.) NEES is aware of approximately 40
such locations (including seven of the 22 locations for which NEES companies
are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are
currently aware of other sites, and may in the future become aware of
additional sites, that they may be held responsible for remediating.
NEES has been notified by the EPA that it is one of several PRPs for
cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, at
which coal tar and other materials were deposited. Between 1931 and 1951,
NEES and its predecessor owned all of the common stock of Green Mountain Power
Corporation (GMP). Prior to, during, and after that time, gas was
manufactured at the Pine Street Canal site by GMP. In 1989, NEES was one of
14 parties required to pay the EPA's past response costs related to this site.
NEES remains a PRP for ongoing and future response costs. In November 1992,
the EPA proposed a cleanup plan estimated by the EPA to cost $50 million. In
June 1993, the EPA withdrew this cleanup plan in response to public concern
about the plan and its cost. It is uncertain at this time what the cost of
any ultimate cleanup plan will be or what NEES's share of such costs will be.
In 1993, the Massachusetts Department of Public Utilities approved a rate
agreement filed by Massachusetts Electric that allows for remediation costs of
former manufactured gas sites and certain other hazardous waste sites located
in Massachusetts to be met from a non-rate recoverable interest-bearing fund
of $30 million established on Massachusetts Electric's books. Rate
recoverable contributions of $3 million, adjusted for inflation, are added to
the fund annually in accordance with the agreement. Any shortfalls in the
fund would be paid by Massachusetts Electric and be recovered through rates
over seven years. The resolution of the issue of rate recovery resulted in a
one-time increase to fourth quarter 1993 earnings of $11 million due to the
reversal of a portion of previously established hazardous waste reserves.
Predicting the potential costs to investigate and remediate hazardous waste
sites continues to be difficult. There are also significant uncertainties as
to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by NEES or its
subsidiaries. Where appropriate, the NEES companies intend to seek recovery
from their insurers and from other PRPs, but it is uncertain whether and to
what extent such efforts would be successful. At December 31, 1994, NEES had
total reserves for environmental response costs of $45 million and a related
regulatory asset of $13 million. NEES believes that hazardous waste
liabilities for all sites of which it is aware, and which are not covered by a
rate agreement, will not be material to its financial position.
<PAGE>
4. Nuclear insurance
The Price-Anderson Act limits the amount of liability claims that would
have to be paid in the event of a single incident at a nuclear plant to $8.9
billion (based upon 110 licensed reactors). The maximum amount of
commercially available insurance coverage to pay such claims is only $200
million. The remaining $8.7 billion would be provided by an assessment of up
to $79.3 million per incident levied on each of the nuclear units in the
United States, subject to a maximum assessment of $10 million per incident per
nuclear unit in any year. The maximum assessment, which was most recently
calculated in 1993, is to be adjusted at least every five years to reflect
inflationary changes. NEP's current interest in the Yankees (excluding Yankee
Atomic), Millstone 3, and Seabrook 1 would subject NEP to a $58.0 million
maximum assessment per incident. NEP's payment of any such assessment would
be limited to a maximum of $7.3 million per incident per year. As a result of
the permanent cessation of power operation of the Yankee Atomic plant, Yankee
Atomic has received from the NRC a partial exemption from obligations under
the Price-Anderson Act. However, Yankee Atomic must continue to maintain $100
million of commercially available nuclear insurance coverage.
Each of the nuclear units in which NEP has an ownership interest also
carries nuclear insurance to cover the costs of property damage,
decontamination or premature decommissioning and workers' claims resulting
from a nuclear incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units covered by this
insurance occurring in a prior six year period exceed the accumulated funds
available. NEP's maximum potential exposure for these assessments, either
directly, or indirectly through purchased power payments to the Yankees, is
approximately $17 million per year.
5. Long-term contracts for the purchase of electricity
NEP purchases a portion of its electricity requirements pursuant to
long-term contracts with owners of various generating units. These contracts
expire in various years from 1995 to 2029.
Certain of these contracts require NEP to make minimum fixed payments, even
when the supplier is unable to deliver power, to cover NEP's proportionate
share of the capital and fixed operating costs of these generating units. The
majority of the payments under these contracts are to the Yankees (excluding
Yankee Atomic-see Note D) and OSP, entities in which NEES subsidiaries hold
ownership interests. The fixed portion of payments under these contracts
totaled $190 million in 1994 and $220 million in 1993 and 1992. These
contracts have minimum fixed payment requirements of $215 million in 1995,
$195 million in 1996, $190 million in 1997 and 1998, $185 million in 1999, and
approximately $2 billion thereafter.
NEP's other contracts, principally with non-utility generators, require NEP
to make payments only if power supply capacity and energy are deliverable from
such suppliers. NEP's payments under these contracts amounted to $210 million
in 1994 and 1993 and $200 million in 1992.
<PAGE>
6. Purchased power contract dispute
In October 1994, NEP was sued by Milford Power Limited Partnership (MPLP),
a venture of Enron Corporation and Jones Capital that owns a 149 MW gas-fired
power plant in Milford, Massachusetts. NEP purchases 56 percent of the power
output of the facility under a long-term contract with MPLP. The suit alleges
that NEP has engaged in a scheme to cause MPLP and its power plant to fail and
has prevented MPLP from finding a long-term buyer for the remainder of the
facility's output. The complaint includes allegations that NEP has violated
the Federal Racketeer Influenced and Corrupt Organizations Act, engaged in
unfair or deceptive acts in trade or commerce, and breached contracts. MPLP
seeks compensatory damages in an unspecified amount, as well as treble
damages. NEP believes that the allegations of wrongdoing are without merit.
NEP has filed counterclaims and crossclaims against MPLP, Enron Corporation,
and Jones Capital, seeking monetary damages and termination of the purchased
power contract.
MPLP also intervened in a recent NEP rate filing.
Note F - Employee benefits
1.Pension plans
The NEES companies' retirement plans are noncontributory defined-benefit
plans covering substantially all employees. The plans provide pension
benefits based on the employee's compensation during the five years before
retirement. The NEES companies' funding policy is to contribute each year,
the net periodic pension cost for that year. However, the contribution for
any year will not be less than the minimum required contribution under federal
law or greater than the maximum tax deductible amount.
Net pension cost for 1994, 1993, and 1992 included the following
components:
Year ended December 31 (thousands of dollars) 1994 1993 1992
-------- ----------------
Service cost-benefits earned during the period$13,715$11,160$10,984
Plus (less):
Interest cost on projected benefit obligation49,06749,34646,171
Return on plan assets at expected long-term
rate (47,281)(45,032) (43,877)
Amortization 5,781 1,364 1,239
------- ------- -------
Net pension cost $21,282 $16,838 $14,517
Assumptions used to determine pension cost were:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future compensation
levels 4.35% 5.35% 6.70%
Expected long-term rate of return on assets8.75%8.75% 9.00%
------- ------- -------
Actual return on plan assets $ 4,384 $69,208 $38,489
Service cost for 1993 does not reflect costs incurred in connection with an
early retirement program offered by the NEES subsidiaries in that year (see
Note F-3).
<PAGE>
<TABLE>
<CAPTION>
The following table sets forth the plans' funded status at December 31 (millions of dollars):
------------------------------------------------------------
Retirement Plans
------------------------------------------------------------
1994 1993
----------------------------------------------------------
Union Non-Union Supple- Union Non-unionSupple-
Employee Employee mental EmployeeEmployee mental
Plans Plans Plans Plans Plans Plans
-------- -------- ------- ---------------- -------
<S> <C> <C> <C> <C> <C> <C>
Benefits earned
Actuarial present value
of accumulated benefit
liability:
Vested $251 $308 $38 $251 $333 $40
Non-vested 8 9 - 20 6 -
---- ---- ---- ---- ---- ----
Total $259 $317 $38 $271 $339 $40
Reconciliation of funded status
Actuarial present value of
projected benefit liability$303 $355 $44 $310 $383 $44
Unrecognized prior service costs(8) (4) (5) (8) (6) (4)
SFAS No. 87 transition liability
not yet recognized (amortized)- (1) (5) - (1) (5)
Net gain (loss) not yet
recognized (amortized) (13) (33) 2 (11) (45) (2)
Additional minimum liability
recognized - - 5 - 8 7
----- ----- ----- ----- ----- -----
282 317 41 291 339 40
Pension fund assets at fair value293 323 - 302 318 -
SFAS No. 87 transition asset
not yet recognized (amortized)(13) - - (14) - -
----- ----- ----- ----- ----- -----
280 323 - 288 318 -
----- ----- ----- ----- ----- -----
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $41 $ 3 $ 21 $40
</TABLE>
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed
effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively.
The expected long-term rate of return on assets used to calculate pension
cost was not changed from the level shown in the table above. The plans'
funded status at December 31, 1994 was calculated using these revised
rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2.Postretirement benefit plans other than pensions
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement
Benefits Other than Pensions" (PBOPs) went into effect. The NEES
subsidiaries provide health care and life insurance coverage to eligible
retired employees. Eligibility is based on certain age and length of
service requirements and in some cases retirees must contribute to the
cost of their coverage.
<PAGE>
The total cost of PBOPs for 1994 and 1993 includes the following
components:
Year ended December 31 (thousands of dollars) 1994 1993
---------- ----------
Service cost-benefits earned during the period$ 8,575 $ 8,160
Plus (less):
Interest cost on the accumulated benefit
obligation 27,813 30,457
Return on plan assets at expected long-term
rate (7,821) (5,089)
Amortization 18,273 18,418
------- -------
Net postretirement benefit cost $46,840 $51,946
------- -------
Actual return on plan assets $ 185 $ 5,249
The following table sets forth benefits earned and the plans' funded
status:
At December 31 (millions of dollars) 1994 1993
---------- ----------
Accumulated postretirement benefit obligation:
Retirees $226 $249
Fully eligible active plan participants 42 23
Other active plan participants 95 130
----- -----
Total benefits earned 363 402
Unrecognized transition obligation (331) (350)
Net gain (loss) not yet recognized 43 (7)
----- -----
75 45
Plan assets at fair value 109 86
Prepaid postretirement benefit costs
recorded on books $ 34 $ 41
1995 1994 1993
------ ------ ------
Assumptions to determine postretirement
benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return on assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
The plans' funded status at December 31, 1994 and 1993 presented above was
calculated using the assumed rates in effect for 1995 and 1994, respectively.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed rates by 1 percent in each year
would increase the accumulated postretirement benefit obligation as of
December 31, 1994 by approximately $54 million and the net periodic cost for
the year 1994 by approximately $7 million.
The NEES subsidiaries fund the annual tax deductible contributions. Plan
assets are invested in equity and debt securities and cash equivalents.
Prior to 1993, NEES subsidiaries recorded the cost of PBOPs when paid.
These costs amounted to approximately $13 million in 1992. Each of the NEES
subsidiaries has been permitted to recover amounts on either a current and/or
deferred basis, which are expected to at least equal the amounts calculated in
accordance with this new accounting standard. Adoption of this new accounting
standard did not have a significant impact on net income.
<PAGE>
3.1993 Early retirement and special severance programs
In February 1993, NEES subsidiary companies offered a voluntary early
retirement program to non-union employees who were at least 55 years old with
10 years of service. This program was part of an organizational review with
the goal of streamlining operations and reducing the work force. The early
retirement offer was accepted by 344 employees. A special severance program
was also announced in February 1993 for employees affected by the
organizational review, but who were not eligible for, or did not accept, the
early retirement offer. NEES subsidiaries recorded in the first quarter a
one-time charge to 1993 earnings of approximately $18 million, after tax ($28
million, before tax), to reflect the cost of the early retirement and special
severance programs which consisted principally of pension benefits.
Note G - Short-term borrowings
At December 31, 1994, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $663 million.
These lines and facilities were used at December 31, 1994 for $2 million of
direct borrowings, and for liquidity support for $232 million of commercial
paper borrowings and $342 million of NEP mortgage bonds in tax-exempt
commercial paper mode (see Note H). Fees are paid on the lines and facilities
in lieu of compensating balances. The weighted average rate on outstanding
short-term borrowings was 6.1 percent at December 31, 1994. The fair value of
the NEES subsidiaries' short-term debt equals carrying value.
Note H - Long-term debt
Substantially all the properties of NEP, Massachusetts Electric, and
Narragansett are subject to the lien of mortgage indentures under which
mortgage bonds have been issued.
The aggregate payments to retire maturing long-term debt are as follows:
(thousands of dollars) 1995 1996 1997 1998 1999
------- --------------- -------- -------
Maturing long-term debt $35,000$10,000 $ 65,500$ 60,000 $33,000
Mandatory prepayments:
Hydro-Transmission Companies11,52011,520 11,520 11,520 11,520
Granite State Electric Company3,4001,000
NEEI 16,000 75,000 75,000 50,000
-------------- ---------------- -------
Total $65,920$97,520 $152,020$121,520 $44,520
The terms of $342 million of variable rate pollution control revenue bonds
collateralized by NEP mortgage bonds require NEP to reacquire the bonds under
certain limited circumstances. At December 31, 1994, interest rates on NEP's
variable rate bonds ranged from 3.30 percent to 5.60 percent. Also, at
December 31, 1994, interest rates on NEEI's debt ranged from 5.94 percent to
7.00 percent. NEP and the retail subsidiaries have issued $56 million of
long-term debt to date in 1995 at interest rates ranging from 7.79 percent to
8.45 percent.
At December 31, 1994, the NEES subsidiaries' long-term debt had a carrying
value of approximately $1,586,000,000 and had a fair value of approximately
$1,555,000,000. To estimate fair value, the carrying amount was used for debt
that reprices frequently at market rates because the carrying amount is a
reasonable estimate of fair value. For all other debt, the fair market value
of the NEES subsidiaries' long-term debt was estimated based on the quoted
prices for similar issues or on the current rates offered to the NEES
companies for debt of the same remaining maturity.
<PAGE>
Report of Management
The management of New England Electric System is responsible for the
integrity of the consolidated financial statements included in this annual
report. The financial statements were prepared in accordance with generally
accepted accounting principles using management's informed best estimates and
judgments where appropriate to fairly present the financial condition of the
NEES companies and their results of operations. The information included
elsewhere in this report is consistent with the financial statements.
The NEES companies maintain an accounting system and system of internal
controls which are designed to provide reasonable assurance as to the
reliability of the financial records, the protection of assets, and the
prevention of any material misstatement of the financial statements. The NEES
companies' accounting controls have been designed to provide reasonable
assurance that errors or irregularities, which could be material to the
financial statements, are prevented or detected by employees within a timely
period as they perform their assigned functions. The NEES companies' internal
auditing staff independently assesses the effectiveness of internal controls
and recommends improvements when appropriate.
Coopers & Lybrand L.L.P., the NEES companies' independent accountants, are
engaged to audit and express their opinion on the financial statements. Their
audit includes a review of internal controls to the extent required by
generally accepted auditing standards.
The Audit Committee, composed solely of outside directors, meets
periodically with management, the internal auditor, and the independent
accountants to ensure that each is carrying out its responsibilities and to
discuss auditing, internal accounting control, and financial reporting
matters. Both the internal auditor and the independent accountants have free
access to the Audit Committee, without management present, to discuss the
results of their audit work.
/s/ John W. Rowe /s/ Alfred D. Houston
John W. Rowe Alfred D. Houston
President and Executive Vice President
Chief Executive Officer and Chief Financial Officer
Report of Independent Accountants
To the Board of Directors and Shareholders of New England Electric System:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of New England Electric System and
subsidiaries (the Company) as of December 31, 1994 and 1993 and the related
consolidated statements of income, retained earnings and cash flows for each
of the three years in the period ended December 31, 1994. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of the Company
as of December 31, 1994 and 1993, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting
principles.
Boston, Massachusetts /s/ COOPERS & LYBRAND L.L.P.
February 27, 1995
<PAGE>
<TABLE>
<CAPTION>
Shareholder Information
New England Electric System
common shares
1994 1993
---------------------------------------------------
Price range Price range
----------------Dividend---------------Dividend
High Low declared High Low declared
-------------- --------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
First quarter $39 $35-1/8 $.56 $42-1/4 $36-7/8 $.54
Second quarter $37-5/8$31-1/2 $.57-1/2$42-7/8 $39-3/8 $.56
Third quarter $34 $28-7/8 $.57-1/2$43-3/8 $40-3/4 $.56
Fourth quarter $32 7/8$29 1/2 $.57 1/2$42 $37 $.56
</TABLE>
The total number of shareholders at December 31, 1994 was 54,593.
Selected quarterly financial information (unaudited)
<TABLE>
<CAPTION>
(thousands of dollars) 1st quarter 2nd quarter 3rd quarter4th quarter*
----------- ---------- ----------------------
<S> <C> <C> <C> <C>
1994
Operating revenue $576,906 $517,078 $591,633 $557,412
Operating income $ 91,862 $ 57,716 $ 84,354 $ 62,564
Net income $ 69,273 $ 33,584 $ 58,851 $ 37,718
Net income per average share$ 1.07$ .51 $ .91 $ .58
1993
Operating revenue $579,490 $518,136 $576,644 $559,708
Operating income $ 80,711 $ 46,046 $ 82,498 $ 93,688
Net income $ 53,586 $19,146 $ 55,531 $ 61,960
Net income per average share$ .82$ .30 $ .85 $ .96
<FN>
*See Notes A-2 and E-3 for discussion of items that increased 1993 fourth quarter
earnings.
</FN>
</TABLE>
Shareholder services
Shareholders may direct questions or acquire additional information about
shareholder records, quarterly dividend payments, or address changes by
contacting a shareholder services representative. The following services are
available to shareholders who have shares registered in their own name: direct
deposit of dividends, automatic investments, dividend reinvestment, and
safekeeping of certificated shares.
New England Electric System
Shareholder Services Department
Post Office Box 770
Westborough, Massachusetts 01581-0770
Toll-Free Number: 1-800-466-7215
Local Number: 508-389-2699
Dividends on common shares
Dividends are generally payable on the first business day of January, April,
July, and October.
<PAGE>
Transfer agent
Questions about the transfer of certificate shares should be directed to:
Bank of Boston, Transfer Processing
Post Office Box 644, Mail Stop 45-01-05
Boston, Massachusetts 02102-0644
617-575-3120
Stock exchange listings
New York Stock Exchange
Boston Stock Exchange
Trading symbol
NES
Annual meeting notice
The annual meeting of New England Electric System will be held at Lowell
Memorial Auditorium, Lowell, Massachusetts, on April 25, 1995, at 10:30 a.m.
Form 10K and Statistical Report
Copies of the annual report on Form 10K to the Securities and Exchange
Commission and a Statistical Report for 1994 can be obtained, free of charge,
by writing to:
New England Electric System
Investor Relations
25 Research Drive
Westborough, Massachusetts 01582
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby
referred to, and a copy of which, as amended, has been filed with the
Secretary of The Commonwealth of Massachusetts. Any agreement, obligation, or
liability made, entered into, or incurred by or on behalf of New England
Electric System binds only its trust estate, and no shareholder, director,
trustee, officer, or agent thereof assumes or shall be held to any liability
therefor.
This report is not to be considered as an offer to sell or buy or solicitation
of an offer to sell or buy any security.
<PAGE>
System Directors
As of December 31, 1994
Joan T. Bok
Chairman of the Board
New England Electric System
Westborough, Massachusetts
Corporate Responsibility Committee
Executive Committee
Paul L. Joskow
Professor of Economics and Management
Massachusetts Institute of Technology
Cambridge, Massachusetts
Audit Committee
John M. Kucharski
Chairman, President, and Chief Executive Officer
EG&G, Inc.
Wellesley, Massachusetts
Compensation Committee
Edward H. Ladd
Chairman
Standish, Ayer & Wood, Inc., Investment counselors
Boston, Massachusetts
Executive Committee
Joshua A. McClure
Former President
American Custom Kitchens, Inc.
Providence, Rhode Island
Corporate Responsibility Committee
Malcolm McLane
Of Counsel
Orr & Reno, P.A., Attorneys
Concord, New Hampshire
Audit Committee
Felix A. Mirando, Jr.
Private investor
Osterville, Massachusetts
Compensation Committee
John W. Rowe
President and Chief Executive Officer
New England Electric System
Westborough, Massachusetts
Corporate Responsibility Committee
Executive Committee
<PAGE>
George M. Sage
President and Treasurer
Bonanza Bus Lines, Inc.
Providence, Rhode Island
Compensation Committee
Executive Committee
Charles E. Soule
President and Chief Executive Officer
Paul Revere Insurance Group
Worcester, Massachusetts
Audit Committee
Anne Wexler
Chairman
The Wexler Group, Management consultants
Washington, D. C.
Corporate Responsibility Committee
Executive Committee
James Q. Wilson
Professor of Management
University of California at Los Angeles
Corporate Responsibility Committee
James R. Winoker
Chief Executive Officer
Belvoir Properties, Inc.,
Providence, Rhode Island
Audit Committee
Compensation Committee
System Officers
As of December 31, 1994
John W. Rowe
President and Chief Executive Officer
Alfred D. Houston
Executive Vice President and Chief Financial Officer
Frederic E. Greenman
Senior Vice President, General Counsel, and Secretary
John W. Newsham
Vice President
Richard P. Sergel
Vice President
Jeffrey D. Tranen
Vice President
Michael E. Jesanis
Treasurer
<PAGE>
System Subsidiaries
Massachusetts Electric Company
25 Research Drive, Westborough, Massachusetts 01582
John H. Dickson, President
The Narragansett Electric Company
280 Melrose Street, Providence, Rhode Island 02901
Robert L. McCabe, President
Granite State Electric Company
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
Lydia M. Pastuszek, President
New England Power Company
25 Research Drive, Westborough, Massachusetts 01582
Narragansett Energy Resources Company
280 Melrose Street, Providence, Rhode Island 02901
New England Electric Resources, Inc.
25 Research Drive, Westborough, Massachusetts 01582
John L. Levett, President
New England Electric Transmission Corporation
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
New England Energy Incorporated
25 Research Drive, Westborough, Massachusetts 01582
New England Hydro-Transmission Corporation
407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766
New England Hydro-Transmission Electric Company, Inc.
25 Research Drive, Westborough, Massachusetts 01582
New England Power Service Company
25 Research Drive, Westborough, Massachusetts 01582
[LOGO OF RECYCLED PAPER APPEARS HERE]
<PAGE>
New England Electric System
25 Research Drive
Westborough, Massachusetts 01582
Telephone 508-366-9011
<PAGE>
Appendix of Graphic and Image Material Appearing in New England
Electric System 1994 Annual Report
1. The cover contains images of a canoe, a pen, a mortarboard,
and a lighthouse.
2. Foldout inside cover contains a map of New England and
indicates service areas and generating facilities.
3. The financial highlights page contains a graph comparing
1994 Return on Equity percentages for New England Electric
System 12.7%, the median of U.S. Electric Utilities 11.4%,
and the median of New England/New York Electric Utilities
11.04%.
4. Pictures of Joan T. Bok, Chairman of the Board, and John W.
Rowe, President and Chief Executive Officer, appear on the
pages of the letter to shareholders.
5. A picture of a mortarboard and a picture of Douglas Smith,
senior technical representative, appear in the Customer
Focus section.
6. A picture of a lighthouse and a picture of Paul Stasiuk,
senior analyst, appear in the Competitive Marketplace
section.
7. A picture of a canoe and a picture of Paula Hamel, senior
environmental engineer, appear in the Environment section.
8. A picture of a fountain pen and a picture of Masheed Hegi,
consulting engineer, appear in the New Rules section.
9. The following graphs appear in the Financial Review Section:
a. Earnings per average share: $2.77 in 1991, $2.85 in
1992, $2.93 in 1993, and $3.07 in 1994.
b. The annual rate of dividends declared per share: $2.08
in 1991, $2.16 in 1992, $2.24 in 1993, and $2.30 in
1994.
c. Percentage growth in kilowatt hour sales to ultimate
customers: negative 1.2% in 1991, 0.4% in 1992, 1.4%
in 1993, and 1.6% in 1994.
d. Customers served per employee: 227 in 1991, 236 in
1992, 259 in 1993, and 261 in 1994.
e. 1994 New England Electric System energy mix: 31% coal,
10% oil, 19% nuclear, 12% hydro, 6% renewables, and 16%
gas.
<PAGE>
f. 1994 Distribution of Revenue: 24% Fuel, 9% Purchased
Power (excluding fuel), 11% Wages and Benefits, 18%
other O&M, 13% Depreciation and Amortization, 11%
Taxes, 5% Interest and Preferred Dividends, 9% Earnings
- Common Shares.
g. 1994 Revenue by Sales Classification: 43% residential,
32% small and medium commercial and industrial, 20%
large commercial and industrial with SED contracts, and
5% large commercial and industrial without SED
contracts.
h. Diverse Regulation - percent of 1994 electric revenue:
73% Federal Energy Regulatory Commission, 19%
Massachusetts, 7% Rhode Island, and 1% New Hampshire.
<PAGE>
POWER OF ATTORNEY
Each of the undersigned directors of New England Electric
System (the "Company"), individually as a director of the
Company, hereby constitutes and appoints John G. Cochrane, Thomas
F. Killeen, and Geraldine M. Zipser, individually, as attorney-
in-fact to execute on behalf of the undersigned the Company's
annual report on Form 10-K for the year ended December 31, 1994,
to be filed with the Securities and Exchange Commission, and to
execute any appropriate amendment or amendments thereto as may be
required by law.
Dated this 28th day of February, 1995.
s/ Joan T. Bok s/ John W. Rowe
__________________________ _________________________
Joan T. Bok John W. Rowe
s/ Paul L. Joskow s/ George M. Sage
__________________________ _________________________
Paul L. Joskow George M. Sage
s/ Charles E. Soule
__________________________ _________________________
John M. Kucharski Charles E. Soule
s/ Edward H. Ladd s/ Anne Wexler
__________________________ _________________________
Edward H. Ladd Anne Wexler
s/Joshua A. McClure
__________________________ _________________________
Joshua A. McClure James Q. Wilson
s/ Malcolm McLane s/ James R. Winoker
__________________________ _________________________
Malcolm McLane James R. Winoker
_________________________
Felix A. Mirando, Jr.
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C> <C>
<FISCAL-YEAR-END> DEC-31-1994 DEC-31-1993
<PERIOD-END> DEC-31-1994 DEC-31-1993
<PERIOD-TYPE> 12-MOS 12-MOS
<BOOK-VALUE> PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,716,721 3,482,501
<OTHER-PROPERTY-AND-INVEST> 423,713 455,127
<TOTAL-CURRENT-ASSETS> 525,723 464,614
<TOTAL-DEFERRED-CHARGES> 418,684 <F1> 393,636 <F1>
<OTHER-ASSETS> 0 0
<TOTAL-ASSETS> 5,084,841 4,795,878
<COMMON> 64,970 64,970
<CAPITAL-SURPLUS-PAID-IN> 736,823 736,823
<RETAINED-EARNINGS> 779,045 728,075
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,580,838 1,529,868
0 0
147,016 <F2> 147,528 <F2>
<LONG-TERM-DEBT-NET> 1,520,488 1,511,589
<SHORT-TERM-NOTES> 233,970 <F3> 71,775
<LONG-TERM-NOTES-PAYABLE> 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 0
<LONG-TERM-DEBT-CURRENT-PORT> 65,920 12,920
0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0
<LEASES-CURRENT> 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,536,609 1,522,198
<TOT-CAPITALIZATION-AND-LIAB> 5,084,841 4,795,878
<GROSS-OPERATING-REVENUE> 2,243,029 2,233,978
<INCOME-TAX-EXPENSE> 128,257 121,124
<OTHER-OPERATING-EXPENSES> 1,818,276 1,809,911
<TOTAL-OPERATING-EXPENSES> 1,946,533 1,931,035
<OPERATING-INCOME-LOSS> 296,496 302,943
<OTHER-INCOME-NET> 16,071 13,657
<INCOME-BEFORE-INTEREST-EXPEN> 312,567 316,600
<TOTAL-INTEREST-EXPENSE> 97,005 107,770
<NET-INCOME> 199,426 190,223
8,697 <F2> 10,585 <F2>
<EARNINGS-AVAILABLE-FOR-COMM> 199,426 188,176
<COMMON-STOCK-DIVIDENDS> 148,456 144,233
<TOTAL-INTEREST-ON-BONDS> 93,500 100,777
<CASH-FLOW-OPERATIONS> 417,966 498,651
<EPS-PRIMARY> $3.07 $2.93
<EPS-DILUTED> $3.07 $2.93
<FN>
<F1> Total deferred charges includes other assets and accrued Yankee Atomic costs.
<F2> Preferred stock reflects preferred stock of subsidiaries. Preferred stock dividends reflect preferred stock dividends of
subsidiaries.
<F3> Short-term notes includes commercial paper obligations.
</FN>
<PAGE>
Exhibit 10(e)
MEMORANDUM OF UNDERSTANDING
WHEREAS, New England Power Company (NEP) provides all
requirements electric service at wholesale to its retail
affiliates, Massachusetts Electric Company, The Narragansett
Electric Company, and Granite State Electric Company (the NEES
Retail Companies) operating in the respective states of
Massachusetts, Rhode Island, and New Hampshire;
WHEREAS, the Massachusetts Department of Public Utilities, the
Rhode Island Public Utilities Commission, and the New Hampshire
Public Utilities Commission regulate the retail rates of the NEES
Retail Companies, which retail rates include wholesale purchased
power costs paid to NEP under wholesale rates regulated by the
Federal Energy Regulatory Commission;
WHEREAS, NEP's cost of providing service and wholesale rates
are affected by the new resources that NEP adds to meet the
electricity requirements of retail customers in Massachusetts,
Rhode Island, and New Hampshire;
WHEREAS, the State Commissions have in place independent
processes through which they review the resource plans and
decisions by NEP prior to the time that those decisions are
reflected in wholesale rates to the NEES Retail Companies; and
WHEREAS, the State Commissions, the NEES Retail Companies, and
NEP believe that plans and resource decisions can be implemented
most effectively under a coordinated, consensual, and consistent
process of review;
NOW THEREFORE, NEP and the NEES Retail Companies commit to do
the following:
<PAGE>
I. Definitions.
As used in this Memorandum:
(A) "Regional Integrated Resource Plan" means a fifteen-year,
system wide resource plan filed by NEP and each NEES
Retail Company with each respective State Commission that
includes: (1) a forecast of demands and kilowatthour
usage by retail customers; (2) an inventory of existing
resources; (3) an identification of additional resource
needs; (4) a projection of the amount of capacity to be
added through Significant New Supply Side Commitments and
other supply side resources that are not Significant New
Supply Side Commitments; (5) a projection of demand side
resources expected to be developed over the planning
horizon; (6) plans for compliance with new environmental
laws, regulations, orders, or consent decrees before
courts or regulatory agencies at existing units involving
significant expenditures, including NEP's proposals to
achieve compliance with the regulatory requirements under
the Clean Air Act Amendments of 1990 at its eight units
at the Salem Harbor and Brayton Point Stations and an
evaluation of those proposals against other alternatives
in the market; (7) a two-year implementation plan
designed to detail how the Regional Integrated Resource
Plan will be developed and implemented in the first two
years; and (8) any other information required to be filed
<PAGE>
with the State Commission under state law or State
Commission regulation.
(B) "Significant New Supply Side Commitment" means a
commitment to either (1) a new contract with a power
supplier ("Purchased Power Contract") or (2) a new
generating project proposed by NEP that is incorporated
in a unit power contract with the NEES Retail Companies
pursuant to Paragraph III ("NEP Unit Power Contract"),
which commitment: (a) is executed or whose construction
will commence after the Regional Integrated Resource Plan
is filed; (b) extends for a period of three years or
longer; (c) involves the purchase of an entitlement in at
least 30 megawatts of additional capacity or requires the
construction of a new generating unit having a total
capacity greater than 30 megawatts; and (d) is intended
to serve the electricity requirements of the NEES retail
companies.
(C) "FERC" means the Federal Energy Regulatory Commission.
(D) "State Commission" means the Massachusetts Department of
Public Utilities, New Hampshire Public Utilities
Commission, and Rhode Island Public Utilities Commission
together with any other agency or agencies that are
authorized under state law to receive or review utility
forecasts and plans in Massachusetts, New Hampshire, and
Rhode Island.
<PAGE>
(E) "All Requirements Tariff" means FERC Electric Tariff,
Original Volume Number 1 of New England Power Company
under which NEP makes all-requirements sales to the NEES
Retail Companies and other wholesale customers.
II. Coordinated State Review of the Regional Integrated Resource
Plans for the NEES Companies.
(A) NEP and each NEES Retail Company shall jointly and
concurrently file at least once every two years a
Regional Integrated Resource Plan with each NEES Retail
Company's respective State Commission.
(B) Each State Commission will review the Regional Integrated
Resource Plan in accordance with state law.
(C) Within 30 days following either (1) the completion of
reviews or the receipt of rulings by all State
Commissions on the Regional Integrated Resource Plan
filing or (2) one year following the filing of the
Regional Integrated Resource Plan, whichever occurs
first, NEP and the NEES Retail Companies shall file a
compliance plan which shall:
(a) notify all State Commissions that the rulings
on the Regional Integrated Resource Plans are
consistent; or
(b) notify all State Commissions that the rulings
on the Regional Integrated Resource Plan are
inconsistent, identify all such inconsistencies,
propose a resolution designed to reconcile the
<PAGE>
inconsistencies, and request a joint hearing before
the State Commissions on the compliance filing.
(D) The State Commissions shall have the opportunity to
supplement or revise their rulings in response to the
compliance plan under Paragraph II.(C) by acting within
90 days of the request.
III. State Commission Review of Significant New Supply Side
Commitments.
(A) On or before its next general wholesale rate filing, NEP
shall file with FERC amendments to its All Requirements
Tariff requiring: (1) all Significant New Supply Side
Commitments, wherever located, to be made initially by
the NEES Retail Companies, subject to review by their
respective State Commissions under Paragraph III.(B), and
conditioned upon a successful completion of that review,
and (2) all Significant New Supply Side Commitments
remaining after state review to be assigned by the NEES
Retail Companies to NEP under Paragraph III.(C).
(B) The NEES Retail Companies shall execute all Purchased
Power Contracts that represent Significant New Supply
Side Commitments and all such contracts shall include a
provision requiring an assignment to NEP in accordance
with the terms of Paragraph III.(C). In addition, the
NEES Retail Companies shall sign NEP Unit Power Contracts
for all projects constructed and owned by NEP that
represent Significant New Supply Side Commitments under
which NEP's rate recovery of appropriate project costs
<PAGE>
will be through its All Requirements Tariff. The NEES
Retail Companies shall file each of these Significant New
Supply Side Commitments with their respective State
Commissions before the Significant New Supply Side
Commitment becomes effective. Each State Commission
shall have 90 days to review the Significant New Supply
Side Commitment; provided, however, that any State
Commission may extend the review period for itself and
all other State Commissions for up to an additional 30
days by issuing a notice or order extending the review
period. If during the review period, as it may be
extended, any State Commission, acting pursuant to state
law and subject to appellate review, objects to the
Significant New Supply Side Commitment or any of its
terms, then the Significant New Supply Side Commitment
shall be rendered null and void, and NEP and all NEES
Retail Companies shall be precluded from going forward
with the Significant New Supply Side Commitment.
(C) If no State Commission objects to a Significant New
Supply Side Commitment within the review period, the
Significant New Supply Side Commitment shall become
effective in accordance with its terms. If the
Significant New Supply Side Commitment is a Purchased
Power Contract, the NEES Retail Companies shall assign it
to NEP, and if the Significant New Supply Side Commitment
is a NEP Unit Power Contract, NEP may proceed with the
project's development.
<PAGE>
(D) If after the date this Memorandum is executed:
(1) A NEES Retail Company terminates all or any part of
its purchases under the All-Requirements Tariff; or
(2) A new law, rule, or order promulgated by a
legislature, court, regulatory agency or other
lawful authority limits the right of any NEES
Retail Company to be the exclusive seller of
electricity at retail within its current franchise
territory; or
(3) A new law, rule, or order promulgated by a
legislature, court, regulatory body or other lawful
authority limits NEP's right to make sales to any
NEES Retail Company under the All-Requirements
Tariff at prices established using NEP's reasonable
and prudent cost of providing service as determined
by FERC,
then the costs that NEP has incurred to serve that NEES
Retail Company shall be allocated to and paid by that
NEES Retail Company and not allocated to or paid by any
other NEES Retail Company.
(E) The procedures established in this Section do not
represent in any way a preapproval process for the rate
recovery by NEP of the costs associated with the
Significant New Supply Side Commitment, and no action or
failure to object by a State Commission shall bind the
State Commission in any way in any future wholesale rate
proceeding before the FERC in which NEP seeks rate
<PAGE>
recovery of the costs associated with the Significant New
Supply Side Commitment. Specifically, failure to object
to a Significant New Supply Side Commitment shall not
preclude the State Commission from arguing to FERC in a
later wholesale rate proceeding that NEP's entry into the
Significant New Supply Side Commitment was unreasonable
or imprudent.
(F) The procedures set forth in this Section shall apply only
to the development of Significant New Supply Side
Commitments. Nothing in this Memorandum shall restrict
or limit the rights or management discretion of NEP or
the NEES Retail Companies to operate and manage their
existing resources and the Significant New Supply Side
Commitments that become effective or are developed
following the State Commission reviews under this
Memorandum, provided, however, that nothing in this
Memorandum shall affect the existing authority of FERC,
or the State Commissions with rate jurisdiction over
reassigned resources, to determine following an
investigation in which interested persons are permitted
to intervene whether the costs incurred are appropriately
recovered in jurisdictional rates. Significant New
Supply Side Commitments shall not include investments or
improvements associated with: (1) the ongoing operation
or management of existing units and the Significant New
Supply Side Commitments that have been developed under
this Memorandum; or (2) compliance with environmental
<PAGE>
laws, regulations, orders, or consent decrees before
courts or regulatory agencies. The Manchester Street
Repowering Project, the replacement of units at the
Vernon Hydro Station, and purchased power contracts made
prior to the effective date of this Agreement are
committed resources and shall not be included in the
definition of a Significant New Supply Side Commitment
and shall not be subject to the procedures set forth in
this Memorandum, provided, however, that all contracts
executed as a result of NEP's request for proposals dated
December 17, 1991 (the Green RFP) shall be treated as
Significant New Supply Side Commitments and shall be
subject to the procedures set forth in this Memorandum.
IV. Conservation and Load Management Programs.
(A) In an Offer of Partial Settlement filed with and approved
by FERC in Docket Nos. ER 88-630-000 et al. (the W-10
Partial Settlement), NEP agreed to cease wholesale rate
recovery of Nondispatchable Program Costs associated with
conservation and load management (C&LM) programs
"whenever a state commission includes Nondispatchable
Program Costs of that affiliate in retail rates." (W-10
Partial Settlement, II.E.3.). NEP also reserved its
right to seek recovery "in wholesale rates for any
expenditures related to C&LM . . . incurred on or after
January 1, 1993." (Id at II.E.5.). Following the
approval of the W-10 Partial Settlement, each of the
State Commissions has included the Nondispatchable
<PAGE>
Program Costs of its respective NEES Retail Company in
retail rates and NEP hereby waives its right under
Section II.E.5 of the W-10 Partial Settlement to seek
recovery of Nondispatchable Program Costs in wholesale
rates during the effective period of this Memorandum of
Understanding. Nothing in this Memorandum shall affect
or restrict NEP's ability to seek recovery of Planning
and Dispatchable Program Costs in wholesale rates or
prevent the reallocation of these costs back to the NEES
Retail Companies, provided, however, that if NEP seeks to
recover these costs, NEP will continue its practice of
filing all relevant cost recovery information with the
State Commissions at the same time that it files this
information with FERC. For purposes of this Memorandum,
"Planning and Dispatchable Program Costs" and
"Nondispatchable Program Costs" shall have the same
meanings as in the W-10 Partial Settlement (II.D.1. and
2.).
(B) NEP agrees to make available to each State Commission
information, data, and analysis necessary to establish
the cost effectiveness of each NEES Retail Company's C&LM
program when that program is evaluated from the
perspective of the integrated NEES System based on NEP's
marginal costs of providing electricity supplies in the
context of the integrated, least cost resource plan, as
well as from the perspective of the NEES Retail Companies
based on NEP's wholesale rate.
<PAGE>
V. Term of Memorandum.
The Term of this Memorandum shall commence when each State
Commission has approved this Agreement and FERC has approved NEP's
filing under Paragraph III.(A), and shall continue for the life of
any Significant New Supply Side Commitment that has become
effective under this Memorandum, provided, however, that NEP or any
NEES Retail Company may terminate their obligations to continue the
contracting and filing procedure for future Significant Supply Side
Commitments under Paragraph III, and NEP may rescind the
modifications to its All-Requirements Tariff made pursuant to
Paragraph III(A) by giving two years written notice to each State
Commission. Notwithstanding the foregoing, NEP or any NEES Retail
Company may immediately terminate such obligations and rescind such
modifications if the following conditions are no longer met:
(A) All Significant New Supply Side Commitments, all
contracts with qualifying facilities wherever they are
located, and all other purchases from any supply side
resource having a capacity greater than one megawatt are
assigned to NEP by the NEES Retail Companies except for
any qualifying facilities signed by Massachusetts
Electric Company pursuant to the October 21, 1991 Offer
of Settlement approved in Docket Nos. E.F.S.C. 91-24 and
D.P.U. 91-114;
(B) An exemption for NEP and Massachusetts Electric Company
from the Massachusetts Integrated Resource Management
regulations set forth in 220 C.M.R. 10.00 et seq. is
granted and remains in effect, and the review of
<PAGE>
Significant New Supply Side Commitments under this
Memorandum is the exclusive procedure for the prior
review of Significant New Supply Side Commitments by
State Commissions other than any further reviews that may
be required by environmental and siting laws within the
state in which the project is to be located or;
(C) Nondispatchable Program Costs are recovered in retail
rates, and the State Commissions recognize as reasonable
and appropriate all conservation and load management
commitments made by or to other State Commissions when
reviewing the Regional Integrated Resource Plans that are
filed under Section I.B.
Granite State Electric Company Massachusetts Electric Company
s/Lydia M. Pastuszek s/John H. Dickson
By: Lydia M. Pastuszek By: John H. Dickson
Title: President Title: President
New England Power Company The Narragansett Electric Company
s/Jeffrey D. Tranen s/Robert L. McCabe
By: Jeffrey D. Tranen By: Robert L. McCabe
Title: President Title: President
DATE: July 21, 1993
<PAGE>
Exhibit 10(l)
1995 FORM
NEW ENGLAND POWER SERVICE COMPANY
25 Research Drive
Westborough, Massachusetts 01582
SERVICE CONTRACT
December 30, 1994
Company
Address
New England Power Service Company (hereinafter called Service
Company) is a company engaged primarily in the rendering of services to
companies in the New England Electric System holding-company system.
The organization, conduct of business and method of cost allocation of
the Service Company are designed to meet the requirements of Section 13
under the Public Utility Holding Company Act of 1935 and the rules and
regulations promulgated thereunder to the end that services performed by
the Service Company for said associate companies will be rendered to
them at cost, fairly and equitably allocated. Services will be rendered
by Service Company only upon receipt from time to time of specific or
general request therefor. Said requests may always be modified or
cancelled by you at your discretion. The parties hereto agree as
follows:
1. The Service Company agrees to furnish you upon the terms and
conditions herein set forth such of the services described in Schedule
1 hereto as you may from time to time request. Service Company will
also furnish, if available, such services not described in Schedule 1 as
you may request. Notwithstanding the foregoing the Service Company
shall not furnish under this agreement any engineering, construction, or
maintenance services for a nuclear generating plant.
2. The Service Company has and will maintain a staff trained and
experienced in the engineering, construction, operation, maintenance and
management of public utility properties. In addition to the services of
its own staff, Service Company will, after consultation with you
concerning services to be rendered pursuant to your request, arrange for
services of non-affiliated experts, consultants, accountants and
attorneys.
3. All of the services rendered under this agreement will be at
actual cost thereof. Direct charges will be made for services where a
direct allocation of cost is possible. The methods of determining such
costs and the allocation thereof are set forth in Schedule II hereto.
These methods are reviewed annually and more frequently, if appropriate.
Such methods may be modified or changed by Service Company without the
necessity of an amendment of this agreement provided that in each
instance all services rendered hereunder will be at actual cost thereof,
fairly and equitably allocated, and all in accordance with the
<PAGE>
requirements of the Public Utility Holding Company Act of 1935 and the
rules and regulations and orders thereunder. You will be advised from
time to time of any material changes in such methods.
4. Bills will be rendered during the first week of each month
covering amounts due for the month calculated on an estimated basis
using the actual expenses incurred during the previous month. This
estimated amount would be adjusted on the bill to be rendered during the
first week of the following month. Any amount remaining unpaid after
fifteen days following receipt of the bill shall bear interest thereon
from the date of the bill at an annual rate of 2% above the lowest
interest rate then being charged by the First National Bank of Boston on
90 day commercial loans. Services will be performed hereunder for not
more than one year commencing January 1, 1995, and continuing through
December 31, 1995, unless terminated at an earlier date by either party
giving thirty days' written notice to the other of such termination at
the end of any month.
5. This agreement will be subject to termination or modification
at any time to the extent its performance may conflict with any federal
or state law or any rule, regulation or order of a federal or state
regulatory body having jurisdiction. The agreement shall be subject to
approval of any federal or state regulatory body whose approval is a
legal prerequisite to its execution and delivery or performance.
NEW ENGLAND POWER SERVICE COMPANY
By:
Treasurer
Accepted , 19
By
<PAGE>
Exhibit 10(y)
AMENDING AGREEMENT
------------------
THIS AMENDING AGREEMENT dated as of the 29th day of October, 1993
BETWEEN:
TRANSCANADA PIPELINES LIMITED
a Canadian corporation
("TransCanada")
AND
NEW ENGLAND POWER COMPANY
a Company incorporated under the laws
of the State of Massachusetts
("Shipper")
WITNESSETH THAT:
WHEREAS TransCanada and Shipper are parties to a Firm
Service Contract dated January 6, 1992 as amended (the "Firm
Service Contract"), which provides for the firm delivery of gas by
TransCanada to a point on the international border near Iroquois,
Ontario (the "Delivery Point"); and
WHEREAS Shipper requested and TransCanada agreed, on the
terms and conditions set forth herein, to amend the volume of gas
to be transported under the Firm Service Contract for the period
between November 1, 1993 and October 31, 1994.
NOW THEREFORE, in consideration of the mutual covenants
and agreements hereinafter set forth, and other good and valuable
consideration, the receipt and sufficiency of which is hereby
acknowledged, TransCanada and Shipper hereby agree as follows:
1. Article II of the Firm Service Contract is deleted in its
entirety and the following is substituted therefor:
<PAGE>
"ARTICLE II - GAS TO BE TRANSPORTED
- -----------------------------------
2.1 Subject to the provisions of this Contract, the FS Toll
Schedule, the List of Tolls, and the General Terms and Conditions
referred to in Section 7.1 hereof, TransCanada shall provide
transportation service hereunder for Shipper in respect of a volume
of gas which, in any one day, from November 1, 1993 until October
31, 1994, shall not exceed 1406.6 10 3m3 and from November 1, 1994
until October 31, 2006, shall not exceed 1699.7 10 3m3 (the
"Contract Demand")."
2. Subject to the amendments contained herein, the Firm
Service Contract is hereby ratified and confirmed.
TRANSCANADA PIPELINES UNITED
s/ H. Feldman
per
s/ S. S. G.
per
NEW ENGLAND POWER COMPANY
s/ Jeffrey W. VanSant
per
s/ John F. Malley
per
<PAGE>
Exhibit 10(z)
TEMPORARY TRANSPORTATION CONTRACT ASSIGNMENT
THIS TEMPORARY ASSIGNMENT made effective as of the 27th day of
October, 1993
BETWEEN: RENAISSANCE ENERGY LTD.
("Assignor")
OF THE FIRST PART
AND
NEW ENGLAND POWER COMPANY
("Assignee")
OF THE SECOND PART
WITNESSES THAT:
WHEREAS, TransCanada PipeLines Limited ("TransCanada") and Assignor
are parties to a Firm Service Contract for firm transportation
service to the Niagara, Ontario Delivery Point made as of November
1, 1993 (a copy of such contract made thereto to the date hereof
being attached hereto as Exhibit " I " and forming a part hereof
(said contract, being hereinafter called the "Contract"); and
WHEREAS, Assignee has requested that Assignor assign part of
Assignor's rights and obligations as Shipper under the Contract and
Assignor has agreed to do so subject to the terms and conditions of
this Assignment.
NOW. THEREFORE. THIS AGREEMENT WITNESSES THAT in consideration of
the covenants and agreements herein set forth, the parties hereto
covenant and agree as follows:
1. Subject to paragraph 6 herein, during the operative term
of this Assignment, Assignor does hereby grant, transfer, assign
and set over unto Assignee, and Assignee accepts from Assignor,
that portion of Assignor's service entitlement as shipper under the
Contract equal to 333.6 10 3m3 per day (the "Assigned Volume"),
together with the corresponding rights and obligations of Assignor
as shipper under the Contract.
2. Subject to Paragraphs 6 and 8 herein, during the
operative term of this Assignment, Assignee hereby covenants and
agrees that it shall perform and observe the covenants and
obligations of Assignor as shipper contained in the Contract
insofar as they pertain to the Assigned Volume, to the same extent
as Assignee would be obligated so to do were Assignee a party to
<PAGE>
the Contract, as shipper, with a service entitlement thereunder
equal to the Assigned Volume.
3. This Assignment shall be in full force and effect as of
and from 08:00 hours on November 1, (the "Date of First Delivery")
(provided that, for the purposes of Assignee nominating service for
the Date of First Delivery, this Assignment shall become effective
as at 08:00 hours on the date immediately preceding the Date of
First Delivery) and, subject to paragraph 4 hereof shall be
operative for a term ending at 08:00 hours on November 1, 1994.
Notwithstanding the foregoing, the operative term of this
Assignment shall not extend beyond the term of the Contract.
4. In the event that Assignee fails to comply with paragraph
2 hereof, Assignor shall have the right to terminate this
Assignment by following the termination procedure set forth in
Section XVII of the General Terms and Conditions contained in
TransCanada's Transportation Tariff as if Assignor were
TransCanada, Assignee were Shipper and this Assignment was the
Contract for this purpose.
5. Assignor will request TransCanada to acknowledge the
assignment herein and to treat Assignee as shipper with a service
entitlement under the Contract equal to the Assigned Volume during
the operative term of this Assignment. Assignee hereby consents to
such request and to such treatment, and for this purpose Assignee
declares that all notices, nominations, requests, invoices, and
other written communications may be given by TransCanada to
Assignee as follows:
(i) Mailing address: 25 Research Drive
Westborough, Massachusetts
01582
(ii) Delivery address: Same as mailing address
(iii) Nominations: Director of Fuel Supply
Facsimile: (508) 898-3952
(iv) Legal and Other: Director of Fuel Supply
6. Assignee acknowledges that Assignor will not seek
TransCanada's consent to this Assignment and that Assignor
accordingly is and will remain obligated to TransCanada to perform
and observe the covenants and obligations of shipper that are
contained in the Contract in regard to the Assigned Volume insofar
as TransCanada is concerned. Without limiting the generality of
the foregoing, the Assignor and the Assignee acknowledge that the
Assignor shall remain responsible for all gas imbalances (as such
term is defined in Section XXII of the General Terms and Conditions
in TransCanada's Transportation Tariff) and Energy-in-Transit
balances associated with the Assigned volume and/or the Contract.
Consequently, Assignee shall indemnify Assignor for and hold
Assignor harmless from all charges that TransCanada may be entitled
to collect from Assignor under the Contract in regard to the
Assigned Volume in the event that Assignee fails to pay them.
<PAGE>
7. Assignee shall be entitled to sub-assign all or part of
the Assigned Volume, together with the corresponding rights and
obligations under the Contract, to a third party by assigning all
or part of its rights and obligations under this Assignment;
provided that no such assignment shall relieve Assignee of its
obligations to Assignor hereunder without Assignor's prior written
consent, which consent shall not be unreasonably withheld.
Notwithstanding any such sub-assignment or sub-assignments,
Assignor is and will remain obligated to TransCanada to perform and
observe the covenants and obligations of shipper that are contained
in the Contract in regard to the Assigned Volume insofar as
TransCanada is concerned.
8. Notwithstanding anything to the contrary herein set forth
or implied, Assignor reserves and retains for itself exclusively
any option or right to renew or otherwise extend the operative term
of the Contract which may be contained in or granted by the
Contract.
9. Assignee acknowledges that it has (or may obtain directly
from TransCanada) a copy of the Transportation Tariff.
10. This Assignment and the rights and obligations of the
parties hereunder are subject to all valid and applicable present
and future laws, rules, regulations, and orders of any governmental
or regulatory authority having jurisdiction or control over the
parties hereto to either of them, or over the Contract.
11. This Assignment shall be construed in accordance with and
governed by the laws of the Province of Alberta and the laws of
Canada applicable therein.
12. This Assignment shall enure to the benefit of and be
binding upon, the parties hereto and their respective successors
and permitted assigns.
IN WITNESS WHEREOF the parties hereto have duly executed
and delivered this Assignment as of the day, month. and year first
above written.
RENAISSANCE ENERGY LTD. NEW ENGLAND POWER COMPANY
- ---------------------- --------------------------
ASSIGNOR ASSIGNEE
s/ Max Muselius s/ Jeffrey W. VanSant
BY: BY:
Vice President, Marketing Vice President
TITLE: TITLE:
<PAGE>
s/ John F. Malley
BY: BY:
Vice President
TITLE: TITLE:
cc: TransCanada PipeLines Limited
FAX: (403) 267-8620 S.K. Dorton
<PAGE>
FIRM SERVICE CONTRACT
---------------------
THIS FIRM SERVICE CONTRACT FOR FIRM TRANSPORTATION
SERVICE, made as of the 1st day of November, 1993.
BETWEEN: TRANSCANADA PIPELINES
LIMITED
a Canadian corporation
("TransCanada")
OF THE FIRST PART
and
RENAISSANCE ENERGY LTD-
a company incorporated
under the laws of the
Province of Alberta
("Shipper")
OF THE SECOND PART
WITNESSES THAT:
WHEREAS TransCanada owns and operates a natural gas
pipeline system extending from a point near the Alberta/
Saskatchewan border where TransCanada's facilities interconnect
with the facilities of NOVA Corporation of Alberta easterly to the
Province of Quebec with branch lines extending to various points on
the Canada/United States of America International Border; and
WHEREAS Shipper, Norcen Energy Resources Limited, Rigel
Oil and Gas Ltd., Wainoco Oil Corporation, Ulster Petroleum Ltd.,
Canadian Pioneer Energy Inc., Tarragon Oil and Gas Limited,
Northbridge Gas Marketing, Inc. (collectively, the "Assignor"), and
TransCanada are parties to a firm service contract to the Niagara
Falls Delivery Point made as of the 28th day of July, 1989 having
a Daily Contract Quantity of 904.0 10 3m3 (such firm service
<PAGE>
contract, as amended from time to time to the date hereof being
hereinafter called the "Old Contract"); and
WHEREAS pursuant to an amending agreement dated November
1, 1993, (the "Amending Agreement") Shipper was removed as a party
to the Old Contract effective upon execution of this Contract by
TransCanada and Shipper; and
WHEREAS Shipper has satisfied in full, or TransCanada
has waived, each of the conditions precedent set out in Sections
1.1 (b) and (c) of TransCanada's Firm Service Toll Schedule
referred to in Section 7.1 hereof (the "FS Toll Schedule"); and
WHEREAS Shipper has requested and TransCanada has agreed
to transport volumes of gas, that are delivered by Shipper or
Shipper's agent to TransCanada at the Receipt Point referred to in
Section 3.2 hereof (the "Receipt Point"), to the Delivery Point
referred to in Section 3.1 hereof (the "Delivery Point") pursuant
to the terms and conditions of this Contract; and
WHEREAS the volumes of gas delivered hereunder by Shipper
or Shipper's agent to TransCanada are to be removed from the
province of production of such gas by Shipper and/or Shipper's
suppliers and/or its (their) designated agent(s) pursuant to valid
and subsisting permits and/or such other authorizations in respect
thereof.
NOW THEREFORE THIS CONTRACT WITNESSES THAT, in
consideration of the covenants and agreement herein contained, the
parties hereto covenant and agree as follows:
<PAGE>
ARTICLE I - COMMENCEMENT OF SERVICE
- -----------------------------------
1.1 The date of commencement of service hereunder (the "Date
of Commencement") shall be November 1, 1993.
ARTICLE II - GAS TO BE TRANSPORTED
- ----------------------------------
2.1 Subject to the provisions of this Contract, the FS Toll
Schedule, the List of Tolls, and the General Terms and Conditions
referred to in Section 7.1 hereof, TransCanada shall provide
transportation service hereunder for Shipper in respect of a volume
of gas which, in any one day from the Date of Commencement until
the 31st day of October, 2009, shall not exceed 419.0 10 3m3 (the
"Contract Demand").
ARTICLE III - DELIVERY POINT AND RECEIPT POINT
- ----------------------------------------------
3.1 The Delivery Point hereunder is the point specified as
such in Exhibit "1" which is attached hereto and made a part
hereof.
3.2 The Receipt Point hereunder is the point specified as
such in Exhibit "1" hereof.
<PAGE>
ARTICLE IV - TOLLS
- ------------------
4.1 Shipper shall pay for ail transportation service
hereunder from the Date of Commencement in accordance with
TransCanada's FS Toll Schedule, List of Tolls, and General Terms
and Conditions set out in TransCanada's Transportation Tariff as
the same may be amended or approved from time to time by the
National Energy Board ("NEB").
4.2 Shipper shall pay delivery pressure service hereunder
from the Date of Commencement in accordance with TransCanada's FS
Toll Schedule, List of Tolls and General Terms and Conditions set
out in TransCanada's Transportation Tariff as the same may be
amended or approved from time to time by the NEB.
ARTICLE V - TERM OF CONTRACT
- ----------------------------
5.1 This Contract shall be effective from the date hereof and
shall continue until the 31st day of October, 2009.
ARTICLE VI - NOTICES
- --------------------
6.1 Any notice, request or demand ("Notice") to or upon the
respective parties hereto shall be in writing and shall be validly
communicated by the delivery thereof to its addressee, either
personally or by courier, first class mail, or telecopier to the
address hereinafter mentioned:
<PAGE>
IN THE CASE OF TRANSCANADA: TransCanada PipeLines Limited
(i) mailing address: P.O. Box 1000
Station M
Calgary, Alberta
T2P 4K5
(ii) delivery address: TransCanada PipeLines Tower
111 - 5th Avenue S.W.
Calgary, Alberta
T2P 3Y6
Attention: Vice-President,
Transportation Services &
Rates
Telecopy: (403) 267-8620
(iii) nominations: Attention: Supervisor, Gas
Accounting
Telecopy: (403) 267-6338/6339
(iv) invoices Attention: Manager, Revenue
Accounting
Telecopy: (403) 267-1074
(v) other matters: Attention: Vice-President,
Transportation Services &
Rates
Telecopy: (403) 267-8620
IN THE CASE OF SHIPPER: Renaissance Energy Ltd.
(i) mailing address: 3300, 400 - 3rd Avenue SW
Calgary, Alberta
T2P 4H2
(ii) delivery address: Same as above
(iii) nominations: Attention: Coordinator,
Transportation & Supply
Telecopy: (403) 267-4811
(iv) invoices: Attention: Manager, Marketing
Contracts & Operations
Telecopy: (403) 267-4811
(v) other matters: Attention: Manager, Marketing
Contracts & Operations
Telecopy: (403) 267-4811
Any such Notice shall be sent in order to ensure prompt receipt of
such Notice by the other party. Such Notice sent as aforesaid
shall be deemed to have been received by the party to whom it is
<PAGE>
sent at the time of its delivery if personally delivered or if sent
by telecopier, or on the day following transmittal thereof if sent
by courier, or on the third day following the transmittal thereof
if sent by first class mail; PROVIDED however, that, in the event
normal mail service, courier service, or telecopier service shall
be interrupted by a cause beyond the control of the parties hereto,
then the party sending the Notice shall utilize any service that
has not been so interrupted or shall deliver such Notice. Each
party shall provide Notice to the other of any change of address
for the purposes hereof.
ARTICLE VII - MISCELLANEOUS PROVISIONS
- --------------------------------------
7.1 The FS Toll Schedule, the List of Tolls, and the General
Terms and Conditions set out in TransCanada's Transportation Tariff
as amended or approved from time to time by the NEB are all by
reference made a part of this Contract and operations hereunder
shall, in addition to the terms and conditions of this Contract, be
subject to the provisions thereof. TransCanada shall notify
Shipper at any time that TransCanada files with the NEB revisions
to the FS Toll Schedule, the List of Tolls, and/or the General
Terms and Conditions (the "Revisions") and shall provide Shipper
with a copy of the Revisions.
7.2 The headings used throughout this Contract, the FS Toll
Schedule, the List of Tolls, and the General Terms and Conditions
are inserted for convenience of reference only and are not to be
<PAGE>
considered or taken into account in construing the terms or
provisions thereof nor to be deemed in any way to quality, modify
or explain the effect of any such provisions or terms.
7.3 This Contract shall be construed and applied, and be
subject to the laws of the Province of Alberta, and, when
applicable, the laws of Canada, and shall be subject to the rules,
regulations and orders of any regulatory or legislative authority
having jurisdiction.
7.4 All terms and words herein capitalized and not
otherwise defined in this Contract are incorporated by reference
into this Contract from the FS Toll Schedule, the List of Tolls,
and the General Terms and Conditions set out in TransCanada's
Transportation Tariff as amended from time to time.
ARTICLE VIII - DELIVERY PRESSURE
- --------------------------------
8.1 TransCanada shall increase the line pressure of the gas
it delivers to Shipper at the Delivery Point to a pressure of not
less than 4 850 kPa (g).
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this
Contract as of the date first above written.
TRANSCANADA PIPELINES LIMITED
s/Steve Johnson
per
Vice President
title
s/ S.S.M.
per
title
RENAISSANCE ENERGY LTD.
s/Max Muselius
per
Vice President-Marketing
title
<PAGE>
EXHIBIT "1"
This is EXHIBIT "1" to the FIRM SERVICE CONTRACT for FIRM
TRANSPORTATION SERVICE, made as of the 1st day of November, 1993
between TRANSCANADA PIPELINES LIMITED ("TransCanada") and
RENAISSANCE ENERGY LTD. ("Shipper")
The Delivery Point hereunder is the point of
interconnection between the pipeline facilities of TransCanada and
Tennessee Gas Pipeline Company which is located at:
Niagara Falls, Ontario
The Receipt Point hereunder is the point of
interconnection between the pipeline facilities of TransCanada and
NOVA Corporation of Alberta which is located at:
Empress, Alberta
<PAGE>
To: TransCanada PipeLines Limited
Attn: Ches Maciorowski
Date: October 25, 1994
To Whom It May Concern:
Attached are copies of Temporary Transportation Contract
Assignments as follows;
1. Temporary Transportation Contract Assignment between New
England Power Company (Assignor) and Renaissance Energy Ltd.
(Assignee), dated October 28, 1993.
2. Temporary Transportation Contract Assignment between
Renaissance Energy Ltd. (Assignor) and New England Power Company
(Assignee), dated October 27, 1993.
The purpose of these Assignments was to effect a swap of capacity
held by New England Power Company to Waddington for capacity held
by Renaissance to Niagara for the time period November 1, 1993
through November 1, 1994. The swap volume was 333.6 10 3m3.
The purpose of this letter is to ask that TransCanada accept the
request of New England Power Company and Renaissance Energy Ltd. to
extend the period of the above outlined agreements from November 1,
1994 through November 1, 1995; and that the volume be changed from
333.6 10 3m3 to 333.9 10 3m3.
Both parties to the assignments outlined above have signed here to
signify to you their mutual agreement to the changes proposed in
the immediately preceding paragraph.
Please advise immediately if this letter agreement is sufficient to
effect the charges outlined herein.
Thank you.
NEW ENGLAND POWER COMPANY RENAISSANCE ENERGY LTD.
s/Jeffrey W. VanSant s/J.A. Curkan
By: By:
Manager, Marketing
Authorized Signatory Contracts & Operations
Title: Title:
By:
Title:
October 26, 1994
Date: Date:
<PAGE>
Exhibit 10(aa)
GAS TRANSPORTATION AGREEMENT
Firm Transportation Service
----------------------------
(For New England Power Company)
(Continued)
EXHIBIT A
RECEIPT AND DELIVERY POINTS
TO THE GAS TRANSPORTATION AGREEMENT BETWEEN
ALGONQUIN GAS TRANSMISSION COMPANY (TRANSPORTER) AND
NEW ENGLAND POWER COMPANY (SHIPPER)
DATED APRIL 15,1994
-------------
(Continued)
Deliveries for the account of Shipper shall be made at each Point
of Delivery in quantities not in excess of the Maximum Daily
Delivery Obligation specified herein and at a pressure not less
than the Minimum Delivery Pressure specified herein.
Transporter' Maximum Daily Minimum
Point(s) of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (1) Psig
- ------------- ------------------- ----------------
Beginning on the later of (i) November 1, 1993 or (ii) the date on
which all necessary facilities required to be constructed by
Transporter and upstream domestic pipelines are completed and ready
for service:
Manchester, St.
Meter Station
Providence, RI 59,220 MMBtu 350
Interconnection between
Algonquin's G-1 System
and the Brayton Point
Lateral in Dighton, MA 0 MMBtu -
801 Milford, MA
Meter Station 0 MMBtu -
<PAGE>
GAS TRANSPORTATION AGREEMENT
Firm Transportation Service
---------------------------
(For New England Power Company)
(Continued)
EXHIBIT A
RECEIPT AND DELIVERY POINTS
TO THE GAS TRANSPORTATION AGREEMENT BETWEEN
ALGONQUIN GAS TRANSMISSION COMPANY (TRANSPORTER) AND
NEW ENGLAND POWER COMPANY (SHIPPER)
DATED APRIL 15,1994
(Continued)
Transporter's Maximum Daily Minimum
Point(s) of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (1) Psig
- ------------- --------------------- -----------------
Beginning on the later of (i) November 1, 1994 or (ii) the date that
all necessary facilities required to be constructed by Transporter
and upstream domestic pipelines are completed and ready for
service:
Manchester, St.
Meter Station
Providence, RI 94,214 MMBtu 350
Interconnection between
Algonquin's G-1 System
and the Brayton Point
Lateral in Dighton, MA 0 MMBtu -
801 Milford, MA
Meter Station 0 MMBtu -
Signed for Identification
s/ John J. Mullaney
Algonquin:
s/ Jeffrey W. VanSant s/ Jeffrey D. Tranen
Shipper:
Jeffrey W. VanSant Jeffrey D. Tranen
Vice President President
Supersedes Exhibit A of Contract Number 932002 Dated July 3, 1992.
_______________
(1) The above Maximum Daily Receipt Obligation shall be equal to the
total of Maximum Daily Delivery Obligation for each delivery point
plus Transporter's allowed Fuel Reimbursement Quantity as may exist
from time to time.
<PAGE>
ANNUAL REPORT 1994
NEW ENGLAND POWER COMPANY
A Subsidiary of
New England Electric System
[LOGO] New England Power
A New England Electric System company
<PAGE>
NEW ENGLAND POWER COMPANY
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of December 31, 1994)
Joan T. Bok John W. Newsham
Chairman of the Board of New Executive Vice President of the Company
England Electric System and Vice President of New England
Electric System
Frederic E. Greenman
Vice President, General Counsel, John W. Rowe
and Assistant Clerk of the Company Chairman of the Company and President
and Senior Vice President, General and Chief Executive Officer of New
Counsel, and Secretary of New England Electric System
England Electric System
Jeffrey D. Tranen
Alfred D. Houston President of the Company and Vice
Executive Vice President and Chief President of New England Electric System
Financial Officer of New England
Electric System
Officers
(As of December 31, 1994)
John W. Rowe John F. Malley
Chairman of the Company and Vice President
President and Chief Executive
Officer of New England Electric Arnold H. Turner
System Vice President
Jeffrey D. Tranen Jeffrey W. VanSant
President of the Company and Vice Vice President
President of New England Electric
System Michael E. Jesanis
Treasurer of the Company and of New
John W. Newsham England Electric System
Executive Vice President of the
Company and Vice President of New Robert King Wulff
England Electric System Clerk of the Company and of certain
affiliates
Lawrence E. Bailey
Vice President John G. Cochrane
Assistant Treasurer of the Company and
Jeffrey A. Donahue of an affiliate
Vice President
Kirk L. Ramsauer
Frederic E. Greenman Assistant Clerk of the Company and of an
Vice President, General Counsel, and affiliate
Assistant Clerk of the Company and
Senior Vice President, General Howard W. McDowell
Counsel, and Secretary of New Controller of the Company and of certain
England Electric System affiliates
Transfer Agent and Dividend Paying Agent of Preferred Stock
Bank of Boston, Boston, Massachusetts
Registrar of Preferred Stock
State Street Bank and Trust Company, Boston, Massachusetts
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
<PAGE>
NEW ENGLAND POWER COMPANY
New England Power Company, a wholly-owned subsidiary of New England
Electric System, is a Massachusetts corporation and is qualified to do
business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. The Company is subject, for certain purposes, to the
jurisdiction of the regulatory commissions of these six states, the
Securities and Exchange Commission and the Federal Energy Regulatory
Commission. The Company's business is principally that of generating,
purchasing, transmitting, and selling electric energy in wholesale quantities
to other electric utilities, principally its affiliates, Granite State
Electric Company, Massachusetts Electric Company, and The Narragansett
Electric Company. In 1994, 94 percent of the Company's revenue from the sale
of electricity was derived from sales for resale to affiliated companies and
6 percent from sales for resale to municipal and other utilities.
The Company, through its own generating units, entitlements and purchase
power contracts, has a total capability of 5,533 megawatts. In 1994, the
Company's energy mix was 37 percent coal, 19 percent nuclear, 16 percent gas,
12 percent hydro, 10 percent oil, and 6 percent renewable non-utility
generation.
The Company is a member of the New England Power Pool, which provides
for the coordination of the planning and operation of the generation and
transmission facilities in New England, and the region-wide central dispatch
of generation.
Report of Independent Accountants
New England Power Company, Westborough, Massachusetts:
We have audited the accompanying balance sheets of New England Power
Company (the Company), a wholly-owned subsidiary of New England Electric
System, as of December 31, 1994 and 1993 and the related statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of the Company as
of December 31, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 27, 1995
<PAGE>
NEW ENGLAND POWER COMPANY
Financial Review
Overview
Net income increased by $8 million in 1994 compared with 1993,
reflecting decreased purchased power charges excluding fuel, lower interest
expense and increased allowance for funds used during construction. The
decrease in purchased power was due to overhauls and refueling shutdowns of
partially-owned nuclear power suppliers in 1993. In addition, earnings in
1993 were reduced by a one-time after-tax charge of $6 million ($10 million
before tax) associated with an early retirement program. Partially
offsetting these increases in 1994 earnings were increased operation and
maintenance expenses and the reimbursement of certain power plant
dismantlement costs through revenue credits to The Narragansett Electric
Company (Narragansett), an affiliate.
Net income increased by $7 million in 1993, primarily as a result of
increased revenues attributable to increased peak-demands for electricity in
the summer of 1993, lower costs of scheduled overhauls at thermal generating
units in 1993, and reduced interest costs achieved through debt refinancings.
The increased earnings were partially offset by the one-time charge in
connection with the early retirement program discussed above as well as
increases in operation and maintenance expenses.
Rate Activity
In February 1995, the Federal Energy Regulatory Commission (FERC)
approved a rate agreement filed by the Company. Under the agreement, which
is effective January 1995, the Company's base rates will be frozen until
1997. Before this rate agreement, the Company's rate structure contained two
surcharges which were recovering the costs of a coal conversion project and
a portion of the Company's investment in the Seabrook 1 nuclear unit
(Seabrook 1). Under the rate agreement, these two surcharges, which were due
to expire in mid-1995, will be rolled into base rates. The agreement also
provides for the costs resulting from the Manchester Street Station
repowering project, which is expected to be completed in late 1995, to be
included in rate base, without a rate increase (see "Utility Plant
Expenditures and Financings" section). In addition, the agreement allows the
Company to recover approximately $50 million of deferred costs associated
with terminated purchased power contracts and postretirement benefits other
than pensions (PBOPs) over seven years. The agreement also provides for full
current recovery of PBOP costs commencing in 1995. The agreement further
provides for the recovery over three years of $27 million of costs related
to the dismantling of a retired Narragansett generating station and the
replacement of a turbine rotor at one of the Company's generating units. The
agreement also increases the Company's recovery of depreciation expense by
approximately $8 million annually to recognize costs associated with the
eventual dismantling of its Brayton Point and Salem Harbor generating plants.
Under the agreement, approximately $15 million of the $38 million in
Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement
agreement will be deferred and recovered in 1996. The agreement further
allows for deferral of additional purchased power contract termination costs
and any increases in nuclear decommissioning payments for recovery in future
rates. Yankee Atomic Electric Company, of which the Company is a 30 percent
owner, recently announced a new decommissioning cost estimate, which, if
approved by the FERC, would increase annual billings to the Company by $11
million, beginning in late 1995 and ending in July 2000. (See Note C-1 of
the "Notes to Financial Statements" for a discussion of a 1995 shutdown of
the Maine Yankee nuclear unit.)
The settlement rates provide for approximately $24 million in revenues
in 1996 to complete the amortization of pre-1988 Seabrook 1 costs and the
costs associated with the cancelled Seabrook 2 nuclear unit. To the extent
the settlement rates stay in effect beyond 1996, the agreement provides that
these revenues be applied first to accelerate recovery of deferred PBOP
<PAGE>
costs, and then to additional amortization of the Company's investment in the
Millstone 3 nuclear unit.
Finally, the agreement provided that the Company would reimburse its
wholesale customers for approximately $15 million of discounts provided by
these customers under service extension discount programs. Under these
programs, retail customers are entitled to such discounts only if they have
signed an agreement not to purchase power from another supplier or generate
any additional power themselves for a three to five year period.
The FERC's approval of this rate agreement applies to all of the
Company's customers except the Town of Norwood, Massachusetts and the Milford
Power Limited Partnership (MPLP), who intervened in the rate case. A
separate hearing will be conducted to determine the appropriate rate to
charge these two parties, who represent less than 2 percent of the Company's
sales.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
----------------------------------------
(In Millions) 1994 1993
- ------------- ---- ----
Sales growth $10 $17
Narragansett integrated facilities credit
(excluding fuel) (6) 11
Rate changes - 3
Fuel recovery (6) (4)
Accrued NEEI fuel revenues (7) (8)
Other 1 (1)
--- ---
$(8) $18
=== ===
The entire output of Narragansett's generating capacity is made
available to the Company. Narragansett receives a credit on its purchased
power bill from the Company for its fuel costs and other generation and
transmission-related costs. The increased credit in 1994 reflects increased
dismantlement costs being incurred on Narragansett's previously retired South
Street generating facility. The decrease in the credit in 1993 shown in the
table above reflects reduced non-fuel related credits due to the mid-1992
sale by Narragansett to the Company of 90 percent of its ownership interest
in the Manchester Street Station (see "Utility Plant Expenditures and
Financings" section).
Accrued New England Energy Incorporated (NEEI) fuel revenues and accrued
NEEI fuel costs (see "Operating Expenses" section) reflect losses incurred
by NEEI, an affiliate of the Company, on its rate-regulated oil and gas
operations. These revenues are accrued in the year of the loss but are
billed to the Company's customers through its fuel adjustment clause in the
following year. Changes in accrued NEEI fuel revenues and fuel costs are
principally due to fluctuations in NEEI production (see "Fuel Supply"
section).
<PAGE>
Operating Expenses
The following table summarizes the changes in total operating expenses
discussed below:
Increase (Decrease) in Operating Expenses
-----------------------------------------
(In Millions) 1994 1993
- ------------ ---- ----
Fuel costs $(7) $(3)
Accrued NEEI fuel costs (7) (8)
Purchased energy excluding fuel (11) (2)
Other operation and maintenance 18 13
Depreciation and amortization 6 4
Taxes 5 15
--- ---
$ 4 $19
=== ===
Total fuel costs represent fuel for generation and the portion of
purchased electric energy permitted to be recovered through the Company's
fuel adjustment clause.
Purchased energy excluding fuel represents the remainder of purchased
electric energy costs. The 1994 decrease in purchased energy excluding fuel
was primarily due to overhauls and refueling shutdowns of partially-owned
nuclear power suppliers in 1993.
The increase in other operation and maintenance expense in 1994 reflects
increases in generating plant maintenance costs associated with overhauls of
wholly-owned generating units in part to achieve compliance with the Clean
Air Act. The increase also reflects cost increases in computer system
development, increased demand-side management program expenses, and general
increases in other areas. These increases were partially offset by a
one-time charge in 1993 of $10 million associated with an early retirement
program.
The increase in other operation and maintenance expense in 1993
primarily reflects the previously mentioned early retirement program costs,
$2 million associated with the adoption of a new accounting standard for
postemployment benefits, increased computer systems development costs, and
general increases in other areas. These increases were partially offset by
an $8 million decrease in generating plant maintenance costs.
The increases in depreciation and amortization expense in 1994 and 1993
primarily reflect increased amortization of Seabrook 1 as part of a 1988 rate
settlement and increased depreciation on new plant expenditures. The
increase in 1993 was partially offset by a decrease in depreciation as a
result of new lower depreciation rates established in a prior rate case,
which went into effect in March 1992.
The increase in taxes in 1994 and 1993 primarily reflects increased
income taxes and municipal property taxes. The increase in income taxes in
1993 also includes the effects of the 1993 increase in the federal income tax
rate from 34 percent to 35 percent.
Interest Expense
The decreases in interest expense in 1994 and 1993 are primarily due to
significant refinancings of corporate debt at lower interest rates during
1993 and 1992. In addition, the decrease in 1994 also reflects reduced
interest on rate refunds and taxes primarily in the fourth quarter, partially
offset by increased interest on short-term debt.
<PAGE>
Allowance for Funds Used During Construction (AFDC)
AFDC increased in 1994 and 1993 due to increased construction work in
progress associated with the repowering of the Manchester Street Station (see
"Utility Plant Expenditures and Financings" section).
Fuel Supply
NEEI is engaged in domestic oil and gas exploration, development, and
production. NEEI operates under an intercompany pricing policy (Pricing
Policy) with the Company which was approved by the Securities and Exchange
Commission under the Public Utility Holding Company Act of 1935. The Pricing
Policy requires the Company to purchase all fuel meeting its specifications
offered to it by NEEI. Due to precipitate declines in oil and gas prices,
NEEI has incurred operating losses since 1986, and expects to incur
substantial additional losses in the future. These losses are being passed
on to the Company under the Pricing Policy. The Company is allowed to
recover these losses from its customers under the Company's 1988 FERC rate
settlement, which covered all costs incurred by or resulting from commitments
made by NEEI through March 1, 1988. Other subsequent costs incurred by NEEI
are subject to normal regulatory review.
Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. New
England Electric System (NEES) subsidiaries currently have in place an
environmental audit program intended to enhance compliance with existing
federal, state, and local requirements regarding the handling of potentially
hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency (EPA) or the Massachusetts
Department of Environmental Protection for six sites at which hazardous waste
is alleged to have been disposed. Private parties have also contacted or
initiated legal proceedings against the Company regarding hazardous waste
cleanup. The Company is currently aware of other sites, and may in the
future become aware of additional sites, that it may be held responsible for
remediating.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. Where appropriate, the Company intends to seek recovery from
its insurers and from other PRPs, but it is uncertain whether and to what
extent such efforts would be successful. The Company believes that hazardous
waste liabilities for all sites of which it is aware will not be material to
its financial position.
Electric and Magnetic Fields (EMF)
In recent years, concerns have been raised about whether EMF, which
occur near transmission and distribution lines as well as near household
wiring and appliances, cause or contribute to adverse health effects.
Numerous studies on the effects of these fields, some of them sponsored by
electric utilities (including NEES companies), have been conducted and are
continuing. Some of the studies have suggested associations between certain
EMF and health effects, including various types of cancer, while other
<PAGE>
studies have not substantiated such associations. It is impossible to
predict the ultimate impact on the Company and the electric utility industry
if further investigations were to demonstrate that the present electricity
delivery system is contributing to increased risk of cancer or other health
problems.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In
any event, the Company believes that it currently has adequate insurance
coverage for personal injury claims.
Several state courts have recognized a cause of action for damage to
property values in transmission line condemnation cases based on the fear
that power lines cause cancer. It is difficult to predict what the impact
on the Company would be if this cause of action is recognized in the states
in which the Company operates and in contexts other than condemnation cases.
Legislation has been introduced in Massachusetts that, if passed, would
require state agencies to study existing EMF-related research and make
recommendations for further legislation.
Clean Air Requirements
Approximately 45 percent of the Company's electricity is produced at
eight older thermal generating units in Massachusetts. Six are fueled by
coal, one by oil, and one by oil and gas. The federal Clean Air Act requires
significant reduction in utility sulfur dioxide (SO2) and nitrogen oxides
(NOx) emissions that result from burning fossil fuels by the year 2000 to
reduce acid rain and ground-level ozone (smog).
The Company is reducing SO2 emissions under Phase 1 of the federal acid
rain program that became effective in 1995. The Company is also subject to
Massachusetts SO2 and NOx reduction regulations taking effect in 1995. The
SO2 and NOx reductions that are being made to meet 1995 Phase 1 requirements
have resulted in one-time operation and maintenance costs of $16 million and
capital costs of $88 million through December 31, 1994. Additional
expenditures in 1995 are expected to be less than $10 million and $30
million, respectively. Depending on fuel prices, the Company also expects
to incur up to $5 million annually in increased costs to purchase cleaner
fuels to meet SO2 emission reduction requirements.
All eight of the Company's thermal units will be subject to Phase 2 of
the federal and state acid rain regulations that become effective in 2000.
The Company believes that the SO2 controls already installed for the 1995
requirements will satisfy the Phase 2 acid rain regulations.
In connection with the federal ozone emission requirements, state
environmental agencies in ozone non-attainment areas are developing a second
phase of NOx reduction regulations that would have to be fully implemented
by the Company no later than 1999. While the exact costs are not known, the
Company estimates that the cost of implementing these regulations would not
jeopardize continued operation of its units.
The generation of electricity from fossil fuel also emits trace amounts
of certain hazardous air pollutants and fine particulates. An EPA study of
utility hazardous air pollutant emissions will be completed in 1995. The
study's conclusions could lead to new emission standards requiring costly
controls or fuel restrictions on the Company's plants. At this time, NEES
and its subsidiaries cannot estimate the impact the findings of this research
might have on the Company's operations.
<PAGE>
Purchased Power Contract Dispute
In October 1994, the Company was sued by Milford Power Limited
Partnership (MPLP), a venture of Enron Corporation and Jones Capital that
owns a 149 megawatt (MW) gas-fired power plant in Milford, Massachusetts.
The Company purchases 56 percent of the power output of the facility under
a long-term contract with MPLP. The suit alleges that the Company has
engaged in a scheme to cause MPLP and its power plant to fail and has
prevented MPLP from finding a long-term buyer for the remainder of the
facility's output. The complaint includes allegations that the Company has
violated the Federal Racketeer Influenced and Corrupt Organizations Act,
engaged in unfair or deceptive acts in trade or commerce, and breached
contracts. MPLP seeks compensatory damages in an unspecified amount, as well
as treble damages. The Company believes that the allegations of wrongdoing
are without merit. The Company has filed counterclaims and crossclaims
against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages
and termination of the purchased power contract.
MPLP also intervened in the Company's rate filing (see "Rate Activity"
section).
Competitive Conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of the Company's new generating capability has come from
independent generating sources and Hydro-Quebec.
Since 94 percent of the Company's revenues are from its affiliates that
serve retail customers, the Company is affected by increased competition that
these affiliates are facing in the retail market. Currently, retail
competition includes competition with alternative fuel suppliers (including
natural gas companies) for heating and cooling, competition with
customer-owned generation to displace purchases from electric utilities, and
direct competition among electric utilities to attract major new facilities
to their service territories. Electric utilities, including the NEES
companies, are under increasing pressure from large commercial and industrial
customers to discount rates or face the possibility that such customers might
relocate or seek alternate suppliers. Across the country, including the
states serviced by the NEES companies, there have been an increasing number
of proposals to allow retail customers to choose their electricity supplier,
with utilities required to deliver that electricity over their transmission
and distribution systems. In Massachusetts, the Massachusetts Division of
Energy Resources (DOER) proposed in January 1995 that the Massachusetts
Department of Public Utilities (MDPU) modify its regulations to allow retail
utility customers to choose a supplier and bid for access to the local
utility's transmission and distribution systems in situations where new
generating capacity is needed. The NEES companies have indicated their
support for the DOER proposal. The Company's Massachusetts retail affiliate
has announced plans to propose a limited bidding experiment consistent with
the DOER proposal. Also in Massachusetts, the MDPU initiated a proceeding
in February 1995 regarding electric industry regulation and structure. In
Rhode Island, the Rhode Island Public Utilities Commission has convened a
task force of utilities, commercial and industrial customers, regulators, and
other interested parties to prepare a report by May 1995 regarding
restructuring the industry. In New Hampshire, the New Hampshire Public
Utilities Commission is considering the proposal of a new company to sell
electricity at retail to large customers in New Hampshire.
<PAGE>
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning
and operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could
be substantial, have been referred to by the industry as stranded costs.
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have
taken the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the
FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a
utility may recover such stranded costs from a departing wholesale
requirements customer. On appeal, the United States Court of Appeals for the
District of Columbia Circuit has questioned whether allowing utilities to
recover stranded costs is anti-competitive and the Court remanded the case
back to the FERC for further proceedings and development of the competitive
issues.
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The wholesale business unit has responded to increased competition by
freezing base rates until at least 1997 (wholesale base rates were last
raised in March 1992), terminating certain purchased power and gas pipeline
contracts, shutting down uneconomic generating stations, and accelerating the
recovery of uneconomic assets and other deferred costs. In addition, the
Company's wholesale tariff requires its wholesale customers, including NEES's
retail subsidiaries, to provide seven years notice before they may terminate
the tariff.
The retail business unit's response to competition includes the
EnergyFIT program, which offers comprehensive value-added services for large
business customers, intensified business development efforts, including
economic development rates and service packages to encourage businesses to
locate in the retail companies' service territories, and development of new
pricing and service options for customers. Additionally, more than 80
percent of the NEES companies' currently eligible large commercial and
industrial customers have signed service extension discount contracts
providing for discounts in exchange for agreements requiring three to five
years notice before they may change electricity suppliers. As part of their
long-term planning process, the NEES companies are from time to time
evaluating other strategies, such as business combinations and other forms
of restructuring, to better respond to the changing competitive environment.
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These
<PAGE>
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable. In
addition, if, because of competition, utilities are unable to recover all of
their costs in rates, it may be necessary to write off those costs that are
not recoverable.
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $229 million for 1994
including $142 million related to the Manchester Street Station repowering
project discussed below. The funds necessary for utility plant expenditures
during the period were provided by net cash from operating activities, after
the payment of dividends, and proceeds of long-term and short-term debt
issues. Cash expenditures for utility plant for 1995 are estimated to be
$160 million (including $110 million related to the repowering of Manchester
Street Station). Internally generated funds are estimated to provide 90
percent of the Company's 1995 capital expenditure requirements for utility
plant. Cash expenditures for utility plant for 1995 are also expected to be
funded through the issuance of long-term and short-term debt.
In 1994, the Company issued $28 million of mortgage bonds at rates
ranging from 8.10 percent to 8.53 percent. The Company has issued $25
million of long-term debt to date in 1995 at interest rates ranging from 7.40
percent to 7.94 percent. In addition, the Company has refinanced $10 million
of variable rate mortgage bonds to date in 1995. The Company plans to issue
an additional $25 million of long-term debt in 1995.
The Company's major construction project is the repowering of Manchester
Street Station, a 140 MW electric generating station in Providence, Rhode
Island. Repowering will more than triple the power generation capacity of
Manchester Street Station and substantially increase the plant's thermal
efficiency. To facilitate financing this project, Narragansett sold a 90
percent interest in the existing station to the Company effective July 1,
1992. The total cost for the generating station, scheduled to be placed in
service in late 1995, is estimated to be approximately $520 million,
including AFDC. At December 31, 1994, $298 million, including AFDC, had been
spent on the generating station ($270 million by the Company). In addition,
related transmission improvements, which were principally the responsibility
of Narragansett, were placed in service in September 1994 at a cost of
approximately $60 million. Substantial commitments have been made relative
to future planned expenditures for this project.
At December 31, 1994, the Company had $146 million of short-term debt
outstanding including $129 million in the form of commercial paper borrowings
and $17 million of borrowings from affiliates. At December 31, 1994, the
Company had lines of credit and bond purchase facilities with banks totaling
$490 million which are available to provide liquidity support for commercial
paper borrowings and for $342 million of the Company's outstanding variable
rate mortgage bonds in tax-exempt commercial paper mode and for other
corporate purposes. There were no borrowings under these lines of credit at
December 31, 1994.
March 22, 1995
<PAGE>
NEW ENGLAND POWER COMPANY
Statements of Income
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating revenue, principally from
affiliates $1,540,757 $1,549,014 $1,530,875
Operating expenses:
Fuel for generation 260,540 273,347 288,868
Purchased electric energy 513,583 525,985 524,134
Other operation 196,610 186,087 162,134
Maintenance 110,528 103,261 114,210
Depreciation and amortization 137,979 131,932 127,733
Taxes, other than income taxes 54,400 51,931 50,828
Income taxes 96,596 93,997 79,799
---------- ---------- ----------
Total operating expenses 1,370,236 1,366,540 1,347,706
---------- ---------- ----------
Operating income 170,521 182,474 183,169
Other income:
Allowance for equity funds used
during construction 9,142 3,252 2,722
Equity in income of nuclear power
companies 4,816 5,646 6,252
Other income (expense) - net, including
related taxes (293) (566) 1,822
---------- ---------- ----------
Operating and other income 184,186 190,806 193,965
---------- ---------- ----------
Interest:
Interest on long-term debt 38,711 45,837 59,382
Other interest 1,956 5,427 2,071
Allowance for borrowed funds used
during construction - credit (5,854) (1,926) (1,639)
---------- ---------- ----------
Total interest 34,813 49,338 59,814
---------- ---------- ----------
Net income $ 149,373 $ 141,468 $ 134,151
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Retained earnings at beginning of year $ 346,153 $ 321,699 $ 293,113
Net income 149,373 141,468 134,151
Dividends declared on cumulative
preferred stock (3,440) (4,883) (5,591)
Dividends declared on common stock,
$18.50, $17.25, and $15.50 per share,
respectively (119,323) (111,261) (99,974)
Premium on redemption of preferred stock (870)
---------- ---------- ----------
Retained earnings at end of year $ 372,763 $ 346,153 $ 321,699
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEW ENGLAND POWER COMPANY
Balance Sheets
At December 31,
(In Thousands)
------------------------
1994 1993
---- ----
Assets
Utility plant, at original cost $2,524,544 $2,445,702
Less accumulated provisions for depreciation
and amortization 1,001,393 943,750
---------- ----------
1,523,151 1,501,952
Net investment in Seabrook 1 under rate settlement
(Note C-2) 38,283 103,344
Construction work in progress 314,777 165,860
---------- ----------
Net utility plant 1,876,211 1,771,156
---------- ----------
Investments:
Nuclear power companies, at equity (Note C-1) 46,349 46,342
Non-utility property and other investments 22,980 19,927
---------- ----------
Total investments 69,329 66,269
---------- ----------
Current assets:
Cash 377 610
Accounts receivable:
Affiliated companies 197,655 201,674
Others 69,532 58,581
Fuel, materials, and supplies, at average cost 73,361 55,955
Prepaid and other current assets 33,729 26,454
---------- ----------
Total current assets 374,654 343,274
---------- ----------
Accrued Yankee Atomic costs (Note C-1) 122,452 103,501
Deferred charges and other assets (Note A-6) 170,192 157,087
---------- ----------
$2,612,838 $2,441,287
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share, authorized
and outstanding 6,449,896 shares $ 128,998 $ 128,998
Premiums on capital stocks 86,829 86,829
Other paid-in capital 288,000 288,000
Retained earnings 372,763 346,153
---------- ----------
Total common equity 876,590 849,980
Cumulative preferred stock, par value $100 per
share (Note H) 60,516 61,028
Long-term debt 695,466 667,448
---------- ----------
Total capitalization 1,632,572 1,578,456
---------- ----------
Current liabilities:
Short-term debt (including $16,575,000 and
$8,325,000 to affiliates) 145,575 50,525
Accounts payable (including $69,089,000 and
$58,056,000 to affiliates) 179,761 144,100
Accrued liabilities:
Taxes 6,133 9,337
Interest 9,914 10,086
Other accrued expenses (Note A-7) 10,866 38,313
Dividends payable 14,512
---------- ----------
Total current liabilities 352,249 266,873
---------- ----------
Deferred federal and state income taxes 364,073 344,077
Unamortized investment tax credits 59,014 62,591
Accrued Yankee Atomic costs (Note C-1) 122,452 103,501
Other reserves and deferred credits 82,478 85,789
Commitments and contingencies (Note D)
---------- ----------
$2,612,838 $2,441,287
========== ==========
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating activities:
Net income $ 149,373 $ 141,468 $ 134,151
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 142,764 135,746 130,562
Deferred income taxes and
investment tax credits - net 23,051 20,665 6,378
Allowance for funds used during
construction (14,996) (5,178) (4,361)
Early retirement program 2,967
Decrease (increase) in accounts
receivable (6,932) 31,323 120
Decrease (increase) in fuel,
materials, and supplies (17,406) 16,902 (12,079)
Decrease (increase) in prepaid and
other current assets (7,275) (4,908) (15,938)
Increase (decrease) in accounts payable 35,661 (35,913) 26,437
Increase (decrease) in other current
liabilities (30,823) 25,205 (16,374)
Other, net (26,845) (46,559) (4,995)
--------- --------- ---------
Net cash provided by operating
activities $ 246,572 $ 281,718 $ 243,901
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $(229,015) $(156,614) $(115,093)
Other investing activities (3,053) (2,402)
Purchase of 90 percent interest in
Manchester Street Station from
affiliate ( 3,249)
--------- --------- ---------
Net cash used in investing
activities $(232,068) $(159,016) $(118,342)
--------- --------- ---------
Financing Activities:
Dividends paid on common stock $(133,835) $(120,936) $ (75,787)
Dividends paid on preferred stock (3,440) (4,883) (5,591)
Changes in short-term debt 95,050 32,200 18,325
Long-term debt - issues 28,000 224,000 260,000
Long-term debt - retirements (224,000) (337,000)
Preferred stock - retirements (512) (25,000)
Premium on reacquisition of long-term
debt (3,255) (12,294)
Premium on redemption of preferred
stock (870)
--------- --------- ---------
Net cash used in financing
activities $ (14,737) $(122,744) $(152,347)
--------- --------- ---------
Net decrease in cash and cash
equivalents $ (233) $ (42) $ (26,788)
Cash and cash equivalents at
beginning of year 610 652 27,440
--------- --------- ---------
Cash and cash equivalents at end
of year $ 377 $ 610 $ 652
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $ 32,510 $ 42,390 $ 65,210
--------- --------- ---------
Federal and state income taxes paid $ 83,455 $ 78,300 $ 65,484
--------- --------- ---------
Dividends received from investments
at equity $ 4,809 $ 5,103 $ 5,932
--------- --------- ---------
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements
Note A - Significant Accounting Policies
- ----------------------------------------
1. System of Accounts:
The accounts of the Company are maintained in accordance with the
Uniform System of Accounts prescribed by regulatory bodies having
jurisdiction.
2. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC
represents the composite interest and equity costs of capital funds used to
finance that portion of construction costs not eligible for inclusion in rate
base. In 1994, an average of $25 million of construction work in progress
was included in rate base, all of which was attributable to the Manchester
Street Station repowering project. AFDC is capitalized in "Utility plant"
with offsetting non-cash credits to "Other income" and "Interest". This
method is in accordance with an established rate-making practice under which
a utility is permitted a return on, and the recovery of, prudently incurred
capital costs through their ultimate inclusion in rate base and in the
provision for depreciation. The composite AFDC rates were 7.8 percent, 8.1
percent, and 9.7 percent in 1994, 1993, and 1992, respectively.
3. Depreciation and Amortization:
The depreciation and amortization expense included in the statements of
income is composed of the following:
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Depreciation $ 52,834 $ 53,128 $ 55,858
Nuclear decommissioning costs (Note A-4) 1,951 1,951 1,890
Amortization:
Investment in Seabrook 1 nuclear unit
under rate settlement (Note C-2) 65,061 58,437 52,443
Oil Conservation Adjustment 11,854 12,137 11,263
Property losses 6,279 6,279 6,279
-------- -------- --------
Total depreciation and amortization
expense $137,979 $131,932 $127,733
======== ======== ========
Depreciation is provided annually on a straight-line basis. The
provisions for depreciation (excluding nuclear decommissioning) as a
percentage of weighted average depreciable property were 2.4 percent in 1994,
2.5 percent in 1993, and 2.7 percent in 1992.
The Oil Conservation Adjustment is designed to recover expenditures for
coal conversion facilities at the Company's Salem Harbor Station by 1995.
At December 31, 1994, such unamortized coal conversion costs included in
utility plant were $4,467,000.
4. Nuclear Plant Decommissioning and Nuclear Fuel Disposal:
The Company is recovering its share of projected decommissioning costs
for the Millstone 3 nuclear generating unit (Millstone 3) and the Seabrook
1 nuclear generating unit (Seabrook 1) through depreciation expense. The
Company records decommissioning cost expense on its books consistent with its
rate recovery. ln addition, the Company is paying its portion of projected
decommissioning costs for all of the Yankee nuclear power companies
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
(Yankees) through purchased power expense. Such costs reflect estimates of
total decommissioning costs approved by the Federal Energy Regulatory
Commission (FERC).
Each of the operating nuclear units in which the Company has an
ownership interest has established decommissioning trust funds or escrow
funds into which payments are being made to meet the projected costs of
decommissioning its plant. If any of the units were shut down prior to the
end of their operating licenses, the funds collected for decommissioning to
that point would be insufficient. Listed below is information on each
nuclear plant in which the Company has an ownership interest. (See Note C-1
for a discussion of Yankee Atomic nuclear power station decommissioning.)
The Company's share of (in millions of dollars)
-----------------------------------------------
Estimated
Decommissioning
Ownership Cost Fund License
Unit Interest (in 1994 $) Balances** Expiration
- ---- --------- --------------- ---------- ----------
Connecticut Yankee 15% 53 22 2007
Maine Yankee *** 20% 66 22 2008
Vermont Yankee 20% 66 23 2012
Millstone 3 * 12% 53 11 2025
Seabrook 1 * 10% 36 4 2026
* Fund balances are included in "Non-utility property and other
investments" on the balance sheet and approximate market value.
** Certain additional amounts are anticipated to be available through tax
deductions.
*** A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally
liable for the shortfall.
In accordance with its recent rate agreement which became effective in
1995, the Company is allowed to defer for later recovery any increases in
decommissioning payments over the level included in rates until its next rate
filing becomes effective.
There is no assurance that decommissioning costs actually incurred by
the Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these
amounts. For example, decommissioning cost estimates assume the availability
of permanent repositories for both low-level and high-level nuclear waste
which do not currently exist.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government is responsible for the disposal of spent nuclear fuel. The
federal government requires the Company to pay a fee based on its share of
the net generation from the Millstone 3 and Seabrook 1 nuclear units. The
Company is recovering this fee through its fuel clause. Similar costs are
incurred by Connecticut Yankee, Maine Yankee, and Vermont Yankee. These
costs are billed to the Company and recovered from customers through the
Company's fuel clause.
5. Cash:
The Company classifies short-term investments with a remaining maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
Outstanding checks are therefore recorded in accounts payable until such time
as the banks present them for payment.
6. Deferred Charges and Other Assets:
The components of deferred charges and other assets are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Regulatory assets:
Deferred SFAS No. 109 costs (see Note B) $ 34,482 $ 41,114
Unamortized losses on reacquired debt 34,862 37,107
Purchased power termination costs 29,012 28,400
Deferred gas pipeline charges (see Note D-4) 37,562 13,187
Unamortized property losses 7,373 12,745
Deferred SFAS No. 106 costs (see Note E-2) 19,149 10,538
Other 2,542 8,928
-------- --------
164,982 152,019
Other deferred charges and other assets 5,210 5,068
-------- --------
$170,192 $157,087
======== ========
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable.
Approximately $100 million of the regulatory assets at December 31, 1994
listed above are expected to be recovered within 10 years, with the majority
of the remaining balance to be recovered within the following 20 years. The
only items for which the majority of the balance shown above will not be
recovered within the next 10 years are the deferred SFAS No. 109 costs and
the deferred gas pipeline charges.
7. Other Accrued Expenses:
The components of other accrued expenses are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Accrued wages and benefits $ 6,397 $10,619
Capital lease obligations due within one year 4,324 4,151
Accrued purchased power termination costs 21,900
Other 145 1,643
------- -------
$10,866 $38,313
======= =======
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes
- ---------------------
The Company and other subsidiaries participate with New England Electric
System (NEES) in filing consolidated federal income tax returns. The
Company's income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by the Internal
Revenue Service through 1991.
Total income taxes in the statements of income are as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Income taxes charged to operations $96,596 $93,997 $79,799
Income taxes charged (credited) to
"Other income" (994) 838 2,627
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Current income taxes $72,551 $74,171 $76,048
Deferred income taxes 26,628 23,270 7,706
Investment tax credits--net (3,577) (2,606) (1,328)
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
Investment tax credits are deferred and amortized over the estimated
lives of the property giving rise to the credits. Since the Tax Reform Act
of 1986 generally eliminated investment tax credits, the amounts shown above
principally reflect the amortization of investment tax credits generated in
prior years.
Total income taxes, as shown above, consist of federal and state
components as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Federal income taxes $78,274 $77,593 $67,830
State income taxes 17,328 17,242 14,596
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
With regulatory approval of the FERC, the Company has adopted
comprehensive interperiod tax allocation (normalization) for temporary
book/tax differences.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes - (continued)
- ---------------------
Total income taxes differ from the amounts computed by applying the
federal statutory tax rates to income before taxes. The reasons for the
differences are as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Computed tax at statutory rate $85,741 $82,706 $73,636
Increases (reductions) in tax resulting
from:
Amortization of investment tax credits (3,045) (2,511) (3,210)
State income taxes, net of federal income
tax benefit 11,263 10,770 9,634
All other differences 1,643 3,870 2,366
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
The Financial Accounting Standards Board established Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes"
which became effective in 1993. The application of this new standard did not
have a significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Deferred tax asset:
Plant related $ 96 $ 86
Investment tax credits 25 26
All other 29 39
----- -----
150 151
----- -----
Deferred tax liability:
Plant related (384) (373)
Equity AFDC (47) (48)
All other (83) (74)
----- -----
(514) (495)
----- -----
Net deferred tax liability $(364) $(344)
===== =====
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appeared on
the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily included deferred income taxes of $12 million related to utility
plant and $5 million related to losses on reacquired debt, partially offset
by deferred tax credits related to Seabrook 2 property losses of $5 million
and rate adjustment mechanisms of $6 million.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note C - Nuclear Power Investments
- ----------------------------------
1. Yankee Nuclear Power Companies:
The Company has minority interests in the four Yankees. These ownership
interests are accounted for on the equity method. The Company's share of the
expenses of the Yankee units is accounted for on the "Purchased electric
energy" line on the statements of income. A summary of combined results of
operations, assets and liabilities of the four Yankees is as follows:
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating revenue $ 631,940 $ 700,148 $ 684,775
========== ========== ==========
Net income $ 30,345 $ 30,061 $ 35,298
========== ========== ==========
Company's equity in net income $ 4,816 $ 5,646 $ 6,252
========== ========== ==========
Net plant 537,103 591,650 666,685
Other assets 1,458,186 1,286,923 1,221,905
Liabilities and debt (1,748,960) (1,633,139) (1,644,962)
---------- ---------- ----------
Net assets $ 246,329 $ 245,434 $ 243,628
========== ========== ==========
Company's equity in net assets $ 46,349 $ 46,342 $ 45,799
========== ========== ==========
Company's purchased electric energy $ 106,404 $ 118,362 $ 118,465
========== ========== ==========
At December 31, 1994, $12 million of undistributed earnings of the
nuclear power companies were included in the Company's retained earnings.
The Company has a 30 percent ownership interest in Yankee Atomic, which
owns a 185 megawatt (MW) nuclear generating station in Rowe, Massachusetts.
The station began commercial service in 1960. At December 31, 1994, the
Company's investment in Yankee Atomic was approximately $7 million. In
February 1992, the Yankee Atomic board of directors decided to permanently
cease power operation of, and in time decommission, the facility.
In March 1993, the FERC approved a settlement agreement that allows
Yankee Atomic to recover all but $3 million of its approximately $50 million
remaining investment in the plant over the period extending to July 2000,
when the plant's Nuclear Regulatory Commission (NRC) operating license would
have expired. Yankee Atomic recorded the $3 million before-tax write-down
in 1992. The settlement agreement also allows Yankee Atomic to earn a return
on the unrecovered balance during the recovery period and to recover other
costs, including an increased level of decommissioning costs, over this same
period. Decommissioning cost recovery increased from $6 million per year to
$27 million per year for the period 1993 to 1995. In the fourth quarter of
1994, Yankee announced a new decommissioning cost estimate that, subject to
approval by the FERC, would increase billings to the Company by an additional
$11 million per year through July 2000.
The Company has recorded an estimate of its entire future payment
obligations to Yankee Atomic as a liability on its balance sheet and an
offsetting regulatory asset reflecting its expected future rate recovery of
such costs. This liability and related regulatory asset amounted to
approximately $122 million each at December 31, 1994, and are included on
separate lines on the balance sheet.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note C - Nuclear Power Investments (continued)
- ----------------------------------
The Company has a 20 percent ownership interest in Maine Yankee which
owns an 880 MW nuclear generating station in Wiscasset, Maine. Since January
1995, the station has been shut down for refueling and inspection. On the
basis of preliminary results of testing and analysis performed during this
shutdown, Maine Yankee has detected substantially greater deterioration of
its steam generator tubes than had been previously found and is unable to
predict its effect on the future of the unit.
2. Jointly-Owned Nuclear Generating Units:
The Company is also a 12 percent and 10 percent owner, respectively, of
the Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 MW. The
Company's net investment in Millstone 3, included in "Net utility plant" is
approximately $400 million. The Company's rate recovery of its investment
in Seabrook 1 was resolved through two separate rate settlement agreements.
A portion of the Company's pre-1988 investment is being recovered in base
rates over a period of seven and one-half years ending in mid-1995. Under
the Company's rate agreement, that was recently approved by the FERC,
approximately $15 million of the $38 million in Seabrook 1 costs due to be
recovered in 1995 pursuant to a 1988 settlement agreement will be deferred
and recovered in 1996. This investment, net of amortization, is shown on a
separate line on the balance sheets. The Company's net investment in
Seabrook 1 since January 1, 1988, which amounts to approximately $43 million
at December 31, 1994, is included in "Net utility plant" on the balance sheet
and is being recovered over 37 years. The Company's share of the related
expenses for Millstone 3 and Seabrook 1 is included in the operating expenses
of the Company's income statements.
Note D - Commitments and Contingencies
- --------------------------------------
1. Oil and Gas Operations:
New England Energy Incorporated (NEEI), a subsidiary of NEES, is engaged
in domestic oil and gas exploration, development, and production. NEEI
operates under an intercompany pricing policy (Pricing Policy) with the
Company approved by the Securities and Exchange Commission under the Public
Utility Holding Company Act of 1935. The Pricing Policy requires the Company
to purchase all fuel meeting its specifications offered to it by NEEI.
Under the Pricing Policy, NEEI's oil and gas exploration program is
composed of prospects entered into through December 31, 1983 under a
rate-regulated program. NEEI has incurred operating losses since 1986, due
to precipitate declines in oil and gas prices, and expects to incur
substantial additional losses in the future. These losses are passed on to
the Company in the year after they are incurred by NEEI and, in turn, are
being recovered from customers through the Company's fuel clause. The
Company's ability to pass such losses on to its customers was favorably
resolved in the Company's 1988 FERC rate settlement. This settlement covered
all costs incurred by or resulting from commitments made by NEEI through
March 1, 1988.
In 1994, 1993, and 1992, the Company recorded accrued fuel expenses and
accrued revenues of $40 million, $46 million, and $55 million, respectively,
representing losses incurred by NEEI in each year. Under the settlement,
certain NEEI costs incurred subsequent to March 1, 1988 are subject to normal
regulatory review.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
2. Plant Expenditures:
The Company's utility plant expenditures are estimated to be $160
million in 1995. At December 31, 1994, substantial commitments had been made
relative to future planned expenditures.
3. Hydro-Quebec Interconnection:
The Company is a participant in both the Hydro-Quebec Phase I and Phase
II projects. The Company's participation percentage in both projects is
approximately 18 percent. The Hydro-Quebec Phase I and Phase II projects
were established to transmit power from Hydro-Quebec to New England. Three
affiliates of the Company were created to construct and operate transmission
facilities related to these projects. The participants, including the
Company, have entered into support agreements that end in 2020, to pay
monthly their proportionate share of the total cost of constructing, owning,
and operating the transmission facilities. The Company accounts for these
support agreements as capital leases and accordingly recorded approximately
$78 million in utility plant at December 31, 1994. Under the support
agreements, the Company has agreed, in conjunction with any Hydro-Quebec
Phase II project debt financing, to guarantee its share of project debt. At
December 31, 1994, the Company had guaranteed approximately $32 million.
4. Natural Gas Pipeline Capacity:
In connection with the Company's efforts to reduce sulfur dioxide
emissions and repower generating units, the Company has signed several
contracts for natural gas pipeline capacity and gas supply. These agreements
require minimum fixed payments. The Company's minimum net payments are
currently estimated to be approximately $65 million in 1995 and $70 million
per year during 1996 to 1999.
As part of a rate settlement, the Company is recovering 50 percent of
the fixed pipeline capacity payments through its current fuel clause and
deferring the recovery of the remaining 50 percent until the Manchester
Street repowering project is completed. The Company has deferred payments
of approximately $38 million as of December 31, 1994 (see Note A-6). The
Company has been using a portion of this capacity to sell natural gas.
Proceeds from the sale of natural gas and pipeline capacity of $55 million,
$21 million, and $3 million in 1994, 1993, and 1992, respectively, have been
passed to customers through the Company's fuel clause. These proceeds have
been included on the fuel for generation line in the Company's statements of
income as an offset to the related fuel expense.
5. Hazardous Waste:
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. The
NEES subsidiaries currently have in place an environmental audit program
intended to enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous products and
by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for six sites at which hazardous
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
waste is alleged to have been disposed. Private parties have also contacted
or initiated legal proceedings against the Company regarding hazardous waste
cleanup. The Company is currently aware of other sites, and may in the
future become aware of additional sites, that it may be held responsible for
remediating.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. Where appropriate, the Company intends to seek recovery from
its insurers and from other PRPs, but it is uncertain whether and to what
extent such efforts would be successful. The Company believes that hazardous
waste liabilities for all sites of which it is aware will not be material to
its financial position.
6. Nuclear Insurance:
The Price-Anderson Act limits the amount of liability claims that would
have to be paid in the event of a single incident at a nuclear plant to $8.9
billion (based upon 110 licensed reactors).
The maximum amount of commercially available insurance coverage to pay
such claims is only $200 million. The remaining $8.7 billion would be
provided by an assessment of up to $79.3 million per incident levied on each
of the nuclear units in the United States, subject to a maximum assessment
of $ 10 million per incident per nuclear unit in any year. The maximum
assessment, which was most recently calculated in 1993, is to be adjusted at
least every five years to reflect inflationary changes. The Company's
current interest in the Yankees (excluding Yankee Atomic), Millstone 3, and
Seabrook 1 would subject the Company to a $58.0 million maximum assessment
per incident. The Company's payment of any such assessment would be limited
to a maximum of $7.3 million per incident per year. As a result of the
permanent cessation of power operation of the Yankee Atomic plant, Yankee
Atomic has received from the NRC a partial exemption from obligations under
the Price-Anderson Act. However, Yankee Atomic must continue to maintain
$100 million of commercially available nuclear insurance coverage.
Each of the nuclear units in which the Company has an ownership interest
also carries nuclear insurance to cover the costs of property damage,
decontamination or premature decommissioning and workers' claims resulting
from a nuclear incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units covered by this
insurance occurring in a prior six year period exceed the accumulated funds
available. The Company's maximum potential exposure for these assessments,
either directly, or indirectly through purchased power payments to the
Yankees, is approximately $17 million per year.
7. Long-term Contracts for the Purchase of Electricity:
The Company purchases a portion of its electricity requirements pursuant
to long-term contracts with owners of various generating units. These
contracts expire in various years from 1995 to 2029.
Certain of these contracts require the Company to make minimum fixed
payments, even when the supplier is unable to deliver power, to cover the
Company's proportionate share of the capital and fixed operating costs of
these generating units. The majority of the payments under these contracts
are to the Yankees (excluding Yankee Atomic--see Note C-1) and Ocean State
Power, entities in which the Company or its affiliates hold ownership
interests.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
The fixed portion of payments under these contracts totaled $190 million
in 1994 and $220 million in 1993 and 1992. These contracts have minimum
fixed payment requirements of $215 million in 1995, $195 million in 1996,
$190 million in 1997 and 1998, $185 million in 1999, and approximately $2
billion thereafter.
The Company's other contracts, principally with non-utility generators,
require the Company to make payments only if power supply capacity and energy
are deliverable from such suppliers. The Company's payments under these
contracts amounted to $210 million in 1994 and 1993 and $200 million in 1992.
8. Purchased Power Contract Dispute:
In October 1994, the Company was sued by Milford Power Limited
Partnership (MPLP), a venture of Enron Corporation and Jones Capital that
owns a 149 MW gas-fired power plant in Milford, Massachusetts. The Company
purchases 56 percent of the power output of the facility under a long-term
contract with MPLP. The suit alleges that the Company has engaged in a
scheme to cause MPLP and its power plant to fail and has prevented MPLP from
finding a long-term buyer for the remainder of the facility's output. The
complaint includes allegations that the Company has violated the Federal
Racketeer Influenced and Corrupt Organizations Act, engaged in unfair or
deceptive acts in trade or commerce, and breached contracts. MPLP seeks
compensatory damages in an unspecified amount, as well as treble damages.
The Company believes that the allegations of wrongdoing are without merit.
The Company has filed counterclaims and crossclaims against MPLP, Enron
Corporation, and Jones Capital, seeking monetary damages and termination of
the purchased power contract.
MPLP also intervened in the Company's recent rate filing.
Note E - Employee Benefits
- --------------------------
1. Pension Plans:
The Company participates with other subsidiaries of NEES in
noncontributory defined-benefit plans covering substantially all employees
of the Company. The plans provide pension benefits based on the employee's
compensation during the five years before retirement. The Company's funding
policy is to contribute each year, the net periodic pension cost for that
year. However, the contribution for any year will not be less than the
minimum required contribution under federal law or greater than the maximum
tax deductible amount.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
Net pension cost for 1994, 1993, and 1992 included the following
components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Service cost--benefits earned during
the period $ 2,202 $ 1,953 $ 1,858
Plus (less):
Interest cost on projected benefit
obligation 6,403 6,070 5,558
Return on plan assets at expected
long-term rate (6,554) (5,850) (5,600)
Amortization 557 47 31
------- ------- -------
Net pension cost $ 2,608 $ 2,220 $ 1,847
======= ======= =======
Assumptions used to determine pension
cost:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future
compensation levels 4.35% 5.35% 6.70%
Expected long-term rate of return on
assets 8.75% 8.75% 9.00%
------- ------- -------
Actual return on plan assets $ 608 $ 8,949 $ 4,887
======= ======= =======
Service cost for 1993 does not reflect costs incurred in connection with
an early retirement program offered by the Company in that year (see Note
E-3).
The funded status of the plans cannot be presented separately for the
Company as the Company participates in the plans with other NEES
subsidiaries. The following table sets forth the funded status of the NEES
companies' plans at December 31:
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
Retirement Plans,
(In Millions)
---------------------------
1994 1993
---- ----
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
-------- --------- -------- ---------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $251 $308 $251 $333
Non-vested 8 9 20 6
---- ---- ---- ----
Total $259 $317 $271 $339
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of projected
benefit liability $303 $355 $310 $383
Unrecognized prior service costs (8) (4) (8) (6)
SFAS No. 87 transition liability not
yet recognized (amortized) - (1) - (1)
Net loss not yet recognized
(amortized) (13) (33) (11) (45)
Additional minimum liability
recognized - - - 8
---- ---- ---- ----
282 317 291 339
---- ---- ---- ----
Pension fund assets at fair value 293 323 302 318
SFAS No. 87 transition asset not
yet recognized (amortized) (13) - (14) -
---- ---- ---- ----
280 323 288 318
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $ 3 $ 21
==== ==== ==== ====
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed effective
January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected
long-term rate of return on assets used to calculate pension cost was not
changed from the level shown in the table above. The plans' funded status
at December 31, 1994 was calculated using these revised rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions and Postemployment
Benefits:
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement
Benefits Other Than Pensions" (PBOPs) went into effect. The Company provides
health care and life insurance coverage to eligible retired employees.
Eligibility is based on certain age and length of service requirements and
in some cases retirees must contribute to the cost of their coverage.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
The total cost of PBOPs for 1994 and 1993 included the following
components:
Year Ended December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Service cost--benefits earned during the period $1,628 $1,632
Plus (less):
Interest cost on the accumulated benefit
obligation 3,954 4,275
Return on plan assets at expected long-term
rate (1,111) (725)
Amortization 2,591 2,558
------ ------
Net postretirement benefit cost $7,062 $7,740
====== ======
Actual return on plan assets $ 54 $ 746
====== ======
The following table sets forth benefits earned and the plans' funded
status:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Accumulated postretirement benefit obligation:
Retirees $ 31 $ 34
Fully eligible active plan participants 3 1
Other active plan participants 17 22
---- ----
Total benefits earned 51 57
Unrecognized transition obligation (46) (49)
Net gain (loss) not yet recognized 6 (1)
---- ----
11 7
Plan assets at fair value 15 12
---- ----
Prepaid postretirement benefit costs recorded
on books $ 4 $ 5
==== ====
1995 1994 1993
---- ---- ----
Assumptions used to determine
postretirement benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return on
assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
The plans' funded status at December 31, 1994 and 1993 presented above
was calculated using the assumed rates in effect for 1995 and 1994,
respectively.
The health care cost trend rate assumption has a significant effect on
the amounts reported. Increasing the assumed rates by 1 percent in each year
would increase the accumulated postretirement benefit obligation as of
December 31, 1994 by approximately $8 million and the net periodic cost for
the year 1994 by approximately $1 million.
The Company funds the annual tax deductible contributions. Plan assets
are invested in equity and debt securities and cash equivalents.
Prior to 1993, the Company recorded the cost of PBOPs when paid which
amounted to approximately $1.7 million in 1992. The Company has deferred all
increased costs that have resulted from the adoption of SFAS No. 106 in 1993.
Pursuant to a recently approved rate agreement, recovery of PBOP costs on a
current basis and recovery of $19 million of previously deferred amounts over
a seven year period commenced January 1, 1995. Therefore adoption of this
new accounting standard did not have a significant impact on net income.
3. 1993 Early Retirement and Special Severance Programs:
In February 1993, the Company offered a voluntary early retirement
program to non-union employees who were at least 55 years old with 10 years
of service. This program was part of an organizational review with the goal
of streamlining operations and reducing the work force. The early retirement
offer was accepted by 43 employees. A special severance program was also
announced in February 1993 for employees affected by the organizational
review, but who were not eligible for, or did not accept, the early
retirement offer. The Company recorded a one-time charge to 1993 earnings
of approximately $6 million, after tax ($10 million, before tax), to reflect
the cost of the early retirement and special severance programs which
consisted principally of pension benefits. This total includes the Company's
portion of its affiliated service company's cost of these programs.
Note F - Short-term Borrowing Arrangements
- ------------------------------------------
At December 31, 1994, the Company had $146 million of short-term debt
outstanding including $129 million in the form of commercial paper borrowings
and $17 million of borrowings of borrowings from affiliates. At December 31,
1994, the Company had lines of credit and standby bond purchase facilities
with banks totaling $490 million which are available to provide liquidity
support for commercial paper borrowings and for $342 million of the Company's
outstanding variable rate mortgage bonds in tax-exempt commercial paper mode
(see Note I) and for other corporate purposes. There were no borrowings
under these lines of credit at December 31, 1994. Fees are paid on the lines
and facilities in lieu of compensating balances. The weighted average rate
on outstanding short-term borrowings was 6.0 percent at December 31, 1994.
Note G - Intercompany Lending Arrangement
- -----------------------------------------
NEES and certain subsidiaries, including the Company, with regulatory
approval, operate a money pool to more effectively utilize cash resources and
to reduce outside short-term borrowings. Short-term borrowing needs are met
first by available funds of the money pool participants. Borrowing companies
pay interest at a rate designed to approximate the cost of outside short-term
borrowings. Companies which invest in the pool share the interest earned on
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note G - Intercompany Lending Arrangement (continued)
- -----------------------------------------
a basis proportionate to their average monthly investment in the money pool.
Funds may be withdrawn from or repaid to the pool at any time without prior
notice.
Note H - Cumulative Preferred Stock
- -----------------------------------
A summary of cumulative preferred stock at December 31, 1994 and 1993
is as follows (in thousands of dollars except for share data):
Shares
Authorized
and Dividends Call
Outstanding Amount Declared Price
------------- ------------- ------------- ------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
$100 Par value--
6.00% Series 75,020 80,140 $ 7,502 $ 8,014 $ 458 $ 481 (a)
4.56% Series 100,000 100,000 10,000 10,000 456 456 $104.08
4.60% Series 80,140 80,140 8,014 8,014 368 368 101.00
4.64% Series 100,000 100,000 10,000 10,000 464 464 102.56
6.08% Series 100,000 100,000 10,000 10,000 608 608 102.34
7.24% Series 150,000 150,000 15,000 15,000 1,086 1,086 103.06
8.40% Series 840
8.68% Series 580
------- ------- ------- ------- ------ ------
Total 605,160 610,280 $60,516 $61,028 $3,440 $4,883
======= ======= ======= ======= ====== ======
(a) Noncallable.
The annual dividend requirement for total cumulative preferred stock was
$3,433,000 and $3,463,000 for 1994 and 1993, respectively.
During 1993, all of the Company's 8.68 percent Series and 8.40 percent
Series of cumulative preferred stock were redeemed. Total premiums of
$870,000 in connection with these redemptions were charged to retained
earnings in 1993. There are no mandatory redemption provisions on the
Company's cumulative preferred stock.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note I - Long-term Debt
- -----------------------
A summary of long-term debt is as follows:
At December 31, (In Thousands)
------------------------------
Series Rate % Maturity 1994 1993
- ------ ------ -------- ---- ----
General and Refunding Mortgage Bonds:
W (93-3) 5.12 February 2, 1996 $ 5,000 $ 5,000
W (93-8) 5.06 February 5, 1996 5,000 5,000
Y (94-3) 8.10 December 22, 1997 3,000
W (93-2) 6.17 February 2, 1998 4,300 4,300
W (93-4) 6.14 February 2, 1998 1,300 1,300
W (93-5) 6.17 February 3, 1998 5,000 5,000
W (93-7) 6.10 February 4, 1998 10,000 10,000
W (93-9) 6.04 February 4, 1998 29,400 29,400
Y (94-4) 8.28 December 21, 1999 10,000
W (93-6) 6.58 February 10, 2000 5,000 5,000
W (93-1) 7.00 February 3, 2003 25,000 25,000
Y (94-2) 8.33 November 8, 2004 10,000
K 7.25 October 15, 2015 38,500 38,500
L 7.80 April 1, 2016 29,850 29,850
X variable March 1, 2018 79,250 79,250
R variable November 1, 2020 107,850 107,850
S variable November 1, 2020 20,750 20,750
T variable November 1, 2020 28,000 28,000
U 8.00 August 1, 2022 170,000 170,000
V variable October 1, 2022 106,150 106,150
Y (94-1) 8.53 September 20, 2024 5,000
Unamortized discounts and premiums (2,884) (2,902)
-------- --------
Long-term debt $695,466 $667,448
======== ========
Substantially all of the properties and franchises of the Company are
subject to the lien of the mortgage indentures under which the general and
refunding mortgage bonds have been issued.
The Company will make cash payments of $10 million in 1996, $3 million
in 1997, $50 million in 1998, and $10 million in 1999 to retire maturing
mortgage bonds. There are no cash payments for maturing mortgage bonds
required in 1995.
The terms of $342 million of variable rate pollution control revenue
bonds collateralized by the Company's mortgage bonds require the Company to
reacquire the bonds under certain limited circumstances. At December 31,
1994, interest rates on the Company's variable rate bonds ranged from 3.30
percent to 5.60 percent.
Note J - Fair Value of Financial Instruments
- --------------------------------------------
At December 31, 1994, the Company's long-term debt had a carrying value
of $695,000,000 and had a fair value of approximately $685,000,000. To
estimate fair value, the carrying amount was used for debt that reprices
frequently at market rates because the carrying amount is a reasonable
estimate of fair value. For all other debt, the fair market value of the
Company's long-term debt was estimated based on the quoted prices for similar
issues or on the current rates offered to the Company for debt of the same
remaining maturity. The fair value of the Company's short-term debt equals
carrying value. The fair value of the Company's other investments equals
carrying value.
<PAGE>
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note K - Restrictions on Retained Earnings Available for
Dividends on Common Stock
- --------------------------------------------------------
Pursuant to the provisions of the Articles of Organization and the
By-Laws relating to the Dividend Series Preferred Stock, certain restrictions
on payment of dividends on common stock would come into effect if the "junior
stock equity" was, or by reason of payment of such dividends became, less
than 25 percent of "Total capitalization." However, the junior stock equity
at December 31, 1994 was 54 percent of total capitalization including
long-term debt due in one year and, accordingly, none of the Company's
retained earnings at December 31, 1994 were restricted as to dividends on
common stock under the foregoing provisions.
Under restrictions contained in the indentures relating to general and
refunding mortgage bonds, none of the Company's retained earnings at
December 31, 1994 were restricted as to dividends on common stock.
Note L - Supplementary Income Statement Information
- ---------------------------------------------------
Advertising expenses, expenditures for research and development, and
rents were not material and there were no royalties paid. Taxes, other than
income taxes, charged to operating expenses are set forth by classes as
follows:
Year Ended December 31,
(In Thousands)
-----------------------------
1994 1993 1992
---- ---- ----
Municipal property taxes $46,506 $44,124 $43,124
Federal and state payroll and other taxes 7,894 7,807 7,704
------- ------- -------
$54,400 $51,931 $50,828
======= ======= =======
New England Power Service Company, an affiliated service company
operating pursuant to the provisions of Section 13 of the Public Utility
Holding Company Act of 1935, furnished services to the Company at the cost
of such services. These costs amounted to $103,961,000, $94,366,000, and
$80,535,000, including capitalized construction costs of $22,396,000,
$20,335,000, and $22,759,000, for each of the years 1994, 1993, and 1992,
respectively.
<PAGE>
NEW ENGLAND POWER COMPANY
Operating Statistics (Unaudited)
<TABLE>
<CAPTION> Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Sources of Energy (Thousands of KWH)
Net generation - thermal 10,971,319 11,621,038 12,087,775 13,569,122 13,333,413
Net generation - conventional hydro 1,352,600 1,253,925 1,212,155 1,507,656 1,887,521
Generation - pumped storage 525,653 548,358 530,796 498,895 511,175
Net generation - nuclear 1,767,959 1,696,677 1,592,340 1,033,332 1,415,029
Nuclear entitlements 2,535,534 2,196,998 2,214,976 2,713,947 1,945,459
Purchased energy from
non-affiliates (B) 8,674,191 7,800,975 7,287,856 6,323,144 5,128,451
Energy for pumping (723,352) (750,784) (738,364) (685,659) (699,473)
---------- ---------- ---------- ---------- ----------
Total generated and purchased 25,103,904 24,367,187 24,187,534 24,960,437 23,521,575
Losses, company use, etc. (635,695) (548,228) (632,850) (589,001) (557,978)
---------- ---------- ---------- ---------- ----------
Total sources of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597
========== ========== ========== ========== ==========
Sales of Energy (Thousands of KWH)
Resale:
Affiliated companies 22,182,761 21,858,491 21,497,993 21,496,098 21,706,432
Less - generation by affiliated
Company (A) (5,781) (4,506) (83,753) (162,844) (583,413)
---------- ---------- ---------- ---------- ----------
Net sales to affiliated companies 22,176,980 21,853,985 21,414,240 21,333,254 21,123,019
Other utilities (B) 1,731,225 1,528,686 1,705,591 2,613,034 1,421,325
Municipals 551,866 426,525 415,659 411,171 404,352
---------- ---------- ---------- ---------- ----------
Total sales for resale 24,460,071 23,809,196 23,535,490 24,357,459 22,948,696
Ultimate customers 8,138 9,763 19,194 13,977 14,901
---------- ---------- ---------- ---------- ----------
Total sales of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597
========== ========== ========== ========== ==========
</TABLE>
<PAGE>
NEW ENGLAND POWER COMPANY
Operating Statistics (Unaudited) (continued)
<TABLE>
<CAPTION> Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenue (In Thousands)
Revenue from electric sales
Resale:
Affiliated companies $1,448,503 $1,459,619 $1,450,831 $1,384,222 $1,281,933
Less - G and T credits (A) (32,346) (26,001) (38,697) (50,961) (66,048)
---------- ---------- ---------- ---------- ----------
Net sales to affiliated companies 1,416,157 1,433,618 1,412,134 1,333,261 1,215,885
Other utilities (B) 56,306 52,695 55,156 76,162 66,971
Municipals 32,055 27,574 26,980 25,755 22,989
---------- ---------- ---------- ---------- ----------
Total revenue from sales for resale 1,504,518 1,513,887 1,494,270 1,435,178 1,305,845
Ultimate customers 606 752 1,399 1,097 1,033
---------- ---------- ---------- ---------- ----------
Total revenue from electric sales 1,505,124 1,514,639 1,495,669 1,436,275 1,306,878
Other operating revenue 35,633 34,375 35,206 36,016 35,196
---------- ---------- ---------- ---------- ----------
Total operating revenue $1,540,757 $1,549,014 $1,530,875 $1,472,291 $1,342,074
========== ========== ========== ========== ==========
Annual Maximum Demand
(Kw - one hour peak) 4,385,000 4,081,000 3,964,000 4,250,000 4,059,000
<FN>
(A) The generation and transmission facilities of affiliates are operated as an integrated part of the
Company's power supply and the affiliates receive generation and transmission (G and T) credits against
their power bills for costs of facilities so integrated.
(B) Includes transactions with the New England Power Pool.
</FN>
</TABLE>
<PAGE>
NEW ENGLAND POWER COMPANY
Selected Financial Information
Year Ended December 31, (In Millions)
-------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $ 942 $ 939 $ 907 $ 861 $ 809
Fuel cost recovery 563 576 589 575 498
Other 36 34 35 36 35
------ ------ ------ ------ ------
Total operating revenue $1,541 $1,549 $1,531 $1,472 $1,342
Net income $ 149 $ 141 $ 134 $ 135 $ 222*
Total assets $2,613 $2,441 $2,387 $2,277 $2,306
Capitalization:
Common equity $ 877 $ 850 $ 825 $ 797 $ 784
Cumulative preferred stock 61 61 86 86 86
Long-term debt 695 667 666 730 781
------ ------ ------ ------ ------
Total capitalization $1,633 $1,578 $1,577 $1,613 $1,651
Preferred dividends declared $ 3 $ 5 $ 6 $ 6 $ 6
Common dividends declared $ 119 $ 111 $ 100 $ 116 $ 105
* Includes the reversal of a portion of a 1988 write-down under a rate
settlement related to the Seabrook 1 nuclear power plant. See Note C-2.
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
- -------------- ------- ------- ------- -------
1994
Operating revenue $399,574 $356,488 $419,555 $365,140
Operating income $ 56,873 $ 32,192 $ 55,217 $ 26,239
Net income $ 49,189 $ 26,182 $ 49,818 $ 24,184
1993
Operating revenue $395,065 $361,131 $417,912 $374,906
Operating income $ 51,579 $ 35,864 $ 56,625 $ 38,406
Net income $ 40,090 $ 26,944 $ 47,072 $ 27,362
Per share data is not relevant because the Company's common stock is
wholly-owned by New England Electric System.
A copy of New England Power Company's Annual Report on Form 10-K to the
Securities and Exchange Commission, for the year ended December 31, 1994,
will be available on or about April 1, 1995, without charge, upon written
request to New England Power Company, Shareholder Services Department,
25 Research Drive, Westborough, Massachusetts 01582.
<PAGE>
POWER OF ATTORNEY
Each of the undersigned directors of New England Power Company
(the "Company"), individually as a director of the Company, hereby
constitutes and appoints John G. Cochrane, Thomas F. Killeen, and
Geraldine M. Zipser, individually, as attorney-in-fact to execute
on behalf of the undersigned the Company's annual report on Form
10-K for the year ended December 31, 1994, to be filed with the
Securities and Exchange Commission, and to execute any appropriate
amendment or amendments thereto as may be required by law.
Dated this 21st day of March, 1995.
s/ Joan T. Bok s/ John W. Newsham
Joan T. Bok John W. Newsham
s/ Frederic E. Greenman
Frederic E. Greenman John W. Rowe
s/ Alfred D. Houston s/ Jeffrey D. Tranen
Alfred D. Houston Jeffrey D. Tranen
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C> <C>
<FISCAL-YEAR-END> DEC-31-1994 DEC-31-1993
<PERIOD-END> DEC-31-1994 DEC-31-1993
<PERIOD-TYPE> 12-MOS 12-MOS
<BOOK-VALUE> PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,876,211 1,771,156
<OTHER-PROPERTY-AND-INVEST> 69,329 66,269
<TOTAL-CURRENT-ASSETS> 374,654 343,274
<TOTAL-DEFERRED-CHARGES> 292,644 <F1> 260,588 <F1>
<OTHER-ASSETS> 0 0
<TOTAL-ASSETS> 2,612,838 2,441,287
<COMMON> 128,998 128,998
<CAPITAL-SURPLUS-PAID-IN> 374,829 374,829
<RETAINED-EARNINGS> 372,763 346,153
<TOTAL-COMMON-STOCKHOLDERS-EQ> 876,590 849,980
0 0
60,516 61,028
<LONG-TERM-DEBT-NET> 695,466 667,448
<SHORT-TERM-NOTES> 145,575 <F2> 50,525 <F2>
<LONG-TERM-NOTES-PAYABLE> 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 0
<LONG-TERM-DEBT-CURRENT-PORT> 0 0
0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0
<LEASES-CURRENT> 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 834,691 812,306
<TOT-CAPITALIZATION-AND-LIAB> 2,612,838 2,441,287
<GROSS-OPERATING-REVENUE> 1,540,757 1,549,014
<INCOME-TAX-EXPENSE> 96,596 93,997
<OTHER-OPERATING-EXPENSES> 1,273,640 1,272,543
<TOTAL-OPERATING-EXPENSES> 1,370,236 1,366,540
<OPERATING-INCOME-LOSS> 170,521 182,474
<OTHER-INCOME-NET> 13,665 8,332
<INCOME-BEFORE-INTEREST-EXPEN> 184,186 190,806
<TOTAL-INTEREST-EXPENSE> 34,813 49,338
<NET-INCOME> 149,373 141,468
3,440 4,883
<EARNINGS-AVAILABLE-FOR-COMM> 145,933 135,715
<COMMON-STOCK-DIVIDENDS> 119,323 111,261
<TOTAL-INTEREST-ON-BONDS> 38,711 45,837
<CASH-FLOW-OPERATIONS> 246,572 281,718
<EPS-PRIMARY> 0 0
<EPS-DILUTED> 0 0
<FN>
<F1> Total deferred charges includes other assets and accrued Yankee Atomic costs.
<F2> Short-term notes includes commercial paper obligations and short-term debt to affiliates.
</FN>
<PAGE>
ANNUAL REPORT 1994
MASSACHUSETTS ELECTRIC COMPANY
A Subsidiary of
New England Electric System
[LOGO] Massachusetts Electric
A New England Electric System company
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of December 31, 1994)
Urville J. Beaumont Patricia McGovern
Treasurer and Director, Beaumont Of Counsel, Goulston and Storrs, P.C.,
and Campbell, P.A. (Attorneys), Boston, Massachusetts
Salem, New Hampshire
John F. Reilly
Joan T. Bok President and Chief Executive Officer
Chairman of the Board of New of Fred C. Church, Inc., Lowell,
England Electric System Massachusetts
Sally L. Collins John W. Rowe
Director--Workplace Health Services, President and Chief Executive Officer
Greenfield, Massachusetts of New England Electric System
John H. Dickson Richard P. Sergel
President and Chief Executive Chairman of the Company and Vice
Officer of the Company President of New England Electric
System
Charles B. Housen
Chairman and President, Erving Richard M. Shribman
Industries, Erving, Massachusetts Treasurer, Norick Realty Corporation,
Salem, Massachusetts
Dr. Kathryn A. McCarthy
Research Professor of Physics, Roslyn M. Watson
Tufts University, Medford, President, Watson Ventures, Boston,
Massachusetts Massachusetts
Officers
(As of December 31, 1994)
Richard P. Sergel Anthony C. Pini
Chairman of the Company and Vice President
Vice President of New England
Electric System Nancy H. Sala
Vice President
John H. Dickson
President and Chief Executive Dennis E. Snay
Officer Vice President
David L. Holt Michael E. Jesanis
Executive Vice President Treasurer of the Company and of New
England Electric System
John C. Amoroso
Vice President Robert King Wulff
Clerk of the Company and of certain
Peter H. Gibson affiliates
Vice President
Howard W. McDowell
Gregory A. Hale Controller and Assistant Treasurer of
Vice President the Company and Controller of certain
affiliates
Cheryl A. LaFleur
Vice President Frederic E. Greenman
Assistant Clerk and General Counsel of
Robert H. McLaren the Company and Senior Vice President,
Vice President General Counsel, and Secretary of New
England Electric System
Charles H. Moser
Vice President
Lydia M. Pastuszek
Vice President of the Company and
President of an affiliate
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock
State Street Bank and Trust Company, Boston, Massachusetts
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Massachusetts Electric Company is a wholly-owned subsidiary of New
England Electric System operating in Massachusetts. The Company's business
is the distribution and sale of electricity at retail. Electric service is
provided to approximately 940,000 customers in 149 cities and towns having
a population of about 2,160,000 (1990 Census). The Company's service area
covers approximately 43 percent of Massachusetts. The cities and towns
served by the Company include the highly diversified commercial and
industrial cities of Worcester, Lowell, and Quincy, the Interstate 495 high
technology belt, suburban communities, and many rural towns. The principal
industries served include computer manufacturing and related businesses,
electrical and industrial machinery, plastic goods, fabricated metals and
paper, and chemical products. In addition, a broad range of professional,
banking, medical, and educational institutions is served.
The properties of the Company consist principally of substations and
distribution lines interconnected with transmission and other facilities of
New England Power Company (NEP), an affiliate. The Company buys its electric
energy requirements from NEP under a contract which obligates NEP to furnish
such requirements at its standard resale rate. The Company participates
through NEP in the New England Power Pool, which provides for the
coordination of the planning and operation of the generation and transmission
facilities in New England, and the region-wide central dispatch of
generation.
Report of Independent Accountants
Massachusetts Electric Company, Westborough, Massachusetts:
We have audited the accompanying balance sheets of Massachusetts
Electric Company (the Company), a wholly-owned subsidiary of New England
Electric System, as of December 31, 1994 and 1993 and the related statements
of income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of the Company as
of December 31, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 27, 1995
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Financial Review
Overview
Net income for 1994 increased by $11 million compared with 1993. The
increase was primarily due to the inclusion in 1993 of one-time charges
associated with an early retirement program and the establishment of
additional gas waste reserves. In addition, the increase in 1994 earnings
reflects increased kilowatthour (KWH) sales. These factors were partially
offset by increased operation and maintenance expenses excluding the effect
of the one-time charges discussed above.
Net income decreased in 1993 by $11 million compared with 1992 primarily
due to the 1993 one-time charges mentioned above. The Company also
experienced an increase in purchased power expense due to increased
peak-demand billings. This decrease was partially offset by a $45.6 million
October 1992 rate increase, the effects of a 1993 rate agreement, and an
increase in KWH sales billed to ultimate customers.
Rate Activity
On March 15, 1995, the Company filed a request with the Massachusetts
Department of Public Utilities (MDPU) to increase its base rates by $62
million, effective October 1, 1995. As an alternative to this proposed
increase, the Company filed an incentive rate plan which would increase rates
by about $30 million effective October 1, 1995. Under the proposed incentive
rate plan, subsequent base rate adjustments could occur annually on May 1 and
would be based on a comparison of the Company's rates to rates of all
electric utilities in Massachusetts. The Company is the first electric
utility in the state to file under the MDPU's incentive ratemaking guidelines
issued in February 1995.
The Company also proposed a new discount program for large industrial
customers that are willing to make a minimum annual usage commitment for a
period of five years. The discounts would range from 5 percent to 12.5
percent of base rates depending on a customer's level of commitment. The
Company expects an MDPU decision on its filing in late September 1995.
In 1993, the MDPU approved a rate agreement filed by the Company, the
Massachusetts Attorney General, and two groups of large commercial and
industrial customers.
Under the agreement, effective December 1, 1993, the Company implemented
an 11 month general rate decrease of $26 million (annual basis). This rate
reduction continued in effect through October 31, 1994, at which time rates
increased to the previously approved levels. The Company also agreed not to
further increase its base rates before October 1, 1995. The agreement also
provided for the recognition of unbilled revenues for accounting purposes.
Unbilled revenues at September 30, 1993 of approximately $35 million were
amortized to income over 13 months commencing December 1993.
The agreement further provided for rate discounts for large commercial
and industrial customers who signed agreements to give a five-year notice to
the Company before they purchase power from another supplier or generate any
additional power themselves. The notice provision may be reduced from five
to three years under certain conditions. The aggregate amount of these
service extension discounts was $4 million during 1994 but will increase in
1995 to approximately $10 million per year under the terms of the agreement.
Customers representing approximately 88 percent of revenue from currently
eligible large commercial and industrial customers have signed these
agreements. The discounts are currently available to customers with average
monthly peak demands over 500 kilowatts. However, as part of its March 1995
rate filing with the MDPU, the Company proposed expanding this program to
customers with average monthly peak demands over 200 kilowatts. In addition,
commencing in 1995 the cost of these discounts is being passed on to New
England Power Company (NEP), the Company's affiliated wholesale power
supplier. This is the result of a NEP rate settlement that was approved by
<PAGE>
the Federal Energy Regulatory Commission (FERC) in early 1995. The 1993
agreement also resolved all rate recovery issues associated with
environmental remediation costs of Massachusetts manufactured gas waste sites
formerly owned by the Company and its affiliates, as well as certain other
environmental cleanup costs (see "Hazardous Waste" section). Lastly, the
agreement provided for the rate recovery of $8 million of certain storm
restoration and other costs previously charged to expense. The deferral of
these expenses increased 1993 fourth quarter earnings.
Effective October 1992, the MDPU authorized a $45.6 million annual
increase in rates for the Company.
Demand-Side Management
The Company regularly files its demand-side management (DSM) programs
with the MDPU and has received approval to recover DSM program expenditures
in rates on a current basis. These expenditures were $59 million, $47
million, and $44 million in 1994, 1993, and 1992, respectively. Since 1990,
the Company has been allowed to earn incentives based on the results of its
DSM programs. The Company must be able to demonstrate the electricity
savings produced by its DSM programs to the MDPU before incentives are
recorded. The Company recorded before-tax incentives of $7.1 million, $6.7
million, and $8.6 million in 1994, 1993, and 1992, respectively. The Company
has received regulatory orders that will give it the opportunity to continue
to earn incentives based on 1995 DSM program results.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
----------------------------------------
(In Millions) 1994 1993
- ------------- ---- ----
Sales growth $ 12 $10
General rate changes (22) 33
Unbilled revenues 21 11
Purchased power cost adjustment (PPCA) mechanism 7 (6)
DSM recovery 12 2
Fuel recovery (16) 6
---- ----
$ 14 $56
==== ====
KWH sales increased by 1.8 percent in 1994 compared with a 0.9 percent
increase in 1993. The increase in KWH sales in 1994 reflects an improved
economy.
The Company's rates contain a fuel clause and a PPCA provision. These
mechanisms are designed to allow the Company to pass on to its customers
changes in purchased energy costs resulting from rate increases or decreases
by NEP, the Company's affiliated wholesale power supplier.
General rate changes in 1994 reflect an 11 month rate decrease which
went into effect on December 1, 1993. The agreement also provided for the
recognition of unbilled revenues. For a further discussion, see the "Rate
Activity" section.
General rate changes in 1993 reflect general rate increases which went
into effect in October 1992.
<PAGE>
Operating Expenses
The following table summarizes the changes in total operating expenses
discussed below:
Increase (Decrease) in Operating Expenses
-----------------------------------------
(In Millions) 1994 1993
- ------------ ---- ----
Purchased electric energy:
Fuel costs $(16) $ 6
NEP refunds 4 1
Purchases and demand charges from NEP 4 9
Other operation and maintenance:
DSM 11 4
Other (17) 48
Depreciation 2 2
Taxes 13 (5)
---- ----
$ 1 $65
==== ====
The changes in fuel costs in 1994 and 1993 are the result of changes in
the amount of New England Energy Incorporated (NEEI) costs passed through by
NEP. NEEI is an affiliated company involved in oil and gas exploration and
development. The 1994 decrease also reflects a reduction in the fuel
component of NEP's purchased electric energy costs. In addition, the
increase in fuel costs in 1993 reflects increased KWH purchases.
The changes in other operation and maintenance expense in 1994 and 1993
are primarily the result of 1993 one-time charges of $26 million for the
establishment of additional gas waste reserves and $13 million associated
with an early retirement program, partially offset by the effects in the
fourth quarter of 1993 of the Company's rate agreement which allowed recovery
of amounts previously charged to expense (see "Rate Activity" section).
Other operation and maintenance expense in 1994 and 1993 also included
increased computer system development costs, increased postretirement benefit
expenses, and general increases in other areas. The increase in 1993 also
included increased uninsured claims and increased costs associated with the
adoption of a new accounting standard for postemployment benefits.
The increase in taxes in 1994 was primarily due to increased income and
increased municipal property tax accruals.
Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. New
England Electric System (NEES) subsidiaries currently have in place an
environmental audit program intended to enhance compliance with existing
federal, state, and local requirements regarding the handling of potentially
hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for 17 sites at which hazardous waste
is alleged to have been disposed. Private parties have also contacted or
initiated legal proceedings against the Company regarding hazardous waste
<PAGE>
cleanup. The most prevalent types of hazardous waste sites with which the
Company has been associated are manufactured gas locations. The Company is
aware of approximately 35 such locations in Massachusetts (including seven
of the 17 locations for which the Company is a PRP). The Company is
currently aware of other sites, and may in the future become aware of
additional sites, that it may be held responsible for remediating.
In 1993, the MDPU approved a rate agreement filed by the Company (see
"Rate Activity" section) that allows for remediation costs of former
manufactured gas sites and certain other hazardous waste sites located in
Massachusetts to be met from a non-rate recoverable interest-bearing fund of
$30 million established on the Company's books. Rate recoverable
contributions of $3 million, adjusted for inflation, are added to the fund
annually in accordance with the agreement. Any shortfalls in the fund would
be paid by the Company and be recovered through rates over seven years.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. Where appropriate, the Company intends to seek recovery from
its insurers and from other PRPs, but it is uncertain whether and to what
extent such efforts would be successful. At December 31, 1994, the Company
had total reserves for environmental response costs of $35 million and a
related regulatory asset of $9 million. The Company believes that hazardous
waste liabilities for all sites of which it is aware, and which are not
covered by a rate agreement, will not be material to its financial position.
Electric and Magnetic Fields (EMF)
In recent years, concerns have been raised about whether EMF, which
occur near transmission and distribution lines as well as near household
wiring and appliances, cause or contribute to adverse health effects.
Numerous studies on the effects of these fields, some of them sponsored by
electric utilities (including NEES companies), have been conducted and are
continuing. Some of the studies have suggested associations between certain
EMF and health effects, including various types of cancer, while other
studies have not substantiated such associations. It is impossible to
predict the ultimate impact on the Company and the electric utility industry
if further investigations were to demonstrate that the present electricity
delivery system is contributing to increased risk of cancer or other health
problems.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In
any event, the Company believes that it currently has adequate insurance
coverage for personal injury claims.
Several state courts have recognized a cause of action for damage to
property values in transmission line condemnation cases based on the fear
that power lines cause cancer. It is difficult to predict what the impact
on the Company would be if this cause of action is recognized in
Massachusetts and in contexts other than condemnation cases.
Legislation has been introduced in Massachusetts that, if passed, would
require state agencies to study existing EMF-related research and make
recommendations for further legislation.
Competitive Conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
<PAGE>
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of NEP's new generating capability has come from independent
generating sources and Hydro-Quebec.
Electric utilities are also facing increased competition in the retail
market. Currently, retail competition includes competition with alternative
fuel suppliers (including natural gas companies) for heating and cooling,
competition with customer-owned generation to displace purchases from
electric utilities, and direct competition among electric utilities to
attract major new facilities to their service territories. Electric
utilities, including the Company, are under increasing pressure from large
commercial and industrial customers to discount rates or face the possibility
that such customers might relocate or seek alternate suppliers. Across the
country, including Massachusetts and the other states in which the Company's
affiliates operate, there have been an increasing number of proposals to
allow retail customers to choose their electricity supplier, with utilities
required to deliver that electricity over their transmission and distribution
systems. The Massachusetts Division of Energy Resources (DOER) proposed in
January 1995 that the MDPU modify its regulations to allow retail utility
customers to choose a supplier and bid for access to the local utility's
transmission and distribution systems in situations where new generating
capacity is needed. The NEES companies have indicated their support for the
DOER proposal. The Company has announced plans to propose a limited bidding
experiment consistent with the DOER proposal. In addition, the MDPU
initiated a proceeding in February 1995 regarding electric industry
regulation and structure. In Rhode Island, the Rhode Island Public Utilities
Commission has convened a task force of utilities, commercial and industrial
customers, regulators, and other interested parties to prepare a report by
May 1995 regarding restructuring the industry. In New Hampshire, the New
Hampshire Public Utilities Commission is considering the proposal of a new
company to sell electricity at retail to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning
and operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could
be substantial, have been referred to by the industry as stranded costs.
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have
taken the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the
FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a
utility may recover such stranded costs from a departing wholesale
requirements customer. On appeal, the United States Court of Appeals for the
District of Columbia Circuit has questioned whether allowing utilities to
recover stranded costs is anti-competitive and the Court remanded the case
back to the FERC for further proceedings and development of the competitive
issues.
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
<PAGE>
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The retail business unit, which includes the Company, is responding to
competition through the development of an EnergyFIT program, which offers
comprehensive value-added services for large business customers, intensified
business development efforts, including economic development rates and
service packages to encourage businesses to locate in the Company's service
territory, and development of new pricing and service options for customers.
Additionally, customers representing approximately 88 percent of the
Company's currently eligible revenues have signed service extension discount
contracts providing for discounts in exchange for agreements requiring three
to five years notice before they may change electricity suppliers (see "Rate
Activity" section). As part of their long-term planning process, the NEES
companies are from time to time evaluating other strategies, such as business
combinations and other forms of restructuring, to better respond to the
changing competitive environment.
Since the largest component of the Company's costs is represented by the
cost of power purchased from NEP, its competitive position is affected by
NEP's ability to control costs. NEP is controlling costs and positioning
itself for increased competition by freezing base rates until at least 1997
(wholesale base rates were last raised in March 1992), terminating certain
purchased power and gas pipeline contracts, shutting down uneconomic
generating stations, and accelerating the recovery of uneconomic assets and
other deferred costs. In addition, NEP's wholesale tariff requires its
wholesale customers, including the Company and NEES's other retail
subsidiaries, to provide seven years notice before they may terminate the
tariff.
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable. In
addition, if, because of competition, utilities are unable to recover all of
their costs in rates, it may be necessary to write off those costs that are
not recoverable.
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $94 million in 1994. The
funds necessary for utility plant expenditures during 1994 were primarily
provided by net cash from operating activities, after the payment of
dividends, and long-term and short-term debt issues. Cash expenditures for
utility plant for 1995 are estimated to be approximately $105 million.
Internally generated funds are expected to meet approximately 65 percent of
capital expenditure requirements in 1995.
In 1994, the Company issued $36 million of first mortgage bonds, bearing
interest rates ranging from 7.05 percent to 8.85 percent. The Company has
<PAGE>
issued $48 million of long-term debt to date in 1995 at interest rates
ranging from 7.79 percent to 8.46 percent, and plans to issue an additional
$42 million of long-term debt later in 1995 to meet maturing long-term debt
obligations and fund capital expenditures.
At December 31, 1994, the Company had $82 million of short-term debt
outstanding including $73 million in the form of commercial paper borrowings
and $9 million of borrowings from affiliates. As of December 31, 1994, the
Company had lines of credit with banks totaling $90 million which are
available to provide liquidity support for commercial paper borrowings and
other corporate purposes. There were no borrowings under these lines of
credit at December 31, 1994.
March 20, 1995
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Statements of Income
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating revenue $1,482,070 $1,468,540 $1,412,948
---------- ---------- ----------
Operating expenses:
Purchased electric energy, principally
from New England Power Company,
an affiliate 1,074,402 1,081,918 1,065,189
Other operation 215,794 229,438 171,326
Maintenance 35,502 28,168 34,166
Depreciation 42,775 40,848 39,200
Taxes, other than income taxes 28,664 26,527 23,041
Income taxes 22,265 11,055 19,915
---------- ---------- ----------
Total operating expenses 1,419,402 1,417,954 1,352,837
---------- ---------- ----------
Operating income 62,668 50,586 60,111
Other income (expense) - net, including
related taxes (995) (64) 147
---------- ---------- ----------
Operating and other income 61,673 50,522 60,258
---------- ---------- ----------
Interest:
Interest on long-term debt 20,967 23,403 21,910
Other interest 6,366 3,638 3,657
Allowance for borrowed funds used during
construction - credit (386) (298) (214)
---------- ---------- ----------
Total interest 26,947 26,743 25,353
---------- ---------- ----------
Net income $ 34,726 $ 23,779 $ 34,905
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Retained earnings at beginning of year $ 135,276 $ 134,670 $ 125,976
Net income 34,726 23,779 34,905
Dividends declared on cumulative
preferred stock (3,114) (3,772) (3,428)
Dividends declared on common stock,
$12.50, $7.75, and $9.50 per share,
respectively (29,977) (18,585) (22,783)
Premium on redemption of preferred stock (816)
---------- ---------- ----------
Retained earnings at end of year $ 136,911 $ 135,276 $ 134,670
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Balance Sheets
At December 31,
(In Thousands)
------------------------
1994 1993
---- ----
Assets
Utility plant, at original cost $1,346,824 $1,279,194
Less accumulated provisions for depreciation 373,501 352,467
---------- ----------
973,323 926,727
Construction work in progress 22,672 18,558
---------- ----------
Net utility plant 995,995 945,285
---------- ----------
Current assets:
Cash 1,225 773
Accounts receivable:
From sales of electric energy 137,431 142,532
Other (including $6,609,000 and $3,517,000
from affiliates) 36,022 22,881
Less reserves for doubtful accounts 10,394 10,534
---------- ----------
163,059 154,879
Unbilled revenues (Note A-2) 42,800 43,400
Materials and supplies, at average cost 11,524 10,601
Prepaid and other current assets 21,583 19,990
---------- ----------
Total current assets 240,191 229,643
---------- ----------
Deferred charges and other assets (Note A-6) 59,536 57,376
---------- ----------
$1,295,722 $1,232,304
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $25 per share, authorized
and outstanding 2,398,111 shares $ 59,953 $ 59,953
Premiums on capital stocks 45,862 45,862
Other paid-in capital 141,310 141,310
Retained earnings 136,911 135,276
---------- ----------
Total common equity 384,036 382,401
Cumulative preferred stock (Note G) 50,000 50,000
Long-term debt 265,631 264,719
---------- ----------
Total capitalization 699,667 697,120
---------- ----------
Current liabilities:
Long-term debt due in one year 35,000
Short-term debt (including $8,650,000 and
$8,350,000 to affiliates) 81,820 37,925
Accounts payable (including $157,076,000 and
$160,852,000 to affiliates) 182,102 178,117
Accrued liabilities:
Taxes 906 1,133
Interest 7,945 6,784
Other accrued expenses (Note A-7) 27,132 69,823
Customer deposits 4,985 5,907
Dividends payable 13,968 5,575
---------- ----------
Total current liabilities 353,858 305,264
---------- ----------
Deferred federal and state income taxes 176,913 146,414
Unamortized investment tax credits 18,816 20,044
Other reserves and deferred credits 46,468 63,462
Commitments and contingencies (Note C)
---------- ----------
$1,295,722 $1,232,304
========== ==========
The accompanying notes are an integral part of these financial statements.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Statements of Cash Flows
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating activities:
Net income $ 34,726 $ 23,779 $ 34,905
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation 42,775 40,848 39,200
Deferred income taxes and
investment tax credits - net 28,909 3,126 15,252
Allowance for borrowed funds
used during construction (386) (298) (214)
Amortization of unbilled revenues (32,300) (2,700)
Early retirement program 7,665
Decrease (increase) in accounts
receivable, net and unbilled
revenues (7,580) (46,434) (20,266)
Decrease (increase) in materials and
supplies (923) (682) 221
Decrease (increase) in prepaid and
other current assets (1,593) 6,229 (24,806)
Increase (decrease) in accounts
payable 3,985 (9,112) 5,678
Increase (decrease) in other current
liabilities (10,379) 32,507 2,804
Other, net (12,982) 14,723 (1,692)
-------- -------- --------
Net cash provided by operating
activities $ 44,252 $ 69,651 $ 51,082
-------- -------- --------
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $(94,105) $(80,473) $(80,547)
Other investing activities (4,892)
-------- -------- --------
Net cash used in investing
activities $(98,997) $(80,473) $(80,547)
-------- -------- --------
Financing activities:
Capital contributions from parent $ 50,572 $ 10,000
Dividends paid on common stock $(21,584) (19,185) (18,586)
Dividends paid on preferred stock (3,114) (3,850) (3,428)
Changes in short-term debt 43,895 (7,775) 31,150
Long-term debt - issues 36,000 116,000 150,000
Long-term debt- retirements (117,000) (138,000)
Preferred stock - issues 35,000
Preferred stock - retirements (35,000)
Premium on reacquisition of long-term
debt (7,089) (2,197)
Premium on redemption of preferred
stock (816)
-------- -------- --------
Net cash provided by financing
activities $ 55,197 $ 10,857 $ 28,939
-------- -------- --------
Net increase (decrease) in cash and
cash equivalents $ 452 $ 35 $ (526)
Cash and cash equivalents at
beginning of year 773 738 1,264
-------- -------- --------
Cash and cash equivalents at end
of year $ 1,225 $ 773 $ 738
======== ======== ========
Supplementary Information:
Interest paid less amounts capitalized $ 24,562 $ 25,220 $ 23,928
-------- -------- --------
Federal and state income taxes paid $ 1,645 $ 12,090 $ 11,521
-------- -------- --------
The accompanying notes are an integral part of these financial statements.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements
Note A - Significant Accounting Policies
- ----------------------------------------
1. System of Accounts:
The accounts of the Company are maintained in accordance with the
Uniform System of Accounts prescribed by regulatory bodies having
jurisdiction.
2. Revenue:
Under a 1993 rate agreement, the Company began recognizing, for
accounting purposes, revenues for electricity delivered but not yet billed
(unbilled revenues). At December 31, 1993, the Company recorded on its
balance sheet approximately $43 million of unbilled revenues, of which $11
million was recognized in income in the fourth quarter of 1993 pursuant to
this rate agreement, with the balance recognized in 1994. Other accrued
revenues are recorded in accordance with rate adjustment mechanisms.
3. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC
represents an allowance for the cost of funds used to finance construction.
AFDC is capitalized in "Utility plant" with offsetting non-cash credits to
"Interest". This method is in accordance with an established rate-making
practice under which a utility is permitted a return on, and the recovery of,
prudently incurred capital costs through their ultimate inclusion in rate
base and in the provision for depreciation. The composite AFDC rates were
4.8 percent, 3.5 percent, and 3.9 percent, in 1994, 1993, and 1992,
respectively.
4. Depreciation:
Depreciation is provided annually on a straight-line basis. The
provisions for depreciation as a percentage of weighted average depreciable
property were 3.3 percent in 1994, 1993, and 1992.
5. Cash:
The Company classifies short-term investments with a remaining maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
Outstanding checks are therefore recorded in accounts payable until such time
as the banks present them for payment.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
6. Deferred Charges and Other Assets:
The components of deferred charges and other assets are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Regulatory assets:
Deferred SFAS No. 106 costs (see Note D-2) $16,079 $ 9,663
Environmental response costs (see Note C-2) 9,417 15,002
Unamortized losses on reacquired debt 8,848 9,843
Deferred SFAS No. 109 costs (see Note B) 8,445 8,083
Deferred storm costs 6,545 9,652
Other 1,764 2,212
------- -------
51,098 54,455
Other deferred charges and other assets:
Non-utility property 5,344 1,697
Other 3,094 1,224
------- -------
$59,536 $57,376
======= =======
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable.
Approximately $25 million of the regulatory assets at December 31, 1994
listed above are expected to be recovered within 10 years. All of the
remainder will be fully recovered within the next 20 years with the exception
of the Deferred SFAS No. 109 costs which will take longer to recover.
7. Other Accrued Expenses:
The components of other accrued expenses are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Rate adjustment mechanisms $15,087 $21,560
Deferred unbilled revenues 32,300
Accrued wages and benefits 9,969 13,094
Other 2,076 2,869
------- -------
$27,132 $69,823
======= =======
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes
- ---------------------
The Company and other subsidiaries participate with New England Electric
System (NEES) in filing consolidated federal income tax returns. The
Company's income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by the Internal
Revenue Service through 1991.
Total income taxes in the statements of income are as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Income taxes charged to operations $22,265 $11,055 $19,915
Income taxes charged (credited) to
"Other income" (642) 101 143
------- ------- -------
Total income taxes $21,623 $11,156 $20,058
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Current income taxes $(7,286) $ 8,030 $ 4,806
Deferred income taxes 30,137 4,354 16,480
Investment tax credits--net (1,228) (1,228) (1,228)
------- ------- -------
Total income taxes $21,623 $11,156 $20,058
======= ======= =======
Total income taxes, as shown above, consist of federal and state
components as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Federal income taxes $16,942 $ 7,808 $16,200
State income taxes 4,681 3,348 3,858
------- ------- -------
Total income taxes $21,623 $11,156 $20,058
======= ======= =======
Investment tax credits are deferred and amortized over the estimated
lives of the property giving rise to the credits. Since the Tax Reform Act
of 1986 generally eliminated investment tax credits, the amounts shown above
principally reflect the amortization of investment tax credits generated in
prior years.
Consistent with rate-making policies of the Massachusetts Department of
Public Utilities (MDPU), the Company has adopted comprehensive interperiod
tax allocation (normalization) for temporary book/tax differences.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes (continued)
- ---------------------
Total income taxes differ from the amounts computed by applying the
federal statutory tax rates to income before taxes. The reasons for the
differences are as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Computed tax at statutory rate $19,722 $12,227 $18,687
Increases (reductions) in tax resulting
from:
Amortization of investment tax credits (1,228) (1,228) (1,228)
Adjustment of prior year tax accruals (110) (2,528)
State income taxes, net of federal
income tax benefit 3,043 2,459 2,546
All other differences 196 226 53
------- ------- -------
Total income taxes $21,623 $11,156 $20,058
======= ======= =======
The Financial Accounting Standards Board established Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes"
which became effective in 1993. The application of this new standard did not
have a significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Deferred tax asset:
Plant related $ 8 $ 11
Investment tax credits 8 8
All other 45 59
----- -----
61 78
----- -----
Deferred tax liability:
Plant related (201) (191)
All other (37) (33)
----- -----
(238) (224)
----- -----
Net deferred tax liability $(177) $(146)
===== =====
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appeared on
the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily included deferred income taxes of $8 million related to utility
plant and $8 million in connection with postretirement benefits other than
pensions (PBOPs).
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note C - Commitments and Contingencies
- --------------------------------------
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be
approximately $105 million in 1995. At December 31, 1994, substantial
commitments had been made relative to future planned expenditures.
2. Hazardous Waste:
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. NEES
subsidiaries currently have in place an environmental audit program intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for 17 sites at which hazardous waste
is alleged to have been disposed. Private parties have also contacted or
initiated legal proceedings against the Company regarding hazardous waste
cleanup. The most prevalent types of hazardous waste sites with which the
Company has been associated are manufactured gas locations. The Company is
aware of approximately 35 such locations in Massachusetts (including seven
of the 17 locations for which the Company is a PRP). The Company is
currently aware of other sites, and may in the future become aware of
additional sites, that it may be held responsible for remediating.
In 1993, the MDPU approved a rate agreement filed by the Company that
allows for remediation costs of former manufactured gas sites and certain
other hazardous waste sites located in Massachusetts to be met from a
non-rate recoverable interest-bearing fund of $30 million established on the
Company's books composed of previously recorded reserves of $21 million plus
$9 million of additional reserves recorded in the fourth quarter of 1993.
Rate recoverable contributions of $3 million, adjusted for inflation, are
added to the fund annually in accordance with the agreement. Any shortfalls
in the fund would be paid by the Company and be recovered through rates over
seven years.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. Where appropriate, the Company intends to seek recovery from
its insurers and from other PRPs, but it is uncertain whether and to what
extent such efforts would be successful. At December 31, 1994, the Company
had total reserves for environmental response costs of $35 million and a
related regulatory asset of $9 million. The Company believes that hazardous
waste liabilities for all sites of which it is aware, and which are not
covered by a rate agreement, will not be material to its financial position.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note D - Employee Benefits
- --------------------------
1. Pension Plans:
Employee Benefits The Company participates with other subsidiaries of
NEES in noncontributory defined-benefit plans covering substantially all
employees of the Company. The plans provide pension benefits based on the
employee's compensation during the five years before retirement. The
Company's funding policy is to contribute each year, the net periodic pension
cost for that year. However, the contribution for any year will not be less
than the minimum required contribution under federal law or greater than the
maximum tax deductible amount.
Net pension cost for 1994, 1993, and 1992 included the following
components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Service cost--benefits earned during
the period $ 4,134 $ 3,348 $ 3,326
Plus (less):
Interest cost on projected benefit
obligation 16,435 16,905 15,886
Return on plan assets at expected
long-term rate (17,223) (16,683) $(16,441)
Amortization 1,060 (208) (260)
-------- -------- --------
Net pension cost $ 4,406 $ 3,362 $ 2,511
======== ======== ========
Assumptions used to determine pension
cost:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future
compensation levels 4.35% 5.35% 6.70%
Expected long-term rate of return on
assets 8.75% 8.75% 9.00%
-------- -------- --------
Actual return on plan assets $ 1,541 $ 25,785 $ 14,479
======== ======== ========
Service cost for 1993 does not reflect costs incurred in connection with
an early retirement program offered by the Company in that year (see Note
D-3).
The funded status of the plans cannot be presented separately for the
Company as the Company participates in the plans with other NEES
subsidiaries. The following table sets forth the funded status of the NEES
companies' plans at December 31:
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note D - Employee Benefits (continued)
- --------------------------
Retirement Plans,
(In Millions)
---------------------------
1994 1993
-------- --------
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
-------- --------- -------- ---------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $251 $308 $251 $333
Non-vested 8 9 20 6
---- ---- ---- ----
Total $259 $317 $271 $339
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of projected
benefit liability $303 $355 $310 $383
Unrecognized prior service costs (8) (4) (8) (6)
SFAS No. 87 transition liability not
yet recognized (amortized) - (1) - (1)
Net loss not yet recognized
(amortized) (13) (33) (11) (45)
Additional minimum liability
recognized - - - 8
---- ---- ---- ----
282 317 291 339
---- ---- ---- ----
Pension fund assets at fair value 293 323 302 318
SFAS No. 87 transition asset not
yet recognized (amortized) (13) - (14) -
---- ---- ---- ----
280 323 288 318
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $ 3 $ 21
==== ==== ==== ====
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed effective
January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected
long-term rate of return on assets used to calculate pension cost was not
changed from the level shown in the table above. The plans' funded status
at December 31, 1994 was calculated using these revised rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions and Postemployment
Benefits:
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement
Benefits Other Than Pensions" (PBOPs) went into effect. The Company provides
health care and life insurance coverage to eligible retired employees.
Eligibility is based on certain age and length of service requirements and
in some cases retirees must contribute to the cost of their coverage.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note D - Employee Benefits (continued)
- --------------------------
The total cost of PBOPs for 1994 and 1993 included the following
components:
Year Ended December 31,
(In Thousands)
-----------------------
1994 1993
---- ----
Service cost--benefits earned during the period $ 2,840 $ 2,613
Plus (less):
Interest cost on the accumulated benefit
obligation 11,050 12,007
Return on plan assets at expected long-term
rate (3,306) (2,095)
Amortization 7,287 7,302
------- -------
Net postretirement benefit cost $17,871 $19,827
======= =======
Actual return on plan assets $ 265 $ 2,125
======= =======
The following table sets forth benefits earned and the plans' funded
status:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Accumulated postretirement benefit obligation:
Retirees $ 92 $ 100
Fully eligible active plan participants 19 10
Other active plan participants 33 48
----- -----
Total benefits earned 144 158
Unrecognized transition obligation (131) (138)
Net gain (loss) not yet recognized 15 (3)
----- -----
28 17
Plan assets at fair value 44 35
----- -----
Prepaid postretirement benefit costs recorded
on books $ 16 $ 18
===== =====
1995 1994 1993
---- ---- ----
Assumptions used to determine
postretirement benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return on
assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note D - Employee Benefits (continued)
- --------------------------
The plans' funded status at December 31, 1994 and 1993 presented above
was calculated using the assumed rates in effect for 1995 and 1994,
respectively.
The health care cost trend rate assumption has a significant effect on
the amounts reported. Increasing the assumed rates by 1 percent in each year
would increase the accumulated postretirement benefit obligation as of
December 31, 1994 by approximately $22 million and the net periodic cost for
the year 1994 by approximately $2.5 million.
The Company funds the annual tax deductible contributions. Plan assets
are invested in equity and debt securities and cash equivalents.
Prior to 1993, the Company recorded the cost of PBOPs when paid. These
costs amounted to approximately $5.4 million in 1992. The Company has been
permitted by the MDPU to phase-in over a four year period that commenced in
October 1992, a level of rate recovery that is expected to equal or exceed
the amount of PBOP costs calculated in accordance with SFAS No. 106. At
December 31, 1994, the Company had deferred for later recovery, $16 million
representing that portion of increased PBOP costs not being recovered during
this phase-in period. Therefore, adoption of this new accounting standard
did not have a significant impact on net income.
In the fourth quarter of 1993, the Company recorded a $2 million charge
to earnings reflecting the cumulative effect of adopting a new accounting
standard for postemployment benefits.
3. 1993 Early Retirement and Special Severance Programs:
In February 1993, the Company offered a voluntary early retirement
program to non-union employees who were at least 55 years old with 10 years
of service. This program was part of an organizational review with the goal
of streamlining operations and reducing the work force. The early retirement
offer was accepted by 102 employees. A special severance program was also
announced in February 1993 for employees affected by the organizational
review, but who were not eligible for, or did not accept, the early
retirement offer. The Company recorded in the first quarter of 1993 a
one-time charge to earnings of approximately $8 million, after tax ($13
million, before tax), to reflect the cost of the early retirement and special
severance programs which consisted principally of pension benefits. This
total includes the Company's portion of its affiliated service company's cost
of these programs.
Note E - Short-term Borrowing Arrangements
- ------------------------------------------
At December 31, 1994, the Company had $82 million of short-term debt
outstanding including $73 million in the form of commercial paper borrowings
and $9 million of borrowings from affiliates. At December 31, 1994, the
Company had lines of credit with banks totaling $90 million which are
available to provide liquidity support for commercial paper borrowings and
other corporate purposes. There were no borrowings under these lines of
credit at December 31, 1994. Fees are paid in lieu of compensating balances
on most lines of credit. The weighted average rate on outstanding short-term
borrowings was 6.1 percent at December 31, 1994.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note F - Intercompany Lending Arrangement
- -----------------------------------------
NEES and certain subsidiaries, including the Company, with regulatory
approval, operate a money pool to more effectively utilize cash resources and
to reduce outside short-term borrowings. Short-term borrowing needs are met
first by available funds of the money pool participants. Borrowing companies
pay interest at a rate designed to approximate the cost of outside short-term
borrowings. Companies which invest in the pool share the interest earned on
a basis proportionate to their average monthly investment in the money pool.
Funds may be withdrawn from or repaid to the pool at any time without prior
notice.
Note G - Cumulative Preferred Stock
- -----------------------------------
A summary of cumulative preferred stock at December 31, 1994 and 1993
is as follows (in thousands of dollars except for share data):
Shares
Authorized
and Dividends Call
Outstanding Amount Declared Price
------------- ------------- ------------- ------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
$25 Par value--
6.84% Series 600,000 600,000 $15,000 $15,000 $1,026 $ 370 (a)
$100 Par value--
4.44% Series 75,000 75,000 7,500 7,500 333 333 $104.068
4.76% Series 75,000 75,000 7,500 7,500 357 357 103.730
6.99% Series 200,000 200,000 20,000 20,000 1,398 658 (b)
7.80% Series 878
7.84% Series 1,176
------- ------- ------- ------- ------ ------
Total 950,000 950,000 $50,000 $50,000 $3,114 $3,772
======= ======= ======= ======= ====== ======
(a) Callable on or after October 1, 1998 at $25.80.
(b) Callable on or after August 1, 2003 at $103.50.
The annual dividend requirement for total cumulative preferred stock was
$3,114,000 for 1994 and 1993.
During 1993, all of the Company's 7.80 percent Series and 7.84 percent
Series of cumulative preferred stock were redeemed. Total premiums of
$816,000 in connection with these redemptions were charged to retained
earnings. There are no mandatory redemption provisions on the Company's
cumulative preferred stock.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note H - Long-term Debt
- -----------------------
A summary of long-term debt is as follows:
At December 31, (In Thousands)
------------------------------
Series Rate % Maturity 1994 1993
- ------ ------ -------- ---- ----
First Mortgage Bonds:
R (92-2) 5.875 February 6, 1995 $ 10,000 $ 10,000
S (92-1) 5.860 June 26, 1995 15,000 15,000
S (92-8) 4.730 September 18, 1995 10,000 10,000
R (92-4) 7.230 June 3, 1997 10,000 10,000
R (92-5) 7.210 June 3, 1997 5,000 5,000
S (92-6) 6.120 August 15, 1997 12,000 12,000
S (92-7) 6.010 August 15, 1997 3,000 3,000
R (92-1) 7.240 December 30, 1998 10,000 10,000
S (92-3) 6.630 August 12, 1999 7,500 7,500
S (92-4) 6.600 August 12, 1999 7,500 7,500
S (92-2) 6.980 July 17, 2000 5,000 5,000
S (92-9) 6.310 September 15, 2000 10,000 10,000
R (92-6) 7.710 July 1, 2002 10,000 10,000
S (92-11) 7.250 October 28, 2002 5,000 5,000
S (92-12) 7.340 November 25, 2002 10,000 10,000
T (93-2) 7.090 January 27, 2003 20,000 20,000
T (93-5) 6.400 June 24, 2003 10,000 10,000
U (93-1) 6.240 November 17, 2003 5,000 5,000
U (94-6) 8.520 November 30, 2004 10,000
T (93-7) 6.660 June 23, 2008 5,000 5,000
T (93-8) 6.660 June 30, 2008 5,000 5,000
T (93-10) 6.110 September 8, 2008 10,000 10,000
T (93-11) 6.375 November 17, 2008 10,000 10,000
R (92-3) 8.550 February 7, 2022 5,000 5,000
S (92-5) 8.180 August 1, 2022 10,000 10,000
S (92-10) 8.400 October 26, 2022 5,000 5,000
T (93-1) 8.150 January 20, 2023 10,000 10,000
T (93-3) 7.980 January 27, 2023 10,000 10,000
T (93-4) 7.690 February 24, 2023 10,000 10,000
T (93-6) 7.500 June 23, 2023 3,000 3,000
T (93-9) 7.500 June 29, 2023 7,000 7,000
U (93-2) 7.200 November 15, 2023 10,000 10,000
U (93-3) 7.150 November 24, 2023 1,000 1,000
U (94-1) 7.050 February 2, 2024 10,000
U (94-2) 8.080 May 2, 2024 5,000
U (94-3) 8.030 June 14, 2024 5,000
U (94-4) 8.160 August 9, 2024 5,000
U (94-5) 8.850 November 7, 2024 1,000
Unamortized discounts and premiums (1,369) (1,281)
-------- --------
Total long-term debt 300,631 264,719
======== ========
Long-term debt due within year (35,000)
-------- --------
$265,631 $264,719
======== ========
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Notes to Financial Statements (continued)
Note H - Long-term Debt (continued)
- -----------------------
Substantially all of the properties and franchises of the Company are
subject to the lien of mortgage indentures under which the first mortgage
bonds have been issued.
The Company will make cash payments of $35,000,000 in 1995, $30,000,000
in 1997, $10,000,000 in 1998, and $15,000,000 in 1999 to retire maturing
mortgage bonds. There are no cash payments required in 1996.
Note I - Fair Value of Financial Instruments
- --------------------------------------------
At December 31, 1994, the Company's long-term debt, including long-term
debt due within one year, had a carrying value of approximately $301,000,000
and had a fair value of approximately $280,000,000. The fair market value
of the Company's long-term debt was estimated based on the quoted prices for
similar issues or on the current rates offered to the Company for debt of the
same remaining maturity. The fair value of the Company's short-term debt
equals carrying value.
Note J - Restrictions on Retained Earning Available for
Dividends on Common Stock
- -------------------------------------------------------
As long as any preferred stock is outstanding, certain restrictions on
payment of dividends on common stock would come into effect if the "junior
stock equity" was, or by reason of payment of such dividends became, less
than 25 percent of "total capitalization". However, the junior stock equity
at December 31, 1994 was 52 percent of total capitalization, including
long-term debt due in one year, and, accordingly, none of the Company's
retained earnings at December 31, 1994 were restricted as to dividends on
common stock under the foregoing restrictions.
Under restrictions contained in the indentures relating to first
mortgage bonds, $30,113,000 of the Company's retained earnings at December
31, 1994 were restricted as to dividends on common stock.
Note K - Supplementary Income Statement Information
- ---------------------------------------------------
Advertising expenses, expenditures for research and development, and
rents were not material and there were no royalties paid. Taxes, other than
income taxes, charged to operating expenses are set forth by classes as
follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Municipal property taxes $21,186 $19,620 $16,525
Federal and state payroll and other taxes 7,478 6,907 6,516
------- ------- -------
$28,664 $26,527 $23,041
======= ======= =======
New England Power Service Company, an affiliated service company
operating pursuant to the provisions of Section 13 of the Public Utility
Holding Company Act of 1935, furnished services to the Company at the cost
of such services. These costs amounted to $71,107,000, $61,515,000, and
$47,360,000, including capitalized construction costs of $8,977,000,
$9,038,000, and $8,306,000, for each of the years 1994, 1993, and 1992,
respectively.
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Operating Statistics (Unaudited)
<TABLE>
<CAPTION> Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Sources of Energy (Thousands of KWH)
Purchased energy:
From New England Power Company,
an affiliate 16,455,774 16,179,204 16,005,087 15,971,746 16,206,581
From others 3,364 12,676 13,916 12,865 13,180
---------- ---------- ---------- ---------- ----------
Total purchased 16,459,138 16,191,880 16,019,003 15,984,611 16,219,761
Losses, company use, etc. (733,804) (740,390) (711,157) (730,694) (699,383)
---------- ---------- ---------- ---------- ----------
Total sources of energy 15,725,334 15,451,490 15,307,846 15,253,917 15,520,378
========== ========== ========== ========== ==========
Sales of Energy (Thousands of KWH)
Residential 5,798,806 5,694,539 5,645,350 5,568,452 5,629,825
Commercial 5,936,170 5,743,924 5,645,867 5,585,604 5,648,759
Industrial 3,885,391 3,850,075 3,907,040 3,979,418 4,113,647
Other 95,382 99,991 105,842 113,444 120,142
---------- ---------- ---------- ---------- ----------
Total sales to ultimate customers 15,715,749 15,388,529 15,304,099 15,246,918 15,512,373
Sales for resale 9,585 62,961 3,747 6,999 8,005
---------- ---------- ---------- ---------- ----------
Total sales of energy 15,725,334 15,451,490 15,307,846 15,253,917 15,520,378
========== ========== ========== ========== ==========
Maximum Demand (Kw - one hour peak) 3,016,000 2,819,000 2,791,000 2,888,000 2,761,000
Average Annual Use per Residential
Customer (KWH) 6,948 6,888 6,886 6,832 6,926
Number of Customers at December 31
Residential 839,443 831,223 824,072 817,270 814,558
Commercial 95,430 93,414 92,281 81,355 85,597
Industrial 4,551 4,637 4,624 4,650 4,667
Other 880 906 952 986 910
---------- ---------- ---------- ---------- ----------
Total ultimate customers 940,304 930,180 921,929 904,261 905,732
Other (for resale) 178 278 22 21 22
---------- ---------- ---------- ---------- ----------
Total customers 940,482 930,458 921,951 904,282 905,754
========== ========== ========== ========== ==========
</TABLE>
<PAGE>
NEW ENGLAND POWER COMPANY
Operating Statistics (Unaudited) (continued)
<TABLE>
<CAPTION> Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenue (In Thousands)
Residential $ 589,447 $ 590,106 $ 549,884 $ 521,140 $ 475,004
Commercial 523,806 515,874 510,638 490,078 442,478
Industrial 301,144 314,132 319,905 318,502 294,037
Other 17,185 17,343 17,489 18,304 17,873
---------- ---------- ---------- ---------- ----------
Total revenue from ultimate customers 1,431,582 1,437,455 1,397,916 1,348,024 1,229,392
Unbilled revenues 31,700 11,100
Sales for resale 935 5,401 278 518 517
---------- ---------- ---------- ---------- ----------
Total revenue from electric sales 1,464,217 1,453,956 1,398,194 1,348,542 1,229,909
Other operating revenue 17,853 14,584 14,754 15,346 13,036
---------- ---------- ---------- ---------- ----------
Total operating revenue $1,482,070 $1,468,540 $1,412,948 $1,363,888 $1,242,945
========== ========== ========== ========== ==========
</TABLE>
<PAGE>
MASSACHUSETTS ELECTRIC COMPANY
Selected Financial Information
Year Ended December 31, (In Millions)
-------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $1,088 $1,062 $1,012 $ 984 $ 898
Fuel cost recovery 376 392 386 366 332
Other 18 15 15 15 13
------ ------ ------ ------ ------
Total operating revenue $1,482 $1,469 $1,413 $1,364 $1,243
Net income $ 35 $ 24 $ 35 $ 25 $ 35
Total assets $1,296 $1,232 $1,015 $1,017 $1,014
Capitalization:
Common equity $ 384 $ 382 $ 331 $ 313 $ 296
Cumulative preferred stock 50 50 50 50 50
Long-term debt 266 265 266 194 254
------ ------ ------ ------ ------
Total capitalization $ 700 $ 697 $ 647 $ 557 $ 600
Preferred dividends declared $ 3 $ 4 $ 3 $ 3 $ 3
Common dividends declared $ 30 $ 19 $ 23 $ 5 $ 16
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter*
- -------------- ------- ------- ------- --------
1994
Operating revenue $381,712 $339,886 $376,582 $383,890
Operating income $ 17,124 $ 15,054 $ 10,120 $ 20,370
Net income $ 9,572 $ 8,215 $ 1,431 $ 15,508
1993
Operating revenue $378,441 $340,293 $376,137 $373,669
Operating income $ 13,831 $ 2,573 $ 7,988 $ 26,194
Net income (loss) $ 6,060 $ (4,144) $ 2,204 $ 19,659
Per share data is not relevant because the Company's common stock is
wholly-owned by New England Electric System.
* See Note A-2 for discussion of significant item that affected fourth
quarter 1993 net income.
A copy of Massachusetts Electric Company's Annual Report on Form 10-K
to the Securities and Exchange Commission, for the year ended December 31,
1994, will be available on or about April 1, 1995, without charge, upon
written request to Massachusetts Electric Company, Shareholder Services
Department, 25 Research Drive, Westborough, Massachusetts 01582.
<PAGE>
POWER OF ATTORNEY
Each of the undersigned directors of Massachusetts Electric
Company (the "Company"), individually as a director of the Company,
hereby constitutes and appoints John G. Cochrane, Thomas F.
Killeen, and Geraldine M. Zipser, individually, as attorney-in-fact
to execute on behalf of the undersigned the Company's annual report
on Form 10-K for the year ended December 31, 1994, to be filed with
the Securities and Exchange Commission, and to execute any
appropriate amendment or amendments thereto as may be required by
law.
Dated this 15th day of March, 1995.
s/ Urville J. Beaumont s/ John F. Reilly
Urville J. Beaumont John F. Reilly
s/ Joan T. Bok s/ John W. Rowe
Joan T. Bok John W. Rowe
s/ Sally L. Collins s/ Richard P. Sergel
Sally L. Collins Richard P. Sergel
s/ John H. Dickson s/ Richard M. Shribman
John H. Dickson Richard M. Shribman
s/ Roslyn M. Watson
Charles B. Housen Roslyn M. Watson
s/ Patricia McGovern
Patricia McGovern
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C> <C>
<FISCAL-YEAR-END> DEC-31-1994 DEC-31-1993
<PERIOD-END> DEC-31-1994 DEC-31-1993
<PERIOD-TYPE> 12-MOS 12-MOS
<BOOK-VALUE> PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 995,995 945,285
<OTHER-PROPERTY-AND-INVEST> 0 0
<TOTAL-CURRENT-ASSETS> 240,191 229,643
<TOTAL-DEFERRED-CHARGES> 59,536 <F1> 57,376 <F1>
<OTHER-ASSETS> 0 0
<TOTAL-ASSETS> 1,295,722 1,232,304
<COMMON> 59,953 59,953
<CAPITAL-SURPLUS-PAID-IN> 187,172 187,172
<RETAINED-EARNINGS> 136,911 135,276
<TOTAL-COMMON-STOCKHOLDERS-EQ> 384,036 382,401
0 0
50,000 50,000
<LONG-TERM-DEBT-NET> 265,631 264,719
<SHORT-TERM-NOTES> 81,820 <F2> 37,925 <F2>
<LONG-TERM-NOTES-PAYABLE> 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 0
<LONG-TERM-DEBT-CURRENT-PORT> 35,000 0
0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0
<LEASES-CURRENT> 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 479,235 497,259
<TOT-CAPITALIZATION-AND-LIAB> 1,295,722 1,232,304
<GROSS-OPERATING-REVENUE> 1,482,070 1,468,540
<INCOME-TAX-EXPENSE> 22,265 11,055
<OTHER-OPERATING-EXPENSES> 1,397,137 1,406,899
<TOTAL-OPERATING-EXPENSES> 1,419,402 1,417,954
<OPERATING-INCOME-LOSS> 62,668 50,586
<OTHER-INCOME-NET> (995) (64)
<INCOME-BEFORE-INTEREST-EXPEN> 61,673 50,522
<TOTAL-INTEREST-EXPENSE> 26,947 26,743
<NET-INCOME> 34,726 23,779
3,114 3,772
<EARNINGS-AVAILABLE-FOR-COMM> 31,612 19,191
<COMMON-STOCK-DIVIDENDS> 29,977 18,585
<TOTAL-INTEREST-ON-BONDS> 20,967 23,403
<CASH-FLOW-OPERATIONS> 44,252 69,651
<EPS-PRIMARY> 0 0
<EPS-DILUTED> 0 0
<FN>
<F1> Total deferred charges includes other assets.
<F2> Short-term notes includes commercial paper obligations and short-term debt to affiliates.
</FN>
<PAGE>
Annual Report 1994
The Narragansett Electric Company
A Subsidiary of
New England Electric System
(Logo) Narragansett Electric
A New England Electric System company
<PAGE>
The Narragansett Electric Company
280 Melrose Street
Providence, Rhode Island 02901
Directors
(As of December 31, 1994)
Joan T. Bok John W. Rowe
Chairman of the Board of New England President and Chief Executive
Electric System Officer of New England Electric
System
Stephen A. Cardi
Treasurer, Cardi Corporation Richard P. Sergel
(Construction), Warwick, Rhode Island Chairman of the Company and Vice
President of New England Electric
Frances H. Gammell System
Treasurer and Secretary, Original
Bradford Soap Works, Inc., West Warwick, William E. Trueheart
Rhode Island President of Bryant College,
Smithfield, Rhode Island
Joseph J. Kirby
President, Washington Trust Bancorp, John A. Wilson, Jr.
Inc., Westerly, Rhode Island Consultant to and former President of
Wanskuck Company (Cable reel
Robert L. McCabe manufacturer), Providence, Rhode
President and Chief Executive Officer Island and Consultant to Hinkley,
of the Company Allen, Tobin and Silverstein
Officers
(As of December 31, 1994)
Richard P. Sergel James V. Mahoney
Chairman of the Company and Vice Vice President
President of New England Electric
System Richard Nadeau
Vice President
Robert L. McCabe
President and Chief Executive Officer Michael F. Ryan
Vice President
William Watkins, Jr.
Executive Vice President Thomas G. Robinson
Secretary
Francis X. Beirne
Vice President John G. Cochrane
Assistant Treasurer of the Company
Richard W. Frost and of an affiliate
Vice President
David J. Saggau
Alfred D. Houston Assistant Secretary
Vice President and Treasurer of the
Company and Executive Vice President Howard W. McDowell
and Chief Financial Officer of New Controller of the Company and of
England Electric System certain affiliates
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock
Fleet National Bank, Providence, Rhode Island
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
<PAGE>
The Narragansett Electric Company
The Narragansett Electric Company is a wholly-owned subsidiary of New
England Electric System (NEES) operating in Rhode Island. The Company's
business is the distribution and sale of electricity at retail. Electric
service is provided to approximately 324,000 customers in 27 cities and towns
having a population of approximately 725,000 (1990 Census). The Company's
service area, which includes urban, suburban, and rural areas, covers about
839 square miles or 80 percent of Rhode Island, and includes the cities of
Providence, East Providence, Cranston, and Warwick. The diversified economy
produces fabricated metal products, electrical and industrial machinery,
transportation equipment, textiles, jewelry, silverware, and chemical
products. In addition, a broad range of professional, banking, medical, and
educational institutions is served.
The properties of the Company include an integrated system of
transmission and distribution lines and substations. In addition, the
Company owns a 10 percent share of a steam-electric generating station which
is in the process of being repowered. The repowering will more than triple
the power generating capacity of the station to 489 megawatts. The entire
output of this plant is made available to New England Power Company (NEP),
an affiliate, as part of the integrated NEES system. Under a contract with
NEP, the Company purchases its electric energy requirements from NEP. The
contract provides for the integration of the Company's generating and
transmission facilities with NEP's facilities in order to achieve maximum
economy and reliability. The contract also provides for the application of
credits against the Company's power bills from NEP for costs associated with
the Company's facilities so integrated. The Company and NEP are members of
the New England Power Pool, which provides for the coordination of the
planning and operation of the generation and transmission facilities in New
England, and the region-wide central dispatch of generation.
Report of Independent Accountants
The Narragansett Electric Company, Providence, Rhode Island:
We have audited the accompanying balance sheets of The Narragansett
Electric Company (the Company), a wholly-owned subsidiary of New England
Electric System, as of December 31, 1994 and 1993 and the related statements
of income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of the Company as
of December 31, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 27, 1995
<PAGE>
The Narragansett Electric Company
Financial Review
Overview
Net income for 1994 increased by $300,000 compared with 1993. The
increase was primarily due to the inclusion in 1993 of a one-time charge
associated with an early retirement program. The increase also reflects
kilowatthour (KWH) sales growth in 1994, the commencement of recognition of
revenues for electricity delivered but not yet billed (unbilled revenues)
pursuant to a 1994 rate agreement, and increased allowance for funds used
during construction. These increases were largely offset by rate discounts
to large commercial and industrial customers also implemented as part of this
rate agreement, increases in other operation expenses, and increased interest
expense due to additional debt outstanding.
Net income decreased by $7 million in 1993. This decrease was primarily
due to increased operation and maintenance expenses as well as a reduction
in incentives recorded on the Company's demand-side management (DSM)
programs. This increase in operation and maintenance expense included the
effects of an early retirement program discussed above. The decrease in
income was partially offset by an increase in KWH sales to ultimate
customers.
Rate Activity
On March 1, 1995, the Company filed with the Rhode Island Public
Utilities Commission (RIPUC) a request to increase its base rates by $30.5
million to be effective December 1995. As an alterative to the December 1995
effective date, the Company proposed to phase its requested rate increase in
two steps--the first step in June 1995 ($13 million) and the second step in
June 1996. As part of its filing, the Company proposed a special rate
discount of 8 percent of base rates, for manufacturing customers that agree
to give the Company a five-year notice before they purchase power from
another supplier or generate any additional power themselves.
In July 1994, the RIPUC approved a rate agreement between the Company
and the Rhode Island Division of Public Utilities and Carriers that provides
for a 5 percent base rate discount, excluding fuel costs, for the Company's
large commercial and industrial customers who sign an agreement to give a
five-year notice to the Company before they purchase power from another
supplier or generate any additional power themselves. The notice provision
may be reduced from five to three years under certain conditions. The
aggregate amount of the Company's discounts was $1.5 million in 1994 and is
expected to be approximately $3 million per year thereafter. Customers
representing over 64 percent of revenues from large commercial and industrial
customers have signed these agreements. In addition, commencing in 1995 the
cost of these discounts is being passed on to New England Power Company
(NEP), the Company's affiliated wholesale power supplier. This is the result
of a NEP rate settlement that was approved by the Federal Energy Regulatory
Commission (FERC) in early 1995. The agreement also provides for the Company
to recognize, for accounting purposes, $14 million of unbilled revenues over
a 21 month period beginning April 1994 through December 1995.
Effective March 1993, the RIPUC approved a new purchased power cost
adjustment (PPCA) mechanism for the recovery of all of the Company's
purchased power costs, excluding fuel charges which continue to be
<PAGE>
Rate Activity (continued)
recovered through a separate adjustment mechanism. Under the new mechanism
any over or under-collections of purchased power expense will ultimately be
passed on to customers including the effects of peak-demand billing
fluctuations. The Company accrues the effects of this new mechanism on its
books on a current basis. In August 1994, the RIPUC gave notice that it
intends to open a proceeding to consider the effect of fuel adjustment
clauses on utility incentives to reduce costs.
Effective January 1993, the RIPUC approved a $1.5 million increase in
rates for the Company, representing the first step of a three year phase-in
of the Company's recovery of costs associated with postretirement benefits
other than pensions (PBOPs). The second and third $1.5 million increases
took effect in January 1994 and 1995, respectively.
A 1986 Rhode Island Supreme Court decision held that the RIPUC's
rate-making power includes the authority to order refunds of amounts earned
in excess of an allowed return. As a result, the RIPUC monitors the
Company's earnings on a regular basis.
Demand-Side Management
The Company regularly files its demand-side management (DSM) programs
with the RIPUC and has received approval to recover DSM program expenditures
in rates on a current basis. These expenditures were $10 million, $12
million, and $12 million in 1994, 1993, and 1992, respectively. Since 1990,
the Company has been allowed to earn incentives based on the results of its
DSM programs. The Company must be able to demonstrate the electricity
savings produced by its DSM programs to the RIPUC before incentives are
recorded. The Company recorded before-tax incentives of $0.6 million, $0.5
million, and $1.3 million in 1994, 1993, and 1992, respectively. The Company
has received regulatory orders that will give it the opportunity to continue
to earn incentives based on 1995 DSM program results.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
- -----------------------------------------------------------------------
(In Millions) 1994 1993
- -----------------------------------------------------------------------
Sales growth $ 5 $ 6
General rate changes - 2
Unbilled revenues 5 -
PPCA mechanism (2) 2
DSM recovery (2) -
Fuel recovery (7) 5
---------------------
$(1) $15
=====================
KWH sales billed to ultimate customers in 1994 increased by 0.6 percent
over 1993. The increase in KWH sales reflects an improved economy partially
offset by a loss of sales attributable to the May 1994 plant closing of one
<PAGE>
Operating Revenue (continued)
of the Company's largest customers. Revenues from this customer, excluding
fuel and purchased power costs, were approximately $1.4 million on an annual
basis. KWH sales in 1993 increased 2.9 percent over 1992 sales, reflecting
more normal weather conditions in 1993 compared with 1992, partially offset
by the fact that 1992 included an extra day for leap year.
The Company's rates contain a fuel clause and a PPCA provision. These
mechanisms are designed to allow the Company to pass on to its customers
changes in purchased energy costs resulting from rate increases or decreases
by NEP, the Company's affiliated wholesale power supplier.
In the third quarter of 1994, the Company began recognizing unbilled
revenues according to its rate agreement filed in July 1994 with the RIPUC.
For a further discussion of unbilled revenues, see "Rate Activity" section.
Operating Expenses
The following table summarizes the changes in total operating expenses
discussed below:
Increase (Decrease) in Operating Expenses
- -------------------------------------------------------------------------
(In Millions) 1994 1993
- -------------------------------------------------------------------------
Fuel for generation $ - $(3)
Purchased electric energy:
Fuel costs (7) 5
NEP refunds 1 2
Purchases and demand charges from NEP 2 4
Integrated facilities credit from NEP (6) 13
Other operation and maintenance:
DSM (2) -
Thermal generation - (6)
Other 1 13
Depreciation 7 (2)
Taxes 1 (4)
---------------
$(3) $22
===============
The entire output of the Company's generating capacity is made available
to NEP. The Company receives a credit on its purchased power bill from NEP
for its fuel costs and other generation and transmission costs. The change
in the integrated facilities credit from NEP for 1994 shown in the above
table reflects increased credits for dismantlement costs being incurred on
the Company's previously retired South Street generating station. These
increased costs for dismantlement are reflected in the increase in
depreciation shown above.
The change in the integrated facilities credit from NEP for 1993
reflects decreased credits is attributable to the Company's mid-1992 sale of
90 percent of the Manchester Street Station to NEP as part of the Manchester
Street repowering project. The decreases in fuel for generation and thermal
generation-related operation and maintenance costs in 1993 are also due to
this sale (see "Repowering of Manchester Street Station" section).
<PAGE>
Operating Expenses (continued)
The changes in the fuel cost component of purchased power in 1994 and
1993 reflect changes in the amount of New England Energy Incorporated's
(NEEI) costs passed through by NEP. NEEI is an affiliated company involved
in oil and gas exploration and development. The 1994 decrease also reflects
a reduction in the fuel component of NEP's purchased electric energy costs.
In addition, the increase in fuel costs in 1993 reflects increased KWH
purchases.
The change in other operation and maintenance expense in both 1993 and
1994 reflects the one-time charge of $5 million in 1993 associated with an
early retirement program. The increase in both periods also reflects
increased computer system development costs and postretirement benefit costs
as well as general increases in other areas.
Allowance for Funds Used During Construction (AFDC)
AFDC increased in 1994 and 1993 due to increased construction work in
progress associated with the repowering of the Manchester Street Station (see
"Repowering of Manchester Street Station" section).
Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products. New
England Electric System (NEES) subsidiaries currently have in place an
environmental audit program intended to enhance compliance with existing
federal, state, and local requirements regarding the handling of potentially
hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for two sites (one of which is located
in Massachusetts) at which hazardous waste is alleged to have been disposed.
The Company is currently aware of other sites, and may in the future become
aware of additional sites, that it may be held responsible for remediating.
Gas was manufactured from coal in Rhode Island in the past. The Company
is aware of five sites on which gas was manufactured or manufactured gas was
stored that were owned either by the Company or by its predecessor companies.
It is not known to what extent the Company would be held liable for hazardous
wastes, if any, left at these manufactured gas locations.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and remediation
costs of any particular hazardous waste site that may ultimately be borne by
the Company. A preliminary review by a consultant hired by the NEES
companies of the potential cost of investigating and, if necessary,
remediating Rhode Island manufactured gas sites resulted in costs per site
<PAGE>
Hazardous Waste (continued)
ranging from less than $1 million to $8 million. An informal survey of other
utilities conducted on behalf of NEES and its subsidiaries indicated costs
in a similar range. Where appropriate, the Company intends to seek recovery
from its insurers and from other PRPs, but it is uncertain whether and to
what extent such efforts would be successful. The Company believes that
hazardous waste liabilities for all sites of which it is aware will not be
material to its financial position.
Electric and Magnetic Fields (EMF)
In recent years, concerns have been raised about whether EMF, which
occur near transmission and distribution lines as well as near household
wiring and appliances, cause or contribute to adverse health effects.
Numerous studies on the effects of these fields, some of them sponsored by
electric utilities (including NEES companies), have been conducted and are
continuing. Some of the studies have suggested associations between certain
EMF and health effects, including various types of cancer, while other
studies have not substantiated such associations. It is impossible to
predict the ultimate impact on the Company and the electric utility industry
if further investigations were to demonstrate that the present electricity
delivery system is contributing to increased risk of cancer or other health
problems.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In
any event, the Company believes that it currently has adequate insurance
coverage for personal injury claims.
Several state courts have recognized a cause of action for damage to
property values in transmission line condemnation cases based on the fear
that power lines cause cancer. It is difficult to predict what the impact
on the Company would be if this cause of action is recognized in Rhode Island
and in contexts other than condemnation cases.
Bills have been introduced unsuccessfully in the past in the Rhode
Island legislature to require that transmission lines be placed underground.
Competitive Conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of NEP's new generating capability has come from independent
generating sources and Hydro-Quebec.
<PAGE>
Competitive Conditions (continued)
Electric utilities are also facing increased competition in the retail
market. Currently, retail competition includes competition with alternative
fuel suppliers (including natural gas companies) for heating and cooling,
competition with customer-owned generation to displace purchases from
electric utilities, and direct competition among electric utilities to
attract major new facilities to their service territories. Electric
utilities, including the Company, are under increasing pressure from large
commercial and industrial customers to discount rates or face the possibility
that such customers might relocate or seek alternate suppliers. Across the
country, including Rhode Island and the other states in which the Company's
affiliates operate, there have been an increasing number of proposals to
allow retail customers to choose their electricity supplier, with utilities
required to deliver that electricity over their transmission and distribution
systems. In Rhode Island, the RIPUC has convened a task force of utilities,
commercial and industrial customers, regulators, and other interested parties
to prepare a report by May 1995 regarding restructuring the industry. The
Massachusetts Division of Energy Resources (DOER) proposed in January 1995
that the Massachusetts Department of Public Utilities (MDPU) modify its
regulations to allow retail utility customers to choose a supplier and bid
for access to the local utility's transmission and distribution systems in
situations where new generating capacity is needed. The NEES companies have
indicated their support for the DOER proposal. The Company's Massachusetts
retail affiliate has announced plans to propose a limited bidding experiment
consistent with the DOER proposal. Also in Massachusetts, the MDPU initiated
a proceeding in February 1995 regarding electric industry regulation and
structure. In New Hampshire, the New Hampshire Public Utilities Commission
is considering the proposal of a new company to sell electricity at retail
to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning
and operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could
be substantial, have been referred to by the industry as stranded costs.
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have
taken the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the
FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a
utility may recover such stranded costs from a departing wholesale
requirements customer. On appeal, the United States Court of Appeals for the
District of Columbia Circuit has questioned whether allowing utilities to
recover stranded costs is anti-competitive and the Court remanded the case
back to the FERC for further proceedings and development of the competitive
issues.
<PAGE>
Competitive Conditions (continued)
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The retail business unit, which includes the Company, is responding to
competition through the development of an EnergyFIT program, which offers
comprehensive value-added services for large business customers, intensified
business development efforts, including economic development rates and
service packages to encourage businesses to locate in the Company's service
territory, and development of new pricing and service options for customers.
Additionally, more than 75 percent of the Company's large commercial and
industrial customers (representing 64 percent of eligible revenues) have
signed service extension discount contracts providing for discounts in
exchange for agreements requiring three to five years notice before they may
change electricity suppliers (see "Rate Activity" section). As part of their
long-term planning process, the NEES companies are from time to time
evaluating other strategies, such as business combinations and other forms
of restructuring, to better respond to the changing competitive environment.
Since the largest component of the Company's costs is represented by the
cost of power purchased from NEP, its competitive position is affected by
NEP's ability to control costs. NEP is controlling costs and positioning
itself for increased competition by freezing base rates until at least 1997
(wholesale base rates were last raised in March 1992), terminating certain
purchased power and gas pipeline contracts, shutting down uneconomic
generating stations, and accelerating the recovery of uneconomic assets and
other deferred costs. In addition, NEP's wholesale tariff requires its
wholesale customers, including the Company and NEES's other retail
subsidiaries, to provide seven years notice before they may terminate the
tariff.
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable. In
addition, if, because of competition, utilities are unable to recover all of
their costs in rates, it may be necessary to write off those costs that are
not recoverable.
<PAGE>
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $93 million in 1994,
including $33 million related to the Manchester Street Station repowering
project discussed below. The funds necessary for utility plant expenditures
were primarily provided by net cash from operating activities, after the
payment of dividends, the issuance of long-term and short-term debt, and a
capital contribution from NEES. Cash expenditures for utility plant for 1995
are estimated to be $55 million (including approximately $16 million related
to the repowering of Manchester Street Station). Internally generated funds
are estimated to provide 50 percent of these needs in 1995. Cash
expenditures for utility plant are also expected to be funded through the
issuance of long-term and short-term debt.
In 1994, the Company issued $33 million of first mortgage bonds bearing
interest rates ranging from 6.91 percent to 8.33 percent. The Company has
issued $5 million of long-term debt to date in 1995 at an interest rate of
7.81 percent and plans to issue an additional $20 million of long-term debt
later in 1995 to reduce short-term debt and fund capital expenditures.
At December 31, 1994, the Company had $30 million of short-term debt
outstanding in the form of commercial paper borrowings. As of December 31,
1994, the Company had lines of credit with banks totaling $41 million. There
were no borrowings under these lines of credit at December 31, 1994.
Repowering of Manchester Street Station
The Company's major construction project is the repowering of Manchester
Street Station, a 140 megawatt electric generating station in Providence,
Rhode Island. Repowering will more than triple the power generation capacity
of Manchester Street Station and substantially increase the plant's thermal
efficiency. To facilitate financing this project, the Company sold a 90
percent interest in the existing station to NEP effective July 1, 1992. The
total cost for the generating station, scheduled to be placed in service in
late 1995, is estimated to be approximately $520 million including AFDC. At
December 31, 1994, $298 million, including AFDC, had been spent on the
generating station (including $28 million by the Company). In addition,
related transmission improvements were placed in service in September 1994
at a cost of approximately $60 million (including approximately $45 million
by the Company).
<PAGE>
The Narragansett Electric Company
Statements of Income
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenue $481,669 $483,028 $468,252
Operating expenses:
Purchased electric energy, principally
from New England Power Company, an affiliate 300,678 310,895 286,483
Other operation 73,082 73,723 69,602
Maintenance 12,281 12,179 12,286
Depreciation 24,813 17,645 19,826
Taxes, other than federal income taxes 35,818 35,846 35,172
Federal income taxes 4,883 4,175 8,984
----------------------------------
Total operating expenses 451,555 454,463 432,353
----------------------------------
Operating income 30,114 28,565 35,899
Other income:
Allowance for equity funds used during construction 1,028 543 10
Other income (expense) - net, including related taxes (856) (634) (639)
----------------------------------
Operating and other income 30,286 28,474 35,270
----------------------------------
Interest:
Interest on long-term debt 14,334 12,715 13,290
Other interest 2,897 2,074 1,277
Allowance for borrowed funds used during
construction - credit (1,534) (589) (349)
----------------------------------
Total interest 15,697 14,200 14,218
----------------------------------
Net income $ 14,589 $ 14,274 $ 21,052
==================================
Statements of Retained Earnings
- -----------------------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
- -----------------------------------------------------------------------------------------
Retained earnings at beginning of year $81,659 $74,207 $59,804
Net income 14,589 14,274 21,052
Dividends declared on cumulative preferred stock (2,143) (1,931) (1,553)
Dividends declared on common stock, $2.25, $4.00,
and $4.50 per share, respectively (2,549) (4,530) (5,096)
Premium on redemption of preferred stock (361)
----------------------------------
Retained earnings at end of year $91,556 $81,659 $74,207
==================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
The Narragansett Electric Company
Balance Sheets
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, (In Thousands) 1994 1993
- -----------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility plant, at original cost $617,498 $534,569
Less accumulated provisions for depreciation 161,557 156,652
---------------------
455,941 377,917
Construction work in progress 35,974 43,660
---------------------
Net utility plant 491,915 421,577
---------------------
Current assets:
Cash 713 838
Accounts receivable:
From sales of electric energy 51,278 55,795
Other (including $9,306,000 and $1,087,000 from affiliates) 17,953 11,701
Less reserves for doubtful accounts 4,472 3,800
---------------------
64,759 63,696
Unbilled revenues (Note A-2) 13,100
Fuel, materials, and supplies, at average cost 5,170 4,572
Prepaid and other current assets 13,993 11,515
---------------------
Total current assets 97,735 80,621
---------------------
Deferred charges and other assets (Note A-6) 57,727 53,709
---------------------
$647,377 $555,907
=====================
Capitalization and Liabilities
Capitalization:
Common stock, par value $50 per share, authorized
and outstanding 1,132,487 shares $ 56,624 $ 56,624
Premiums on preferred stocks 170 170
Other paid-in capital 60,000 45,000
Retained earnings 91,556 81,659
---------------------
Total common equity 208,350 183,453
Cumulative preferred stock, par value $50 per share 36,500 36,500
Long-term debt 188,862 155,972
---------------------
Total capitalization 433,712 375,925
---------------------
Current liabilities:
Short-term debt (including $19,725,000 to affiliates in 1993) 29,800 19,725
Accounts payable (including $47,900,000 and $43,468,000
to affiliates) 56,139 51,005
Accrued liabilities:
Taxes 143 1,712
Interest 5,615 4,921
Other accrued expenses (Note A-2) 25,346 11,798
Customer deposits 5,261 5,622
Dividends payable 819 1,102
---------------------
Total current liabilities 123,123 95,885
---------------------
Deferred federal income taxes 70,253 63,494
Unamortized investment tax credits 8,518 9,026
Other reserves and deferred credits 11,771 11,577
Commitments and contingencies (Note C)
---------------------
$647,377 $555,907
=====================
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
The Narragansett Electric Company
Statements of Cash Flows
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating activities:
Net income $ 14,589 $ 14,274 $ 21,052
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation 24,813 17,645 19,826
Deferred federal income taxes and
investment tax credits - net 3,422 1,690 4,053
Allowance for funds used during construction (2,562) (1,132) (359)
Amortization of unbilled revenues (6,158)
Early retirement program 2,705
Decrease (increase) in accounts receivable, net
and unbilled revenues (14,163) (2,183) (5,935)
Decrease (increase) in fuel, materials, and (598) 429 3,281
supplies
Decrease (increase) in prepaid and other current
assets (2,478) 2,359 (12,786)
Increase (decrease) in accounts payable 5,134 (3,180) 2,214
Increase (decrease) in other current liabilities 12,312 2,287 8,879
Other, net 5,877 (2,180) 404
----------------------------------
Net cash provided by operating activities $ 40,188 $ 32,714 $ 40,629
----------------------------------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(92,503) $(62,897) $(39,624)
Other investing activities (911)
Purchase of 90 percent interest in Manchester
Street Station from affiliate 3,249
----------------------------------
Net cash used in investing activities $(93,414) $(62,897) $(36,375)
----------------------------------
Financing activities:
Capital contributions from NEES $ 15,000 $ 10,000
Dividends paid on common stock (2,831) $ (5,663) (4,530)
Dividends paid on preferred stock (2,143) (1,783) (1,553)
Changes in short-term debt 10,075 16,050 (11,850)
Long-term debt - issues 33,000 27,500 67,500
Long-term debt - retirements (14,900) (62,200)
Preferred stock - issues 20,000
Preferred stock - retirements (10,000)
Premium on reacquisition of long-term debt (652) (1,645)
Premium on redemption of preferred stock (361)
Net cash provided by (used in) ----------------------------------
financing activities $ 53,101 $ 30,191 $ (4,278)
----------------------------------
Net increase (decrease) in cash and cash
equivalents $ (125) $ 8 $ (24)
Cash and cash equivalents at beginning of year 838 830 854
----------------------------------
Cash and cash equivalents at end of year $ 713 $ 838 $ 830
==================================
Supplementary Information:
Interest paid less amounts capitalized $ 14,015 $ 12,623 $ 12,365
----------------------------------
Federal income taxes paid $ 2,982 $ 2,352 $ 4,005
----------------------------------
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
The Narragansett Electric Company
Notes to Financial Statements
Note A - Significant Accounting Policies
- ----------------------------------------
1. System of Accounts:
The accounts of the Company are maintained in accordance with the Uniform
System of Accounts prescribed by regulatory bodies having jurisdiction.
2. Revenue:
The Company, pursuant to its 1994 rate agreement, began accruing revenues
for electricity delivered but not yet billed (unbilled revenues).
Unbilled revenues at December 31, 1994 were $13 million, of which $5
million were recognized in income monthly in 1994. The remainder of $8
million at December 31, 1994 has been deferred for recognition monthly
through December 1995 and appears on the balance sheet under the caption
"Other accrued expenses". Accrued revenues are also recorded in
accordance with rate adjustment mechanisms.
3. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC
represents the composite interest and equity costs of capital funds used
to finance that portion of construction costs not eligible for inclusion
in rate base. In 1994, an average of $5 million of construction work in
progress was included in rate base, all of which was attributable to the
Manchester Street Station repowering project. AFDC is capitalized in
"Utility plant" with offsetting non-cash credits to "Other income" and
"Interest". This method is in accordance with an established rate-making
practice under which a utility is permitted a return on, and the recovery
of, prudently incurred capital costs through their ultimate inclusion in
rate base and in the provision for depreciation. The composite AFDC rates
were 6.8 percent, 6.9 percent, and 5.0 percent, in 1994, 1993, and 1992,
respectively.
4. Depreciation:
Depreciation is provided annually on a straight-line basis. The
provisions for depreciation as a percentage of weighted average
depreciable property were 4.5 percent, 3.5 percent, and 3.8 percent in
1994, 1993, and 1992, respectively. The increase in the depreciation rate
in 1994 is primarily due to the recognition through depreciation expense
of dismantlement costs for a retired generating facility.
5. Cash:
The Company classifies short-term investments with a remaining maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
Outstanding checks are therefore recorded in accounts payable until such
time as the banks present them for payment.
<PAGE>
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
6. Deferred Charges and Other Assets:
The components of deferred charges and other assets are as follows:
--------------------------------------------------------------------
At December 31, (In Thousands) 1994 1993
--------------------------------------------------------------------
Regulatory assets:
Deferred SFAS No. 109 costs (see Note B) $26,999 $24,170
Unamortized losses on reacquired debt 12,538 13,383
Deferred SFAS No. 106 costs (see Note D-2) 5,539 4,053
Deferred storm costs 4,277 5,122
Other 3,751 3,750
--------------------
53,104 50,478
Other deferred charges and other assets 4,623 3,231
--------------------
$57,727 $53,709
====================
Electric utility rates are generally based on a utility's costs. As a
result, electric utilities are subject to certain accounting standards
that are not applicable to other business enterprises in general. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in
future rates. The effects of competition could ultimately cause the
operations of the Company, or a portion thereof, to cease meeting the
criteria for application of these accounting rules. In such an event,
accounting standards applicable to enterprises in general would apply and
immediate write-off of any previously deferred costs (regulatory assets)
would be necessary in the year in which these criteria were no longer
applicable. Approximately $20 million of the regulatory assets at
December 31, 1994 listed above are expected to be recovered within 10
years. All of the remainder will be fully recovered within the next 20
years with the exception of the Deferred SFAS No. 109 costs which will
take longer to recover.
Note B - Federal Income Taxes
- -----------------------------
The Company and other subsidiaries participate with New England Electric
System (NEES) in filing consolidated federal income tax returns. The
Company's income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by the
Internal Revenue Service through 1991.
<PAGE>
Note B - Federal Income Taxes (continued)
- -----------------------------
Federal income taxes consist of the following components:
-------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-------------------------------------------------------------------------
Income taxes charged to operations:
Current income taxes $1,511 $2,537 $4,998
Deferred income taxes 3,880 2,146 4,493
Investment tax credits--net (508) (508) (507)
----------------------------
Total income taxes charged to operations 4,883 4,175 8,984
----------------------------
Income taxes charged (credited)
to "Other income":
Current income taxes (491) (354) (390)
Deferred income taxes 50 53 67
----------------------------
Total income taxes charged (credited) to
"Other income" (441) (301) (323)
----------------------------
Total federal income taxes $4,442 $3,874 $8,661
============================
Investment tax credits are deferred and amortized over the estimated lives
of the property giving rise to the credits. Since the Tax Reform Act of
1986 generally eliminated investment tax credits, the amounts shown above
principally reflect the amortization of investment tax credits generated
in prior years.
Consistent with rate-making policies of the Rhode Island Public Utilities
Commission (RIPUC), the Company has adopted comprehensive interperiod tax
allocation (normalization) for most temporary book/tax differences.
Total federal income taxes differ from the amounts computed by applying
the federal statutory tax rates to income before taxes. The reasons for
the differences are as follows:
--------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
--------------------------------------------------------------------------
Computed tax at statutory rate $ 6,661 $ 6,352 $10,102
Increases (reductions) in tax resulting from:
Book versus tax depreciation not normalized 653 496 749
Costs associated with utility plant
retirements deducted for tax purposes (1,872) (1,756) (1,257)
Allowance for equity funds used during
construction (360) (190) (3)
Amortization of investment tax credits (508) (508) (508)
Adjustment of prior year tax accruals (150) (473)
All other differences 18 (47) (422)
----------------------------
Total federal income taxes $ 4,442 $ 3,874 $ 8,661
============================
Effective federal income tax rate 23.3% 21.3% 29.1%
============================
<PAGE>
Note B - Federal Income Taxes (continued)
- -----------------------------
The Financial Accounting Standards Board established Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes" which became effective in 1993. The application of this new
standard did not have a significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
--------------------------------------------------------------------
At December 31, (In Millions) 1994 1993
--------------------------------------------------------------------
Deferred tax asset:
Plant related $ 2 $ 2
Investment tax credits 3 3
All other 13 13
------------------
18 18
------------------
Deferred tax liability:
Plant related (57) (53)
All other (31) (28)
------------------
(88) (81)
------------------
Net deferred tax liability $(70) $ (63)
==================
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appeared on the
income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily included deferred income taxes of $3 million in connection with
postretirement benefits other than pensions and $2 million related to
utility plant, partially offset by deferred tax credits of $1 million
associated with rate adjustment mechanisms.
<PAGE>
Note C - Commitments and Contingencies
- --------------------------------------
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be $55 million
in 1995. At December 31, 1994, substantial commitments had been made
relative to future planned expenditures.
2. Hazardous Waste:
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of
property contaminated with hazardous substances.
The electric utility industry typically utilizes and/or generates in its
operations a range of potentially hazardous products and by-products.
NEES subsidiaries currently have in place an environmental audit program
intended to enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous products and
by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for two sites (one of which is
located in Massachusetts) at which hazardous waste is alleged to have been
disposed. The Company is currently aware of other sites, and may in the
future become aware of additional sites, that it may be held responsible
for remediating.
Gas was manufactured from coal in Rhode Island in the past. The Company
is aware of five sites on which gas was manufactured or manufactured gas
was stored that were owned either by the Company or by its predecessor
companies. It is not known to what extent the Company would be held
liable for hazardous wastes, if any, left at these manufactured gas
locations.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant
uncertainties as to the portion, if any, of the investigation and
remediation costs of any particular hazardous waste site that may
ultimately be borne by the Company. A preliminary review by a consultant
hired by the NEES companies of the potential cost of investigating and,
if necessary, remediating Rhode Island manufactured gas sites resulted in
costs per site ranging from less than $1 million to $8 million. An
informal survey of other utilities conducted on behalf of NEES and its
subsidiaries indicated costs in a similar range. Where appropriate, the
Company intends to seek recovery from its insurers and from other PRPs,
but it is uncertain whether and to what extent such efforts would be
successful. The Company believes that hazardous waste liabilities for all
sites of which it is aware will not be material to its financial position.
3. 1991 Rhode Island Filled Land Legislation:
The Company's title to properties which may be situated on filled lands
(including substations) has been called into question by a 1991 Rhode
Island Supreme Court case dealing with title to filled land. The
Company's title to the land on which the Manchester Street Station
property is located was cleared by legislation in July 1992, by the Rhode
Island legislature. The Company is challenging the 1991 ruling with
respect to another parcel of property.
<PAGE>
Note D - Employee Benefits
- --------------------------
1. Pension Plans:
The Company participates with other subsidiaries of NEES in
noncontributory defined-benefit plans covering substantially all employees
of the Company. The plans provide pension benefits based on the
employee's compensation during the five years before retirement. The
Company's funding policy is to contribute each year, the net periodic
pension cost for that year. However, the contribution for any year will
not be less than the minimum required contribution under federal law or
greater than the maximum tax deductible amount.
Net pension cost for 1994, 1993, and 1992 included the following
components:
-------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-------------------------------------------------------------------------
Service cost-benefits earned during the
period $ 1,877 $ 1,557 $ 1,558
Plus (less):
Interest cost on projected benefit
obligation 8,629 8,737 8,261
Return on plan assets at expected long-term
rate (9,024) (8,739) (8,572)
Amortization 567 (101) (125)
----------------------------
Net pension cost $ 2,049 $ 1,454 $ 1,122
============================
Assumptions used to determine pension cost:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future
compensation levels 4.35% 5.35% 6.70%
Expected long-term rate of return on assets 8.75% 8.75% 9.00%
----------------------------
Actual return on plan assets $ 809 $13,545 $ 7,570
============================
Service cost for 1993 does not reflect costs incurred in connection with
an early retirement program offered by the Company in that year (see Note
D-3).
The funded status of the plans cannot be presented separately for the
Company as the Company participates in the plans with other NEES
subsidiaries. The following table sets forth the funded status of the
NEES companies' plans at December 31:
<PAGE>
Note D - Employee Benefits (continued)
- --------------------------
-------------------------------------------------------------------------
Retirement Plans (In Millions) 1994 1993
---------------------------------------------------------------------------
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
----------------------------------------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $251 $308 $251 $333
Non-vested 8 9 20 6
--------------------------------------
Total $259 $317 $271 $339
======================================
Reconciliation of funded status
Actuarial present value of
projected benefit liability $303 $355 $310 $383
Unrecognized prior service costs (8) (4) (8) (6)
SFAS No. 87 transition liability
not yet recognized (amortized) - (1) - (1)
Net loss not yet recognized
(amortized) (13) (33) (11) (45)
Additional minimum liability
recognized - - - 8
--------------------------------------
282 317 291 339
--------------------------------------
Pension fund assets at fair value 293 323 302 318
SFAS No. 87 transition asset not
yet recognized (amortized) (13) - (14) -
--------------------------------------
280 323 288 318
--------------------------------------
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $ 3 $ 21
======================================
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed
effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively.
The expected long-term rate of return on assets used to calculate pension
cost was not changed from the level shown in the table above. The plans'
funded status at December 31, 1994 was calculated using these revised
rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions and Postemployment
Benefits:
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits
Other Than Pensions" (PBOPs) went into effect. The Company provides
health care and life insurance coverage to eligible retired employees.
<PAGE>
Note D - Employee Benefits (continued)
- --------------------------
Eligibility is based on certain age and length of service requirements and
in some cases retirees must contribute to the cost of their coverage.
The total cost of PBOPs for 1994 and 1993 included the following
components:
--------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993
--------------------------------------------------------------------
Service cost--benefits earned during
the period $ 1,252 $ 1,161
Plus (less):
Interest cost on the accumulated
benefit obligation 5,630 6,330
Return on plan assets at expected
long-term rate (1,640) (1,031)
Amortization 3,716 3,864
---------------------
Net postretirement benefit cost $ 8,958 $10,324
=====================
Actual return (loss) on plan assets $ (23) $ 1,047
=====================
The following table sets forth benefits earned and the plans' funded status:
-----------------------------------------------------------------------
At December 31, (In Millions) 1994 1993
-----------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 50 $ 54
Fully eligible active plan participants 10 7
Other active plan participants 14 22
------------------
Total benefits earned 74 83
Unrecognized transition obligation (70) (74)
Net gain (loss) not yet recognized 10 (1)
------------------
14 8
Plan assets at fair value 22 17
------------------
Prepaid postretirement benefit costs
recorded on books $ 8 $ 9
==================
----------------------------------------------------------------------
1995 1994 1993
----------------------------------------------------------------------
Assumptions used to determine
postretirement benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return
on assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
<PAGE>
Note D - Employee Benefits (continued)
- --------------------------
The plans' funded status at December 31,1994 and 1993 presented above was
calculated using the assumed rates in effect for 1995 and 1994,
respectively.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed rates by 1 percent in each year
would increase the accumulated postretirement benefit obligation as of
December 31, 1994 by approximately $11 million and the net periodic cost
for the year 1994 by approximately $1.2 million.
The Company funds the annual tax deductible contributions. Plan assets
are invested in equity and debt securities and cash equivalents.
Prior to 1993, the Company recorded the cost of PBOPs when paid. These
costs amounted to approximately $3.0 million in 1992. The Company has
been permitted by the RIPUC to phase-in over a three year period that
commenced January 1, 1993, a level of rate recovery that is expected to
equal or exceed the amount of PBOP costs calculated in accordance with
SFAS No. 106. At December 31, 1994, the Company had deferred for recovery
over a seven year period commencing January 1, 1996, $6 million,
representing that portion of increased PBOP costs not being recovered
during this phase-in period. Therefore, adoption of this new accounting
standard did not have a significant impact on net income.
In the fourth quarter of 1993, the Company recorded a $1 million charge
to earnings reflecting the cumulative effect of adopting a new accounting
standard for postemployment benefits.
3. 1993 Early Retirement and Special Severance Programs:
In February 1993, the Company offered a voluntary early retirement program
to non-union employees who were at least 55 years old with 10 years of
service. This program was part of an organizational review with the goal
of streamlining operations and reducing the work force. The early
retirement offer was accepted by 46 employees. A special severance
program was also announced in February 1993 for employees affected by the
organizational review, but who were not eligible for, or did not accept,
the early retirement offer. The Company recorded in the first quarter of
1993 a one-time charge to earnings of approximately $3 million, after tax
($5 million, before tax), to reflect the cost of the early retirement and
special severance programs which consisted principally of pension
benefits. This total includes the Company's portion of its affiliated
service company's cost of these programs.
Note E - Short-term Borrowing Arrangements
- ------------------------------------------
At December 31, 1994, the Company had $30 million of short-term debt
outstanding in the form of commercial paper borrowings. At December 31,
1994, the Company had lines of credit with banks totaling $41 million.
There were no borrowings under these lines of credit at December 31, 1994.
Fees are paid in lieu of compensating balances on most lines of credit.
The weighted average rate on outstanding short-term borrowings was 6.1
percent at December 31, 1994.
<PAGE>
Note F - Intercompany Lending Arrangement
- -----------------------------------------
NEES and certain subsidiaries, including the Company, with regulatory
approval, operate a money pool to more effectively utilize cash resources
and to reduce outside short-term borrowings. Short-term borrowing needs
are met first by available funds of the money pool participants.
Borrowing companies pay interest at a rate designed to approximate the
cost of outside short-term borrowings. Companies which invest in the pool
share the interest earned on a basis proportionate to their average
monthly investment in the money pool. Funds may be withdrawn from or
repaid to the pool at any time without prior notice.
Note G - Cumulative Preferred Stock
- -----------------------------------
A summary of cumulative preferred stock at December 31, 1994 and 1993 is
as follows (in thousands of dollars except for share data):
Shares
Authorized
and Dividends Call
Outstanding Amount Declared Price
-------------------------------------------------------------------------
1994 1993 1994 1993 1994 1993
-------------------------------------------------------------------------
$50 Par value--
4.50% Series 180,000 180,000 $ 9,000 $ 9,000 $ 405 $ 405 $55.000
4.64% Series 150,000 150,000 7,500 7,500 348 348 52.125
6.95% Series 400,000 400,000 20,000 20,000 1,390 710 (a)
8.00% Series 468
--------------------------------------------------
Total 730,000 730,000 $36,500 $36,500 $2,143 $1,931
==================================================
(a) Callable on or after August 1, 2003 at $51.74.
The annual dividend requirement for total cumulative preferred stock was
$2,143,000 for 1994 and 1993.
During 1993, all of the Company's 8.00 percent Series of cumulative
preferred stock were redeemed. Total premiums of $361,000 in connection
with this redemption were charged to retained earnings in 1993. There are
no mandatory redemption provisions on the Company's cumulative preferred
stock.
<PAGE>
Note H - Long-term Debt
- -----------------------
A summary of long-term debt is as follows:
At December 31, (In Thousands)
-------------------------------------------------------------
Series Rate % Maturity 1994 1993
-------------------------------------------------------------
First Mortgage Bonds:
U (92-1) 7.230 June 3, 1997 $ 10,000 $ 10,000
U (92-2) 7.210 June 3, 1997 5,000 5,000
U (92-3) 7.000 June 16, 1997 10,000 10,000
U (92-7) 5.700 September 16, 1997 7,500 7,500
V (94-2) 6.960 May 3, 1999 2,000
V (94-3) 6.910 May 4, 1999 1,000
U (92-6) 6.630 August 12, 1999 5,000 5,000
U (92-5) 6.980 July 17, 2000 5,000 5,000
U (92-8) 6.340 September 18, 2000 10,000 10,000
U (92-4) 7.830 June 17, 2002 15,000 15,000
U (93-1) 7.080 January 13, 2003 7,500 7,500
U (93-2) 6.560 April 15, 2003 5,000 5,000
U (93-4) 6.350 July 1, 2003 5,000 5,000
V (94-4) 7.420 June 15, 2004 5,000
V (94-6) 8.330 November 8, 2004 10,000
U (93-3) 6.650 June 30, 2008 5,000 5,000
S 9.125 May 1, 2021 22,200 22,200
T 8.875 August 1, 2021 40,000 40,000
U (93-5) 7.050 September 1, 2023 5,000 5,000
U (94-1) 7.050 February 2, 2024 5,000
V (94-1) 8.080 May 2, 2024 5,000
V (94-5) 8.160 August 9, 2024 5,000
Unamortized discounts and premiums (1,338) (1,228)
-------------------
Total long-term debt $188,862 $155,972
===================
Substantially all of the properties and franchises of the Company are
subject to the lien of the mortgage indentures under which first mortgage
bonds have been issued.
The Company will make cash payments of $32,500,000 in 1997 and $8,000,000
in 1999 to retire maturing mortgage bonds. There are no cash payments
required in 1995, 1996, and 1998.
<PAGE>
Note I - Fair Value of Financial Instruments
- --------------------------------------------
At December 31, 1994, the Company's long-term debt had a carrying value
of approximately $189,000,000 and had a fair value of approximately
$183,000,000. The fair market value of the Company's long-term debt was
estimated based on the quoted prices for similar issues or on the current
rates offered to the Company for debt of the same remaining maturity. The
fair value of the Company's short-term debt equals carrying value.
Note J - Restrictions on Retained Earnings Available for Dividends on
Common Stock
- ---------------------------------------------------------------------
As long as any preferred stock is outstanding, certain restrictions on
payment of dividends on common stock would come into effect if the "junior
stock equity" was, or by reason of payment of such dividends became less
than 25 percent of "total capitalization". However, the junior stock
equity at December 31, 1994 was 48 percent of total capitalization and,
accordingly, none of the Company's retained earnings at December 31, 1994
were restricted as to dividends on common stock under the foregoing
restrictions.
Under restrictions contained in the indentures relating to first mortgage
bonds, none of the Company's retained earnings at December 31, 1994 were
restricted as to dividends on common stock.
Note K - Regulatory Matters
- ---------------------------
A 1986 Rhode Island Supreme Court decision held that the RIPUC's
rate-making powers include the authority to order refunds of amounts
earned in excess of an allowed return. As a result, the RIPUC monitors
the Company's earnings on a regular basis.
<PAGE>
Note L - Supplementary Income Statement Information
- ---------------------------------------------------
Advertising expenses, expenditures for research and development, and rents
were not material and there were no royalties paid. Taxes, other than
federal income taxes, charged to operating expenses are set forth by
classes as follows:
-----------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-----------------------------------------------------------------------
Municipal property taxes $13,944 $13,798 $13,509
State gross earnings tax 19,270 19,281 18,730
Federal and state payroll and other taxes 2,604 2,767 2,933
----------------------------
$35,818 $35,846 $35,172
============================
New England Power Service Company, an affiliated service company operating
pursuant to the provisions of Section 13 of the Public Utility Holding
Company Act of 1935, furnished services to the Company at the cost of such
services. These costs amounted to $32,445,000, $30,133,000, and
$23,543,000 including capitalized construction costs of $7,756,000,
$6,602,000, and $5,436,000 for each of the years 1994, 1993, and 1992,
respectively.
<PAGE>
The Narragansett Electric Company
Operating Statistics (Unaudited)
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
Year Ended December 31, 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Sources of Energy (Thousands of KWH)
Net generation for New England
Power Company 5,781 4,506 83,753 162,844 583,413
Purchased energy:
From New England Power
Company, an affiliate
(net of generation) 5,001,843 4,982,254 4,729,733 4,699,509 4,272,537
From others 2,909 2,343 2,249 2,243 1,556
--------------------------------------------------------
Total generated and purchased 5,010,533 4,989,103 4,815,735 4,864,596 4,857,506
Losses, company use, etc. (263,234) (270,373) (229,106) (277,383) (265,328)
--------------------------------------------------------
Total sources of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178
========================================================
Sales of Energy (Thousands of KWH)
Residential 1,843,970 1,817,675 1,783,754 1,784,156 1,794,215
Commercial 1,983,508 1,931,377 1,877,738 1,867,225 1,879,587
Industrial 868,092 917,305 869,062 878,142 858,675
Other 51,138 51,821 55,476 57,106 59,099
--------------------------------------------------------
Total sales to
ultimate customers 4,746,708 4,718,178 4,586,030 4,586,629 4,591,576
Sales for resale 591 552 599 584 602
--------------------------------------------------------
Total sales of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178
========================================================
Annual Maximum Demand
(Kw - one hour peak) 1,005,000 939,000 919,000 961,000 940,000
Average Annual Use per
Residential Customer (KWH) 6,397 6,337 6,265 6,308 6,387
Number of Customers at
December 31
Residential 289,317 287,876 286,228 284,275 282,314
Commercial 32,195 31,948 31,534 31,417 31,591
Industrial 1,825 1,869 1,914 1,944 1,983
Other 875 878 941 934 906
--------------------------------------------------------
Total ultimate customers 324,212 322,571 320,617 318,570 316,794
Other electric companies
(for resale) 2 1 3 4 3
--------------------------------------------------------
Total customers 324,214 322,572 320,620 318,574 316,797
========================================================
Operating Revenue (In Thousands)
Residential $201,221 $202,522 $196,983 $192,688 $172,804
Commercial 189,633 190,185 183,702 178,616 162,013
Industrial 72,364 78,088 76,275 76,299 68,644
Other 6,905 6,778 6,587 6,197 5,500
--------------------------------------------------------
Total revenue from
ultimate customers 470,123 477,573 463,547 453,800 408,961
Unbilled revenues 4,891
Sales for resale 68 64 68 65 62
--------------------------------------------------------
Total revenue from
electric sales 475,082 477,637 463,615 453,865 409,023
Other operating revenue 6,587 5,391 4,637 3,645 3,250
--------------------------------------------------------
Total operating revenue $481,669 $483,028 $468,252 $457,510 $412,273
========================================================
</TABLE>
<PAGE>
The Narragansett Electric Company
Selected Financial Information
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Year Ended December 31, (In Millions) 1994 1993 1992 1991 1990
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue:
Electric sales
(excluding fuel cost recovery) $356 $351 $342 $340 $308
Fuel cost recovery 120 127 121 114 101
Other 6 5 5 4 3
------------------------------------------
Total operating revenue $482 $483 $468 $458 $412
Net income $ 15 $ 14 $ 21 $ 17 $ 18
Total assets $647 $556 $479 $445 $421
Capitalization:
Common equity $208 $183 $176 $151 $136
Cumulative preferred stock 37 37 27 27 27
Long-term debt 189 156 143 118 112
------------------------------------------
Total capitalization $434 $376 $346 $296 $275
Preferred dividends declared $ 2 $ 2 $ 2 $ 2 $ 2
Common dividends declared $ 3 $ 5 $ 5 $ 5 $ 8
</TABLE>
Selected Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1994
Operating revenue $125,461 $103,800 $137,014 $115,394
Operating income $ 10,407 $ 2,714 $ 10,937 $ 6,056
Net income (loss) $ 6,314 $ (1,013) $ 7,230 $ 2,058
1993
Operating revenue $124,147 $107,529 $136,174 $115,178
Operating income $ 8,220 $ 3,937 $ 9,761 $ 6,647
Net income $ 3,800 $ 493 $ 6,435 $ 3,546
Per share data is not relevant because the Company's common stock is wholly-owned by New
England Electric System.
A copy of The Narragansett Electric Company's Annual Report on Form 10-K to the Securities
and Exchange Commission, for the year ended December 31, 1994, will be available on or
about April 1, 1995, without charge, upon written request to The Narragansett Electric
Company, Shareholder Services Department, 280 Melrose Street, Providence, Rhode Island
02901.
</TABLE>
<PAGE>
POWER OF ATTORNEY
Each of the undersigned directors of The Narragansett
Electric Company (the "Company"), individually as a director of
the Company, hereby constitutes and appoints John G. Cochrane,
Thomas F. Killeen, and Geraldine M. Zipser, individually, as
attorney-in-fact to execute on behalf of the undersigned the
Company's annual report on Form 10-K for the year ended December
31, 1994, to be filed with the Securities and Exchange
Commission, and to execute any appropriate amendment or
amendments thereto as may be required by law.
Dated this 28th day of March, 1995.
Joan T. Bok John W. Rowe
s/ Stephen A. Cardi s/ Richard P. Sergel
Stephen A. Cardi Richard P. Sergel
s/ Frances H. Gammell s/ William E. Trueheart
Frances H. Gammell William E. Trueheart
s/ Joseph J. Kirby s/ John A. Wilson, Jr.
Joseph J. Kirby John A. Wilson, Jr.
s/ Robert L. McCabe
Robert L. McCabe
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C> <C>
<FISCAL-YEAR-END> DEC-31-1994 DEC-31-1993
<PERIOD-END> DEC-31-1994 DEC-31-1993
<PERIOD-TYPE> 12-MOS 12-MOS
<BOOK-VALUE> PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 491,915 421,577
<OTHER-PROPERTY-AND-INVEST> 0 0
<TOTAL-CURRENT-ASSETS> 97,735 80,621
<TOTAL-DEFERRED-CHARGES> 57,727 <F1> 53,709 <F1>
<OTHER-ASSETS> 0 0
<TOTAL-ASSETS> 647,377 555,907
<COMMON> 56,624 56,624
<CAPITAL-SURPLUS-PAID-IN> 60,170 45,170
<RETAINED-EARNINGS> 91,556 81,659
<TOTAL-COMMON-STOCKHOLDERS-EQ> 208,350 183,453
0 0
36,500 36,500
<LONG-TERM-DEBT-NET> 188,862 155,972
<SHORT-TERM-NOTES> 29,800 <F2> 19,725 <F2>
<LONG-TERM-NOTES-PAYABLE> 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 0
<LONG-TERM-DEBT-CURRENT-PORT> 0 0
0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0
<LEASES-CURRENT> 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 183,865 160,257
<TOT-CAPITALIZATION-AND-LIAB> 647,377 555,907
<GROSS-OPERATING-REVENUE> 481,669 483,028
<INCOME-TAX-EXPENSE> 4,883 4,175
<OTHER-OPERATING-EXPENSES> 446,672 450,288
<TOTAL-OPERATING-EXPENSES> 451,555 454,463
<OPERATING-INCOME-LOSS> 30,114 28,565
<OTHER-INCOME-NET> 172 (91)
<INCOME-BEFORE-INTEREST-EXPEN> 30,286 28,474
<TOTAL-INTEREST-EXPENSE> 15,697 14,200
<NET-INCOME> 14,589 14,274
2,143 1,931
<EARNINGS-AVAILABLE-FOR-COMM> 12,446 11,982
<COMMON-STOCK-DIVIDENDS> 2,549 4,530
<TOTAL-INTEREST-ON-BONDS> 14,334 12,715
<CASH-FLOW-OPERATIONS> 40,188 32,714
<EPS-PRIMARY> 0 0
<EPS-DILUTED> 0 0
<FN>
<F1> Total deferred charges includes other assets.
<F2> Short-term notes includes commercial paper borrowings. Short-term notes at December 31, 1993 also includes short-term
debt to affiliates.
</FN>
