<PAGE 1>
Commonwealth
Energy System
Notice of 1996
(LOGO) Annual Meeting,
Proxy Statement
and 1995 Financial
Information
Please sign and return your
proxy promptly
<PAGE 2>
COMMONWEALTH ENERGY SYSTEM
Cambridge, Massachusetts
Notice of Annual Meeting of Shareholders
May 2, 1996
To the Shareholders of
COMMONWEALTH ENERGY SYSTEM:
Notice is hereby given that the Annual Meeting of Shareholders of
Commonwealth Energy System will be held at the office of the System, One Main
Street, P.O. Box 9150, Cambridge, Massachusetts 02142-9150, on Thursday,
May 2, 1996, at 10:30 o'clock A.M., Eastern Daylight Time, for the following
purposes:
1. To elect three Trustees to hold office for a three-year term and
until the election and qualification of their respective
successors.
2. To take action on a proposal by the Board of Trustees: i) to
amend Section 22 of the System's Declaration of Trust, as amended,
to change the number of authorized Common Shares of the System
from eighteen million (18,000,000) shares having a par value of
four dollars ($4) each to fifty million (50,000,000) shares having
a par value of two dollars ($2) each; ii) to amend Section 5 of
the System's Declaration of Trust in order to facilitate the
implementation of share splits; and iii) to authorize and consent
to a two-for-one share split resulting in the issuance of one
additional Common Share for each Common Share outstanding.
3. To consider and vote upon a shareholder proposal, if presented at
the meeting, as described herein.
4. To transact such other business as may properly come before the
meeting or any adjournment or adjournments thereof.
Common Shareholders of record at the close of business on March 15, 1996
are entitled to notice of, and to vote at, the meeting.
By order of the Trustees,
Michael P. Sullivan
Vice President, Secretary
and General Counsel
March 29, 1996
IMPORTANT
We cordially invite you to attend the Annual Meeting of Shareholders,
but IF YOU DO NOT EXPECT TO BE PRESENT, PLEASE MAIL YOUR PROXY IN ORDER THAT
THE PRESENCE OF A QUORUM MAY BE ASSURED. Because our shares are widely
distributed over a large number of holders, it is both necessary and desirable
that all Shareholders send in their proxies. Failure to secure a quorum on
the date set would necessitate an adjournment, which would cause the System
considerable and needless expense. To avoid this, please SIGN AND DATE the
accompanying proxy and mail it promptly in the enclosed envelope to
Commonwealth Energy System, P.O. Box 9150, Cambridge, Massachusetts 02142-
9150.
<PAGE 3>
PROXY STATEMENT
This statement is furnished in connection with the solicitation of
proxies by the Board of Trustees of Commonwealth Energy System (hereinafter
called the "System") to be used at the Annual Meeting of Shareholders of the
System to be held on Thursday, May 2, 1996, at the principal executive office
of the System, One Main Street, P.O. Box 9150, Cambridge, Massachusetts 02142-
9150, of which due notice has been given in accordance with the System's
Declaration of Trust dated December 31, 1926, as amended. If the enclosed
form of proxy is executed and returned, it may nevertheless be revoked at any
time insofar as it has not been exercised. A properly executed and returned
proxy will be voted in accordance with the directions contained thereon.
Abstentions shall be voted neither "for" nor "against," but shall be counted
in the determination of a quorum. Broker non-votes shall not be counted
either in calculating the number of shares present for the purpose of
determination of a quorum or for the purpose of determining whether a matter
has received the required number of votes. The giving of a later-dated proxy
revokes all proxies previously given. The approximate date on which this
Proxy Statement and the accompanying proxy card will first be mailed to
Shareholders is March 29, 1996.
FINANCIAL STATEMENTS
The audited financial statements of Commonwealth Energy System and
Subsidiary Companies, which include comparative Balance Sheets as of
December 31, 1995 and 1994, Statements of Income and Statements of Cash Flows
for the three years ended December 31, 1995 and the Report of Independent
Public Accountants, are included in Exhibit A of this Proxy Statement.
VOTING SECURITIES
Each Common Share is entitled to one vote. Only Shareholders of record
at the close of business on March 15, 1996 are qualified to vote at the
meeting. There were outstanding as of the record date 10,764,838 Common
Shares.
The Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies owned beneficially 1,678,765 Common Shares representing 15.6% of the
outstanding Common Shares as of January 31, 1996. Members of the Plan are
entitled to give voting instructions with respect to their interests.
OWNERSHIP BY MANAGEMENT OF VOTING SECURITIES
The following table shows the beneficial ownership, reported to the
System as of January 31, 1996, of Common Shares of the System owned by the
Chief Executive Officer and the four other most highly compensated Executive
Officers and, as a group, all Trustees and Executive Officers of the System.
Total
Common Percent of
Name Shares (1) Class
William G. Poist 5,871 0.1%
Russell D. Wright 3,602 0.1%
Kenneth M. Margossian 3,165 0.1%
James D. Rappoli 2,001 0.1%
Leonard R. Devanna 1,912 0.1%
All Trustees and Executive Officers
as a group (15 persons) 26,788 0.2%
<PAGE 4>
(1) Beneficial ownership set forth in this Proxy Statement includes, where
applicable, shares with respect to which voting or investment power is
attributed to an Executive Officer or Trustee because of joint or
fiduciary ownership of the shares or relationship of the Executive Officer
or Trustee to the record owner, such as a spouse, together with shares
held under the Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies.
MATTERS TO BE BROUGHT BEFORE THE MEETING
1-ELECTION OF TRUSTEES
Three Trustees will be elected at the Annual Meeting of Shareholders to
hold office for the ensuing three years in accordance with the Declaration of
Trust, which provides for staggered terms of Trustees of three years each.
The three Trustees elected at this meeting will hold office for a three-year
term and until the election and qualification of their respective successors.
Under the terms of the Declaration of Trust, Trustees are required to be
elected by a plurality vote of the Shareholders.
The Shares represented by the enclosed form of proxy will be voted, and
the persons named in such form of proxy will, unless otherwise directed in the
proxy, vote shares represented by proxies received for the election of the
following nominees, all of whom are presently Trustees:
Peter H. Cressy
William J. O'Brien
William G. Poist
It is not contemplated that any of the three nominees will be unable to
serve; however, should any of the nominees be unable to serve, your proxy will
be voted for the election of a nominee acceptable to the remaining Trustees.
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a January 31,
Name, Principal Occupation and Term of Office Trustee Age 1996
(C) SHELDON A. BUCKLER, formerly Vice Chairman
of the Board and a Director, Polaroid
Corporation, Cambridge, Massachusetts
(Manufacturer of photographic equipment
and supplies); Director, Aseco Corp.;
Nashua Corporation; Parlex Corp. and
Spectrum Information Technologies, Inc.
TERM EXPIRES IN 1998 ............... (1991) 64 2,047
(A) PETER H. CRESSY, Chancellor, University of
(E) Massachusetts Dartmouth, North Dartmouth,
Massachusetts
TERM EXPIRES IN 1996 (NOMINEE)...... (1994) 54 105
(B) HENRY DORMITZER, formerly Executive Vice
(D) President, Wyman-Gordon Company, Worcester,
Massachusetts (Producer of forgings for
aerospace and transportation industries)
TERM EXPIRES IN 1997 ................... (1985) 61 700
<PAGE 5>
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a January 31,
Name, Principal Occupation and Term of Office Trustee Age 1996
(A) BETTY L. FRANCIS, Executive Vice President
(C) and Chief Financial Officer, BancBoston
Mortgage Corporation, Jacksonville, Florida
TERM EXPIRES IN 1998 ................... (1991) 49 100
(C) FRANKLIN M. HUNDLEY, Member and a Managing
(D) Director, Rich, May, Bilodeau & Flaherty,
P.C., Boston, Massachusetts (Attorneys);
Director, The Berkshire Gas Company
TERM EXPIRES IN 1997 ................... (1985) 61 2,425
(A) WILLIAM J. O'BRIEN, President, William J.
(D) O'Brien, Inc., Southborough, Massachusetts
(Management consulting)
TERM EXPIRES IN 1996 (NOMINEE).......... (1994) 63 1,100
WILLIAM G. POIST, President and Chief
Executive Officer of Commonwealth Energy
System and Chairman, Chief Executive Officer
and a Director of its subsidiary companies
TERM EXPIRES IN 1996 (NOMINEE).......... (1992) 62 5,871
(B) MICHAEL C. RUETTGERS, President, Chief
(E) Executive Officer and a Director, EMC
Corporation, Hopkinton, Massachusetts
(Data storage technology); Director,
CrossComm Corporation
TERM EXPIRES IN 1998 ................... (1995) 53 500
(B) GERALD L. WILSON, Vannevar Bush Professor of
(E) Engineering, Massachusetts Institute of
Technology, Cambridge, Massachusetts;
Director, Analogic Corp.
TERM EXPIRES IN 1997 ................... (1985) 56 602
Each of the persons named above has held his or her present position (or
another executive position with the same employer) for more than the past five
years except for Dr. Wilson, who served as Vice President-Corporate Technology
and Manufacturing at Carrier Corporation during 1991-1992 while on a leave of
absence from Massachusetts Institute of Technology, and Mr. O'Brien, who
served as President and Chief Executive Officer of The Hanover Insurance
Company from 1979 to 1992.
During 1995, fees of $568,126 were incurred for legal services rendered
by the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr. Hundley is a
Member and a Managing Director. The firm has been employed in the last fiscal
year and the current fiscal year.
Each Trustee, including nominees, owned beneficially less than one-third
of one percent of the outstanding Common Shares.
- - -------------------------
(A) Member of Audit Committee.
(B) Member of Executive Compensation Committee.
(C) Member of Nominating Committee.
(D) Member of Benefit Review Committee.
(E) Member of Strategic Planning Committee.
<PAGE 6>
COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1995
The following table shows compensation paid by the System and its
subsidiaries to the System's President and Chief Executive Officer and the
four other highest paid Executive Officers of the System whose total
compensation in 1995 exceeded $100,000.
SUMMARY COMPENSATION TABLE
<CAPTION.
Long-Term Compensation (3)
Annual Compensation Awards Payouts
Long-
Options Term
Other /Stock Incen- All
Annual Restr- Apprec- tive Other
Compen- icted iation Plan Compen-
Name and Salary sation Stock Rights (LTIP) sation
Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4)
William G. Poist 1995 $350,000 $95,645 - - - - $14,004
President and Chief 1994 320,000 98,721 - - - - 12,804
Executive Officer of 1993 291,888 78,031 - - - - 11,604
the System and Chair-
man and Chief Exec-
utive Officer of its
subsidiary companies
Russell D. Wright 1995 $231,667 $66,060 - - - - $ 9,269
President and Chief 1994 215,897 60,964 - - - - 8,400
Operating Officer 1993 195,000 53,814 - - - - 7,704
of Cambridge
Electric Light
Company, Canal
Electric Company,
COM/Energy Steam
Company and
Commonwealth
Electric Company
Kenneth M. Margossian 1995 $194,583 $56,040 - - - - $ 7,786
President and 1994 179,917 52,005 - - - - 7,140
Chief Operating 1993 165,000 47,256 - - - - 6,564
Officer of Common-
wealth Gas Company
and Hopkinton LNG Corp.
James D. Rappoli 1995 $164,583 $46,624 - - - - $ 6,586
Financial Vice 1994 151,686 43,196 - - - - 5,880
President and 1993 130,333 36,184 - - - - 5,082
Treasurer of the
System and its
subsidiary companies
<PAGE 7>
SUMMARY COMPENSATION TABLE (CONT'D)
Long-Term Compensation (3)
Annual Compensation Awards Payouts
Long-
Options Term
Other /Stock Incen- All
Annual Restr- Apprec- tive Other
Compen- icted iation Plan Compen-
Name and Salary sation Stock Rights (LTIP) sation
Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4)
Leonard R. Devanna 1995 $154,250 $45,511 - - - - $ 7,714
Vice President - 1994 142,166 41,745 - - - - 5,912
Strategic Planning 1993 133,333 37,542 - - - - 6,603
of the System and
Vice President-
Systems, Planning and
Development of
COM/Energy Services
Company
<FN>
- - --------------------
(1) The amounts in this column represent the aggregate total of cash
compensation received and compensation deferred by the above-named
individuals. Compensation is deferred pursuant to the provisions of the
Employees Savings Plan and the Executive Salary Continuation and Excess
Benefit Plan of Commonwealth Energy System and Subsidiary Companies.
(2) The dollar value of perquisites and other personal benefits, securities
or property totalling either $50,000 or 10% of total annual salary and
bonus, together with various other earnings, amounts reimbursed for the
payment of taxes, and the dollar value of any stock discounts not
generally available are required to be disclosed in this column. In
1995, there were no such perquisites, earnings, reimbursements or
discounts paid or made.
(3) In 1995, the System did not provide to its employees, including
Executive Officers, any payments or awards in the form of restricted
stock, stock options, stock appreciation rights, long-term incentive
plan payouts or other forms of long-term compensation.
(4) The amounts in this column represent the aggregate contributions by the
System and certain subsidiary companies during 1995 on behalf of the
above-named individuals to the Employees Savings Plan and the Executive
Salary Continuation and Excess Benefit Plan of Commonwealth Energy
System and Subsidiary Companies. The Employees Savings Plan of
Commonwealth Energy System and Subsidiary Companies is a defined
contribution plan. The Plan incorporates salary deferral provisions
pursuant to Section 401(k) of the Internal Revenue Code for all
employees who have elected to participate on that basis. The Executive
Salary Continuation and Excess Benefit Plan of Commonwealth Energy
System and Subsidiary Companies is a defined contribution/defined
benefit plan. Unlike the Employees Savings Plan, this Plan is not a
qualified plan under Section 401(a) of the Internal Revenue Code. The
Plan was established to provide an additional benefit to any participant
in the Employees Savings Plan whose benefit under that Plan would be
curtailed by limits in effect under the Internal Revenue Code for
qualified plans. Of the amounts set forth in the "All Other
Compensation" column, $6,162, $9,244, $4,621, $2,311 and $2,890
represent the contributions made on behalf of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna, respectively, by the Employees Savings
Plan. Contributions made on behalf of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna by the Executive Salary Continuation and
Excess Benefit Plan in 1995 equalled $7,842, $25, $3,165, $4,275 and
$4,824, respectively.
<PAGE 8>
PENSION PLAN TABLE
The following table shows annual retirement benefits payable to
employees, including Executive Officers, upon retirement at age 65, in various
compensation and years of service classifications, assuming the election of a
retirement allowance payable as a life annuity from the Pension Plan for
Employees of Commonwealth Energy System and Subsidiary Companies and the
Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy
System and Subsidiary Companies, as of December 31, 1995.
Highest Annual
Consecutive 3-Year
Average Base
Salary of Last Annual Benefit for Years of Service (1)
10 Years 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years
$ 90,000 .... $15,771 $23,656 $ 31,541 $ 39,426 $ 47,312 $ 51,447
120,000 .... 21,271 31,906 42,541 53,176 63,812 69,447
150,000 .... 26,771 40,156 53,541 67,926 80,312 87,447
180,000 .... 32,271 48,406 64,541 80,676 96,812 105,447
210,000 .... 37,771 56,656 75,541 94,426 113,312 123,447
240,000 .... 43,271 64,906 86,541 108,176 129,812 141,447
270,000 .... 48,770 73,156 97,541 121,926 146,312 159,447
300,000 .... 54,270 81,406 108,541 135,676 162,812 177,447
330,000 .... 59,770 89,656 119,541 149,426 179,312 195,447
360,000 .... 65,270 97,906 130,541 163,176 195,812 213,447
390,000 .... 70,770 106,156 141,541 176,926 212,312 231,447
420,000 .... 76,270 114,406 152,541 190,676 228,812 249,447
<FN>
- - -------------
(1) Federal law places certain limits on the amount of benefits which can be
paid from qualified pension plans. Payments made by the System in
excess of the applicable limitations are made pursuant to the terms of
the Executive Salary Continuation and Excess Benefit Plan of
Commonwealth Energy System and Subsidiary Companies. For 1995, the
maximum annual compensation limit under the Pension Plan for Employees
of Commonwealth Energy System and Subsidiary Companies was $150,000, and
the maximum annual benefit under that Plan was $120,000.
The Pension Plan is a non-contributory defined benefit plan. The Plan
is a final average earnings type plan under which benefits reflect the
employee's years of credited service. The employee receives the higher of
either an integrated or non-integrated formula to realize the maximum
retirement benefit applicable to his or her employment history. Both of the
formulae are based on the average of the three highest consecutive January 1
base salaries during the ten-year period preceding the employee's retirement
or termination. Retirement benefits are available to employees on or after
age fifty-five provided the sum of their age and years of service is at least
seventy-five. Messrs. Poist, Wright, Margossian, Rappoli and Devanna have 31,
28, 26, 21 and 14 credited years of service respectively. For the purposes of
calculating the annual retirement benefits of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna pursuant to the Plan, only the amounts set
forth in the summary compensation table as "Salary" are utilized to determine
each Executive Officer's three highest consecutive January 1 base salaries
during the ten-year period preceding the Executive Officer's retirement or
termination.
Each Executive Officer of the System has elected certain pre-retirement
death benefits and supplemental retirement benefits in exchange for waiving
certain standard life insurance benefits (in excess of $50,000), and the
survivor income benefits generally available to all eligible employees. The
alternative program for Executive Officers provides a pre-retirement death
benefit of either: (i) a lump-sum payment of three times annual base salary;
or (ii) fifty percent of monthly base salary for one hundred and eighty
months. The supplemental retirement benefit provides that an Executive
Officer may retire after the attainment of age fifty-five and completion of
ten years of service. Normal retirement at age sixty-five provides an annual
<PAGE 9>
payment equal to thirty-five percent of final base salary per year for life,
or for a period of one hundred and eighty months, whichever is longer.
Benefits are reduced for retirement prior to age sixty-five. The supplemental
retirement benefits are in addition to the amounts shown in the table above
and are not subject to limitation. If termination of employment occurs
following a change in control of the System after the Executive Officer's
completion of ten years of service with the System but before the attainment
of age fifty-five, the Executive Officer shall be entitled to receive upon
attainment of age fifty-five a retirement benefit equal to the amounts that
would have been payable had the Executive Officer remained in the employment
of the System until the date of the Executive Officer's fifty-fifth birthday
and retired on that date. Should the employment of the Executive Officer
terminate for any other reason (other than death) and before completion of ten
years of service and attainment of age fifty-five, there are no benefits
payable under this alternative program for Executive Officers.
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Executive Compensation Committee of the Board of Trustees (the
"Committee") is composed of three independent, non-employee Trustees. The
Committee reviews and approves compensation levels for the System's Chief
Executive Officer and oversees the System's executive compensation programs
affecting all Executive Officers. These programs have been designed in order
to attract, retain, motivate and reward those individuals who are most
responsible for the System's growth and profitability.
Compensation for Executive Officers consists of base salary, annual cash
incentive compensation and long-term incentive awards in the form of
restricted stock awards of Common Shares. Executive Officers also participate
in the Pension Plan and the Employees Savings Plan and receive benefits under
medical and other benefit plans which are available to employees generally.
The Chief Executive Officer's base salary target is designed generally
to match the market median for the utility reference group described in the
next paragraph. The Committee adjusts the Chief Executive Officer's salary in
relation to the salary range target on a subjective basis, through the
evaluation of the same objective criteria used to determine the Chief
Executive Officer's annual incentive award set forth below. Less emphasis is
placed on base salary adjustments than on incentive compensation, consistent
with the Committee's objectives of placing increasingly greater emphasis on
performance based, at-risk incentive compensation.
In setting the Chief Executive Officer's base salary for 1995, the
Committee surveyed and reviewed compensation levels and the reference criteria
relating to such compensation levels within the gas and electric utility
industry. Compensation data and comparisons were provided to the Committee by
an independent consultant and were used by the Committee together with market
compensation data provided by the System's human resources department,
compensation reports contained in proxy materials for companies considered by
the Committee to be similar to the System in size, responsibility and
complexity, and utility industry references such as those provided by the
Edison Electric Institute. Among the reference criteria reviewed by the
Committee in developing external market pay norms were business type
(investor-owned utilities), scope (utilities with revenues of approximately
$500 million to $2 billion) and location (utilities headquartered in the
northeast region of the U.S.). This market reference group of companies
represents a subset of Value Line, Inc.'s utility sample. It is not necessary
for the Committee to formulate a policy with respect to qualifying
compensation paid to Executive Officers for deductibility under Section 162(m)
of the Internal Revenue Code, since the compensation of each Executive Officer
of the System is significantly lower than the $1 million threshold at which
tax deductions are limited.
<PAGE 10>
The System's Annual Incentive Plan provides for awards of up to a
maximum of 30% of annual base salary. The Chief Executive Officer's award for
1995 pursuant to the System's Annual Incentive Plan was determined on a
weighted basis, with two-thirds of the award potential attributable to the
attainment of System goals and objectives, and one-third of the award
potential attributable to individual goals and objectives. For 1995, the
System criteria forming the goals and objectives applicable to the Annual
Incentive Plan were: 1) meeting pre-established targets comparing System
actual net income to budgeted net income for 1995; 2) success in implementing
budgetary constraints in the interest of controlling costs; and 3) meeting
certain pre-established benchmark measures of operation and maintenance
expenses per customer, as compared to a peer group of 18 utility companies
recommended by the System's independent compensation consultant. Each of the
three System goals and objectives are equally weighted, and awards are made
based on meeting, exceeding or reaching maximum attainment of targets.
The goal established for actual net income was to meet or exceed the
approved budgeted amounts. The System's 1995 net income exceeded targeted net
income by 11.9%, resulting in a maximum award. The goal established for cost
control was for operation and maintenance expenses in 1995 to be below the
approved budgeted amounts. This goal was achieved by the System having
reduced actual operation and maintenance expenses to 7.1% below established
budgets, resulting in a maximum award for having exceeded the 5% below budget
maximum target. The goal of maintaining operation and maintenance expenses
per customer within the top 50% of the 18 company industry peer group was
exceeded, as the System was rated the fifth most effective of the 18 companies
in controlling operation and maintenance expenses. In the aggregate, the
goals and objectives applicable to the System component of the Annual
Incentive Plan were rated as 100% achieved.
The individual goals of the Chief Executive Officer for 1995 under the
Annual Incentive Plan included: implementing six specific objectives developed
in 1995 relating to the System's strategic plan, developing and implementing
an effective investor relations program, and strengthening the System's
relationships with state regulatory and elected officials so as to help
advance the System's positions on issues having the greatest impact on the
industry. The Chief Executive Officer's performance relative to achieving
individual goals was rated as 73% achieved, resulting in an aggregate
performance rating of 91% achievement.
The System's Long Term Incentive Plan, approved by shareholders in 1994,
measures performance and provides the potential for awards of Common Shares
over a three-year Plan Period. The first year of the initial Plan Period
established under that Plan was 1994, and as a result no award was made under
the Plan for 1995.
With respect to other Executive Officers, the Chief Executive Officer,
in conjunction with the System's human resources department and independent
consultant, established salary ranges for each Executive Officer. The salary
ranges were based in part upon salaries provided to executive officers in the
System's industry peer group, as reported by the Edison Electric Institute and
from regional salary surveys, so as to establish salary ranges generally in
the median of the peer group. Specific salary levels were then established
through an evaluation of the Executive Officer's performance of goals and
duties. The base salary levels, as recommended by the Chief Executive
Officer, were also reviewed and approved by the Executive Compensation
Committee.
In addition to base salary, the named Executive Officers are also
eligible under the Annual Incentive Plan to receive annual variable incentive
compensation of up to a maximum of 30% of annual base salary. In 1995, the
System goals and objectives constituting the annual performance criteria and
the corresponding weightings which determined eligibility for awards to the
named Executive Officers under the Annual Incentive Plan were the same as
those applicable to the Chief Executive Officer. The individual goals and
<PAGE 11>
objectives of the other Executive Officer Plan participants included various
financial and operating performance standards, such as the continued
maintenance of individual department total annual expenses at amounts not
exceeding approved budgets, the negotiation and execution of settlement
agreements with state regulatory agencies so as to resolve several financial
issues without the need to file and prosecute a rate case, and the
implementation of enhanced procedures designed to further reduce costs and
increase productivity of both in-house and outside legal counsel services.
THE EXECUTIVE COMPENSATION COMMITTEE
Henry Dormitzer, Chairperson
Michael C. Ruettgers
Gerald L. Wilson
<PAGE 12>
COMPARATIVE TOTAL SHAREHOLDER RETURN
Set forth below is a line graph comparing the cumulative total
shareholder return for the System's Common Shares to the cumulative total
return of the S&P 500 Stock Index and a Peer Group Index which is comprised of
88 utility companies (including the System) which are followed by Value Line,
Inc. The entities which comprise the Peer Group are also set forth
hereinafter.
Comparative Five-Year Total Returns
Commonwealth Energy System, S&P 500 and Value Line Peer Group
(Performance results through 12/31/95)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1991-1995) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1990 1991 1992 1993 1994 1995
COM/Energy $100.00 $128.84 $150.74 $174.25 $147.29 $195.20
S&P 500 100.00 130.55 140.72 154.91 157.39 216.42
Peer Group 100.00 129.87 139.63 155.49 136.52 178.91
Assumes $100 invested at the close of trading on the last trading day of
1990 in COM/Energy Common Shares, S&P 500 and the Peer Group. Also
assumes reinvestment of dividends.
Source: Value Line, Inc.
PEER GROUP
Allegheny Power System, Inc. Montana Power Co.
American Electric Power Co., Inc. Nevada Power Co.
Atlantic Energy Inc. New England Electric System
Baltimore Gas and Electric Company New York State Electric & Gas Corp.
Boston Edison Company Niagara Mohawk Power Corporation
Carolina Power & Light Co. NIPSCO Industries Inc.
Centerior Energy Corporation Northeast Utilities
Central Hudson Gas & Electric Corp. Northern States Power Co.
Central Louisiana Electric Company Inc. Northwestern Public Service Co.
Central Maine Power Co. Ohio Edison Co.
Central & South West Corp. Oklahoma Gas & Electric Co.
Central Vermont Public Service Corp. Orange and Rockland Utilities, Inc.
CILCORP Inc. Otter Tail Power Co.
CINergy Corp. Pacific Gas & Electric Co.
CIPSCO Incorporated PacifiCorp.
CMS Energy Corp. PECO Energy Company
<PAGE 13>
Commonwealth Energy System Pinnacle West Capital Corp.
Consolidated Edison Co. of New York, Inc. Portland General Electric Co.
DPL Inc. Potomac Electric Power Co.
Delmarva Power & Light Company PP&L Resources, Inc.
Dominion Resources, Inc. Public Service Co. of Colorado
DQE Public Service Co. of New Mexico
Duke Power Co. Public Service Enterprise Group Inc.
Eastern Utilities Associates Puget Sound Power & Light Co.
Empire District Electric Company Rochester Gas and Electric Corp.
Entergy Corporation St. Joseph Light & Power Co.
Florida Progress SCANA Corp.
FPL Group, Inc. SCEcorp
General Public Utilities Corp. Sierra Pacific Power Co.
Green Mountain Power Corp. The Southern Company
Hawaiian Electric Co., Inc. Southwestern Public Service Co.
Houston Industries Incorporated TECO Energy, Inc.
Idaho Power Co. Texas Utilities Company
IES Industries TNP Enterprises, Inc.
Illinova Corp. Tucson Electric Power Co.
Interstate Power Co. Unicom Corp.
IPALCO Enterprises, Inc. Union Electric Co.
Kansas City Power & Light Co. United Illuminating Co.
KU Energy Corporation UtiliCorp. United Inc.
LG&E Energy Corp. Washington Water Power Co.
Long Island Lighting Co. Western Resources Inc.
MDU Resources Wisconsin Energy Corp.
MidAmerican Energy Company WPL Holdings, Inc.
Minnesota Power & Light Co. WPS Resources Corporation
MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES
The System's Board of Trustees held fourteen meetings throughout 1995.
The Board has an Audit Committee, an Executive Compensation Committee, a
Nominating Committee, a Benefit Review Committee and a Strategic Planning
Committee.
The Audit Committee is composed of Betty L. Francis, Chairperson,
Peter H. Cressy and William J. O'Brien. The Committee held four meetings in
1995. The Committee's functions are to recommend the selection of an
independent public accountant, to review the scope of and approach to audit
work, to review non-audit services provided by the independent public
accountants, and to review accounting principles and practices and the
adequacy of internal controls.
The Executive Compensation Committee is composed of Henry Dormitzer,
Chairperson, Michael C. Ruettgers and Gerald L. Wilson. During 1995 the
Committee held six meetings. This Committee reviews and recommends
compensation and promotional adjustments for certain of the System's personnel
and also reviews and recommends adjustments to the compensation of Trustees.
The Nominating Committee is composed of Sheldon A. Buckler, Chairperson,
Betty L. Francis and Franklin M. Hundley. The Committee held two meetings in
1995. The functions of the Committee are to coordinate suggestions or
searches for potential nominees for the position of Trustee, to review and
<PAGE 14>
evaluate qualifications of potential nominees and to recommend to the Board of
Trustees nominees for vacancies occurring from time to time on the Board of
Trustees. The Committee will consider nominees recommended by Shareholders
upon the timely submission of the names of such nominees with their
qualifications and biographical information forwarded to the Nominating
Committee of the Board of Trustees.
The Benefit Review Committee is composed of Franklin M. Hundley,
Chairperson, Henry Dormitzer and William J. O'Brien. During 1995 the
Committee held one meeting. The Committee was organized to consider and
recommend to the Board of Trustees matters associated with the System's major
funded benefit plans. Functions of the Committee include recommending the
composition of benefit plan boards and reviewing investment policy,
objectives, performance or proposed changes related to the plans.
The Strategic Planning Committee is composed of Gerald L. Wilson,
Chairperson, Peter H. Cressy and Michael C. Ruettgers. The Committee held two
meetings during 1995. The functions of this Committee are to attend strategic
planning sessions, provide support and insight to management and coordinate
management planning activities with the Board of Trustees.
During 1995, each Trustee who was not an employee of the System was
compensated for his or her services as Trustee at the rate of $10,000 per
year, plus $850 for each Trustee and Committee meeting attended. The
Chairpersons of the Audit, Executive Compensation, Benefit Review and
Strategic Planning Committees each received an additional $1,000 during the
year. In addition, the Chairman of the Board received a retainer of $10,000
per year for his services as Chairman of the Board and of the Nominating
Committee. Effective February 23, 1996, non-employee Trustees are compensated
for their services as Trustee at the rate of $12,500 per year, plus $1,000 for
each Trustee and Committee meeting attended. The Chairpersons of the Audit,
Executive Compensation, Benefit Review and Strategic Planning Committees each
receive an additional $1,000 during the year. In addition, the Chairman of
the Board receives a retainer of $20,000 per year for his services as Chairman
of the Board and of the Nominating Committee.
Trustees are entitled to defer all or a specified portion of their
compensation pursuant to the terms of the Deferred Compensation Plan for
Trustees of Commonwealth Energy System. An account is established for each
Trustee electing to participate in the Plan, which account is credited with
the amount which would otherwise be payable to the Trustee as compensation for
the Trustee's services. At the end of each month, interest is credited at an
annual rate equivalent to the weighted average prime lending rate. Upon the
Trustee's retirement, the account balance is paid either in a lump sum or in
annual installments according to the election made by the Trustee. The rights
of the Trustee in the account are not assignable and constitute an unsecured
claim against the general assets of the System.
The Retirement Plan for Trustees of Commonwealth Energy System was
adopted to provide retirement benefits to non-management members of the Board
of Trustees in recognition of their services to the System. Members of the
Board of Trustees who have served as Trustees for at least five years are
eligible to participate in the Plan. Each eligible Trustee qualifies for an
annual retirement benefit payment equal to fifty percent of the annual
retainer fee in effect at retirement (excluding retainers for chairing
committees), plus 10% of the annual retainer fee for each year in addition to
five years served, up to 100% of such fee. The annual retirement benefit
payment is adjusted to reflect the first subsequent increase, if any, in the
annual retainer fee for service on the Board following the Trustee's
retirement. The annual retirement benefit payment becomes vested at the time
of eligibility and is payable to Trustees for a period equal to the greater of
ten years or the number of years of service as a Trustee.
<PAGE 15>
2-AMENDMENTS TO SECTIONS 5 AND 22 OF THE
DECLARATION OF TRUST
There will be presented to Shareholders by the Board of Trustees a
proposal to amend Sections 5 and 22 of the System's Declaration of Trust,
which sections set forth the specific powers of the Board of Trustees, the
present authorized number of Common Shares of beneficial interest and the par
value of such Common Shares. The proposed amendments would change the par
value of each Common Share from Four Dollars ($4.00) to Two Dollars ($2.00),
increase the number of authorized Common Shares from 18,000,000 to 50,000,000
Common Shares, and allow for share splits or reverse share splits and changes
in the par value of Common Shares under certain terms without specific
Shareholder approval. The text of the proposed amendments to Sections 5 and
22 is annexed as Appendix A to this Proxy Statement.
The Trustees of the System have concluded that it would be desirable for
the Common Shares of the System to be split on a two-for-one basis because the
Trustees believe such a split will broaden the market for the System's Common
Shares and result in a wider distribution of the System's Common Shares, both
of which are regarded by the Trustees as being in the best interests of the
System and its Shareholders. In addition, the Trustees have concluded that it
would be desirable to increase the total number of Common Shares authorized
for issuance and for the Trustees of the System to be able to effect future
share splits that would not alter the aggregate par value of the then
outstanding Common Shares without the expense and potential for delay that
could result from the current requirement that splits of Common Shares be
specifically approved by the holders of a majority of such shares.
Accordingly, the Trustees have proposed that the Declaration of Trust of the
System be amended so as to change the number of authorized Common Shares of
the System from 18,000,000 Common Shares, par value $4.00 per share, to
50,000,000 Common Shares, par value $2.00 per share, that share splits be
facilitated by an amendment to Section 5 of the Declaration of Trust, and that
a share split be effected such that each Common Share of the System issued and
outstanding on the record date of such split be changed into two Common
Shares, par value $2.00 per share.
Upon approval by the holders of a majority of the Common Shares, the
proposed amendments will become effective upon the filing of the amended
Declaration of Trust, as required by the terms of the Declaration of Trust and
the laws of the Commonwealth of Massachusetts. The Trustees will vote May 2,
1996 to effect a two-for-one split of the Common Shares. It is presently
expected that the record date of the proposed share split will be May 15,
1996. At the close of business on the record date, the System shall determine
the Shareholders of record on such date. Shareholders of record shall be
entitled to receive an additional Common Share for each Common Share held on
said record date when the share split becomes effective. The effective date
of the share split is expected to be June 5, 1996. The Board of Trustees,
however, may fix a different record or effective date for the share split.
Upon the effective date of the share split, the outstanding certificates
representing Common Shares will represent, in every instance, exactly the same
number of Common Shares of the par value of $2.00 per share. EACH CERTIFICATE
OUTSTANDING PRIOR TO THE RECORD DATE FOR THE SHARE SPLIT WILL CONTINUE TO
REPRESENT THE SAME NUMBER OF SHARES. DO NOT DESTROY YOUR CERTIFICATES AND DO
NOT MAIL THEM TO THE SYSTEM OR ITS TRANSFER AGENT. EACH SUCH CERTIFICATE AND
THE CERTIFICATES FOR ADDITIONAL SHARES TO BE MAILED WILL REPRESENT YOUR TOTAL
SHARES AFTER THE SHARE SPLIT BECOMES EFFECTIVE. It is presently anticipated
that additional certificates representing one additional Common Share of the
par value of $2.00 per share for each Common Share outstanding on the record
date will be issued on the date that the share split becomes effective.
<PAGE 16>
On March 15, 1996, there were 18,000,000 Common Shares authorized, of
which 10,764,838 were issued and outstanding. After giving effect to the
proposed amendment, the number of Common Shares authorized would increase to
50,000,000 and, upon the effective date of the share split, the number of
Common Shares issued and outstanding as aforesaid would double. The increase
in the number of authorized Common Shares will permit the System to respond
more readily to the market for such shares and will assist the System in
effecting transactions involving the issuance of additional Common Shares.
The System, however, currently does not have plans for the issuance of any
additional Common Shares, other than the additional Common Shares that would
be issued to Shareholders in connection with the proposed two-for-one share
split. The System may issue additional Common Shares pursuant to the System's
Dividend Reinvestment and Common Share Purchase Plan or pursuant to a new
issuance of Common Shares made in accordance with the requirements of the
Declaration of Trust and applicable laws.
The change in par value from $4.00 to $2.00, in conjunction with
doubling the number of Common Shares issued and outstanding as aforesaid, will
not result in any changes in the total Shareholders' equity accounts of the
System represented by the Common Shares, Preferred Shares, premium on shares
and retained earnings. Financial statements are not furnished herewith
specifically for the purposes of the proposal, inasmuch as such statements are
not deemed necessary for the exercise of prudent judgment in voting for or
against the proposal, as the proposed amendments, together with the share
split, will occasion no change in and of themselves in the relative holdings
of Shareholders and will cause no change in the aggregate par value of
outstanding Common Shares (or Preferred Shares) of the System.
The System has been advised by counsel that the proposed share split
will not result in any gain or loss for Federal income tax purposes to the
System's Common Shareholders. For Federal income tax purposes, the tax basis
of each Common Share held after the split will be equal to one half of the
basis of each Common Share held prior thereto, and the holder of each Common
Share outstanding immediately prior to the record date will be entitled to
tack the holding period for each such Common Share to each Common Share
received in the proposed share split. For additional information and with
regard to any questions regarding the tax consequences of the proposed share
split, Shareholders should consult their own tax advisors.
Under the current provisions of the Declaration of Trust, approval by
the holders of a majority of the Common Shares is required for any share
split, reverse share split or change in par value involving Common Shares.
The Board of Trustees recommends amending these provisions by the addition of
a new Section 5(w), which will have the effect of deleting the requirement of
obtaining such Common Shareholder approval for share splits, reverse share
splits or changes in par value in connection with share splits that will not
alter the aggregate shareholder equity accounts of the System. The Board
believes that this amendment will help eliminate the expense and potential for
delay that accompanies the present Common Shareholder approval requirement and
should allow the System to respond more readily to the market for its Common
Shares.
The proposed amendments to the Declaration of Trust relating to the
increase in the number of authorized Common Shares and the facilitation of
splits of Common Shares, together with the proposed two-for-one share split,
are presented as one integrated proposal. The adoption of this proposal
requires the affirmative vote of the holders of a majority of the outstanding
Common Shares entitled to be voted at the meeting. There are no rights of
appraisal or similar rights of dissenters with respect to the proposal.
Upon the affirmative vote of the holders of a majority of the
outstanding Common Shares entitled to vote on the proposal, the System will on
May 2, 1996 effect the filing of the amended Declaration of Trust, as required
by the terms of the Declaration of Trust and the laws of the Commonwealth of
Massachusetts and the Trustees will vote to effect the two-for-one share split
as described above.
THE TRUSTEES RECOMMEND A VOTE "FOR" THE APPROVAL OF THE AMENDMENTS.
<PAGE 17>
3-SHAREHOLDER PROPOSAL
The System has been advised that Mr. John Jennings Crapo, Porter Square
Branch, P.O. Box 151, Cambridge, Massachusetts, 02140-0002, holder of 225
Common Shares, proposes to submit the following proposal at the 1996 Annual
Meeting:
It is the judgment of the Shareholders of the Commonwealth Energy System
("C.E.S.") that the C.E.S. DECLARATION OF TRUST dated December 31, 1926 as
Amended be amended and that the Board of Trustees present to Shareholders at
the next Annual Meeting of Shareholders an appropriate amendment to said
Declaration of Trust to accomplish the following:
Trustees elected at the Annual Meeting of Shareholders starting with the
1998 Annual Meeting of Shareholders shall be elected to hold office until the
next annual meeting and until their successors are elected and qualified.
SUPPORTING STATEMENT
Presently I have 225 shares of C.E.S. Common Stock which May 15, 1995
closed at $40.75 and aggregately was worth $9,168.75.
At said stock's closing May 27, 1994 I had 225 said shares and it was
worth $40.50 ($9,112.50).
May 07, 1993 at said stock's closing, I had 225 shares worth $44.50
($10,012.50).
May 08, 1992 at the stock closing I had 225 shares said stock worth
$37.25 ($8,381.25).
May 17, 1991 I had 224 shares of said stock worth $33.37 ($7,476.00).
May 23, 1990 I had 218 shares of said stock at stock's closing worth
$34.50 ($7,521.00).
I've sold none of said shares and plan to continue to own them
throughout the adjournment of the C.E.S. next stockholder meeting at which
time I plan to move proposal's adoption. I plan to attend in person the next
stockholder meeting.
At May 04, 1995 stockholder meeting proponent moved proposal's adoption.
Motion to adopt for the fourth time this proposal has been considered was
seconded by Mr. Henry Dormitzer, Trustee, who is Chairperson of the C.E.S.
Board of Trustees Executive Compensation Committee. At the 1992, 1993 and
1994 C.E.S. stockholder meeting attorney Mr. Richard J. Morrison of the
COM/Energy Services Company seconded Proponent's motion to adopt this
proposal. May 4, 1995, Proponent's Proposal got 16% of the votes of shares
cast in person and by Proxy. These 1995 figures are subject to revision
pending on proponent receiving the tally in writing from Mr. Sullivan, Esq.
whom as General Counsel of COM/Energy Services Co., is Mr. Morrison's
supervisor.
BOARD OF TRUSTEES RECOMMENDATION:
The Board of Trustees recommends a vote AGAINST this proposal for the
following reasons:
This proposal has been submitted at each Annual Meeting since 1991. It
requests that the Board of Trustees submit a proposal to Shareholders at the
1997 Annual Meeting, calling for the repeal of the classified Board, so that
all Trustees would be elected on an annual basis. The classified board was
adopted at the 1987 Annual Meeting, when Shareholders voted to amend the
System's Declaration of Trust to create three classes of Trustees, with an
equal number of Trustees in each class, and to provide that the Trustees would
serve three-year staggered terms, such that three Trustees are eligible for
<PAGE 18>
election each year. The classified board is intended to help to ensure
continued familiarity of Board members with the business, management and
policies of the System, since a majority of the Trustees at any given time
would have prior experience as Board members. These amendments are also
designed to encourage persons seeking to acquire control of the System to
initiate an acquisition through arms-length negotiations with the System's
management and Board of Trustees, by making it more difficult to change the
composition of the Board. Also, the amendments may allow the System's
management to obtain more time and information for evaluating a takeover
proposal, in order to fully protect the interests of the System and its
Shareholders.
As has been its position since this proposal was first submitted, the
Board believes that each Trustee is fully accountable to Shareholders
throughout each term of office, whether that term is three years or one year.
The Board again notes that the classified board system was determined to be of
sufficient merit that the Massachusetts legislature has codified that
system, in its 1990 amendments to the laws pertaining to Massachusetts
business corporations (however, the System, as a Massachusetts Trust, is not
affected by this legislation).
Repeal of the classified Board (which, if the present proposal is
adopted, would actually be pursuant to the acceptance of a proposed Amendment
to the Declaration of Trust to be offered at the 1997 Annual Meeting of
Shareholders) requires the affirmative vote or written consent of three-
quarters of the shares entitled to vote, in accordance with the terms of the
System's Declaration of Trust.
ACCORDINGLY, A VOTE "AGAINST" THE PROPOSAL IS RECOMMENDED.
4-OTHER BUSINESS
The Board of Trustees of the System knows of no matters other than those
set forth in the Notice of the Annual Meeting which are likely to be brought
before the meeting. However, if any other matters of which the Board of
Trustees is not aware are appropriately presented for action, it is the
intention of the persons named in the proxy to vote in accordance with their
judgment on such matters.
<PAGE 19>
MISCELLANEOUS
The independent public accounting firm selected by the Trustees as
Auditor of the System is Arthur Andersen LLP. It is expected that
representatives of Arthur Andersen LLP will be present at the Annual Meeting
with the opportunity to make a statement if they desire to do so and to
respond to appropriate questions.
The cost of soliciting proxies will be borne by the System. A limited
number of regular employees may solicit proxies by telephone or in person
subsequent to the initial solicitation by mail. In addition, the System has
retained the firm of D. F. King to aid in such solicitation of proxies. The
System expects to pay such firm a fee of $5,500 plus expenses. The System
will reimburse banks, brokerage firms and other custodians, nominees and
fiduciaries for reasonable expenses incurred in sending proxy material to
security owners.
The proxy card for a participant in the System's Dividend Reinvestment
and Common Share Purchase Plan includes the number of shares which are
registered in the participant's name and the number of shares beneficially
owned by the participant that are held in the name of the nominee of the
System for the Plan. A participant's vote with respect to the shares
registered in the participant's name is also an instruction by the participant
to the nominee to vote the shares credited to the participant's account under
the Plan.
In order for Shareholder proposals for the 1997 Annual Meeting of
Shareholders to be eligible for inclusion in the System's Proxy Statement,
they must be received by the System at its principal office in Cambridge,
Massachusetts, prior to November 30, 1996.
It is important that proxies be returned promptly to avoid unnecessary
expense. Therefore, Shareholders are urged, regardless of the number of
shares owned, to SIGN, DATE and RETURN the enclosed proxy promptly.
Michael P. Sullivan
Vice President, Secretary
and General Counsel
Cambridge, Massachusetts 02142-9150
March 29, 1996
<PAGE 20>
APPENDIX A
PROPOSED AMENDMENTS TO
SECTIONS 5 and 22 OF THE DECLARATION OF TRUST
Section 5 of the System's Declaration of Trust, "Powers of Trustees",
would be amended by the insertion in Section 5 of a new Subsection (w) which
would read as follows:
Section 5, Subsection (w)--To effect a share split or reverse share
split of the Common Shares of the System and to change the par value of Common
Shares of the System in connection with any such share split or reverse share
split, provided that such share split, reverse share split or change in the
par value of the Common Shares of the System does not result in impairment of
the capital of this trust, as represented by the aggregate of the par value of
its outstanding shares and any cash premiums paid on the sale of such shares;
to effect, without the consent or vote of the holders of any Common Shares or
Preferred Shares, any amendments to this Declaration of Trust necessary to
reflect such a share split, reverse share split or change in par value; and to
issue Common Shares to effect any such share split or reverse share split,
notwithstanding any other provisions of this Declaration of Trust, including,
without limitation, the provisions of Section 22 and Section 44.
In addition, the existing Subsection (w) would be amended by renumbering
it as Subsection (x).
Section 22 of the System's Declaration of Trust would be amended (1) by
deleting the words "eighteen million (18,000,000) Common Shares" in the second
sentence of the first paragraph of said Section 22 and substituting the words
"fifty million (50,000,000) Common Shares" in lieu thereof; (2) by deleting
the words "four dollars ($4) per share" in the second sentence of the first
paragraph of said Section 22 and substituting therein the words "two dollars
($2) per share;" and (3) by deleting the figure "18,000,000" in the first
sentence of the next to last paragraph of said Section 22 and substituting the
figure "50,000,000" in lieu thereof, so that the first paragraph of Section 22
reads in its entirety, as follows:
Section 22.--The beneficial interest in this trust shall be and during
the continuance of this trust shall remain in the owners from time to time of
transferable shares of beneficial interest. The shares of beneficial interest
now authorized shall consist of fifty million (50,000,000) Common Shares
having a par value of two dollars ($2) per share and a class of Cumulative
Preferred Shares having a par value of one hundred dollars ($100) per share
(hereinafter called "Preferred Shares").
and so that the first sentence of the next to last paragraph of said Section
22 reads in its entirety as follows:
Common Shares in addition to the 50,000,000 Shares herein authorized may
be authorized from time to time by vote at a meeting or by the written consent
of the registered holders of a majority of the Common Shares at the time
outstanding and entitled to vote and may be issued from time to time by the
Trustees at not less than par for such consideration and upon such terms and
in such manner as may be determined by such vote or written consent or, if
authorized by such vote or written consent, upon such terms and in such manner
and for such consideration as may be determined by the Trustees.
<PAGE 21>
(LOGO) Commonwealth
Energy System
1995 Financial
Information
Exhibit A
<PAGE 22>
CONTENTS
Published Electronic
Document Document
Management's Discussion and Analysis of Financial
Condition and Results of Operations.................. A-3 23
Management's Report.................................... A-14 37
Report of Independent Public Accountants............... A-14 37
Consolidated Statements of Income...................... A-15 38
Consolidated Balance Sheets............................ A-16 39
Consolidated Statements of Cash Flows.................. A-18 41
Consolidated Statements of Capitalization.............. A-19 42
Consolidated Statements of Changes in Common Shareholders'
Investment and Consolidated Statements of Changes in
Redeemable Preferred Shares.......................... A-20 43
Notes to Consolidated Financial Statements............. A-21 44
Selected Financial Data................................ A-34 59
<PAGE 23>
COMMONWEALTH ENERGY SYSTEM
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Earnings
Earnings and earnings per common share by organizational element for the
three-year period were as follows:
1995 1994 1993
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in Thousands Except Per Share Amounts)
Electric.............. $32,247 $3.03 $32,952 $3.16 $28,742 $2.82
Gas................... 15,352 1.44 12,346 1.19 15,746 1.54
Other................. 2,687 .25 2,500 .24 116 .01
Total........... $50,286 $4.72 $47,798 $4.59 $44,604 $4.37
Parent company earnings and dividends on preferred shares were allocated
among the electric, gas and other operations of the system based on the
Parent's equity investment in each segment.
1995 versus 1994
In 1995, earnings applicable to common shares increased $2.5 million or
5.2% surpassing 1994 as the highest year-end level in the System's history.
The return on average common equity remained strong at 13.3%, down slightly
from the 1994 return of 13.7%. Factors that contributed to the improved
earnings were: 1) a $7.1 million reduction in other operation expense; 2) the
reversal of a reserve related to the system's energy conservation program; and
3) higher steam unit sales. Partially offsetting these factors was an
increase in interest charges related to deferred gas costs and higher short-
term interest rates.
1994 versus 1993
In 1994, earnings improved by 7.2% over 1993. Return on average common
equity for 1994 was 13.7%, equaling the return for 1993. Significant factors
that contributed to the improved earnings were: 1) cost savings of $2.7
million in direct payroll and the absence in 1994 of $3.7 million in severance
pay attributable to a work force reduction implemented at the system's
electric division and services company during the second quarter of 1993; 2)
the reduced undercollection of certain purchased power capacity costs that
resulted in a positive earnings change of $2.9 million; 3) a full year of new
base rates for Cambridge Electric Light Company that became effective in June
1993; 4) an increase of 1.4% in retail electric unit sales; and 5) lower
short-term interest costs of $2.3 million reflecting a 38% decrease in the
debt level to $44.9 million.
The higher earnings in 1994 were achieved despite the decline in
earnings from gas operations that reflected milder weather conditions in the
fourth quarter when degree days were 14% below both normal and the fourth
quarter of the prior year.
Electric Revenues and Unit Sales
Electric operating revenues consisted of:
1995 1994 1993
Operating Revenues - In Thousands
Retail....................... $521,957 $525,326 $513,160
Wholesale.................... 75,217 108,171 105,445
Other........................ 9,873 6,304 5,415
Total.................... $607,047 $639,801 $624,020
<PAGE 24>
Unit sales (in Megawatthours or MWH) were as follows:
% %
1995 Change 1994 Change 1993
Residential.......... 1,752,430 (1.0) 1,770,095 1.5 1,744,181
Commercial........... 2,450,390 1.8 2,406,077 1.2 2,376,968
Industrial and Other. 445,020 - 445,037 2.6 434,875
Total Retail...... 4,647,840 0.6 4,621,209 1.4 4,556,024
Wholesale............ 1,973,543 (48.1) 3,803,786 3.1 3,689,129
Total.............. 6,621,383 (21.4) 8,424,995 2.2 8,245,153
Customers served..... 359,000 0.6 357,000 1.4 352,000
In 1995, electric operating revenues decreased $32.8 million (5.1%) due
mainly to lower fuel oil costs ($32.6 million) caused by a combination of
scheduled maintenance and other repairs to Canal Electric Company's Unit 1
turbine which kept the unit out of service until August 1995. Also
contributing to the decline in revenues were lower conservation and load
management (C&LM) costs of $3.3 million. Offsetting these declines were
increases in revenues related to the recovery of costs associated with a power
contract buy-out ($3.9 million including $1.9 million in carrying charges) and
the recognition in revenues of $2 million in carrying charges associated with
Commonwealth Electric Company's fuel charge stabilization deferral.
In 1995, retail unit sales increased slightly due to higher unit sales
to commercial customers offset somewhat by a 1% decline in sales to
residential customers reflecting the extremely mild weather conditions during
the first quarter of 1995 compared to the record cold experienced during the
same period in 1994. Retail unit sales also reflect modest growth in
customers, mainly in the residential and commercial sectors, resulting from
more housing units and an improved economy that produces added heating and
air-conditioning loads. Growth in unit sales is impacted somewhat by the
system's conservation programs. The system expects that its retail unit sales
growth will average 1% - 2% through the year 2000. Wholesale unit sales
declined significantly due primarily to the decreased availability of Canal
Unit 1. However, fluctuations in the level of wholesale sales have little, if
any, impact on net income.
In 1994, electric operating revenues increased $15.8 million (2.5%) due
primarily to higher fuel and purchased power costs of $11 million (3.2%), new
base rates for Cambridge Electric that became effective June 1, 1993 and
higher total unit sales of 2.2%. Another factor contributing to the increased
level of revenues was a greater recovery of lost base revenues of
approximately $920,000. Partially offsetting these increases was a $1.5
million reduction in C&LM program costs. The rise in wholesale revenues of
$2.7 million or 2.6% was due to a $9.3 million (12.8%) increase in sales to
other utilities offset, in part, by a $5.9 million (21.7%) decline in sales to
the New England Power Pool.
For 1994, retail electric unit sales gained 1.4% as a result of
increased heating demand caused by the extremely cold weather conditions
during the first quarter and greater usage, particularly air-conditioning
load, during the summer months.
Fuel and Purchased Power
To satisfy demand requirements and provide required reserve capacity,
the system supplements its generating capacity by purchasing power on a long
and short-term basis through entitlements pursuant to power contracts with
other New England and Canadian utilities, Qualifying Facilities and other non-
utility generators through a competitive bidding process that is regulated by
the Massachusetts Department of Public Utilities (DPU).
<PAGE 25>
The cost of fuel used for electric generation and electricity purchased
for resale (purchased power) constituted 55% in 1995 and 56% in both 1994 and
1993 of electric operating revenues. During 1995, the 36% decline in fuel
costs was due to reduced consumption at Canal Unit 1 reflecting maintenance
and other repairs discussed previously. The cost of purchased power increased
just 2% in 1995. The fuel charge stabilization deferral ($3.4 million in 1995
compared to $16 million in 1994), implemented in April 1994, was favorably
impacted by the successful renegotiation of a contract with an independent
power producer (IPP) in early 1995 that defers power purchases for a six-year
period coupled with the termination of a second long-term contract with
another IPP through a buy-out arrangement that will provide additional savings
in the future.
For 1994, fuel and purchased power costs increased $11 million or 3.2%
due to higher unit sales and the contractual obligations discussed above prior
to the restructuring of one IPP contract and the termination of a second.
Further, there were additional power purchases from certain natural gas-fired
IPP facilities and reduced generation from Canal Electric's units (for sales
to non-associate utilities).
Energy Mix
The system's energy mix, which includes purchased power, is shown below:
1995 1994 1993
Natural gas................. 41% 38% 29%
Nuclear..................... 25 25 26
Oil......................... 17 24 31
Waste-to-energy............. 10 9 8
Hydro....................... 5 2 3
Coal........................ 2 2 3
Total..................... 100% 100% 100%
The system's energy mix has shifted during the last several years from
oil to natural gas and other fuels due to the requirement to purchase capacity
from IPP facilities and continued efforts to reduce its reliance on oil. The
lower oil component in 1995 reflects Canal Unit 1 being off-line until August.
Gas Revenues, Unit Sales and Cost of Gas Sold
Gas operating revenues consisted of:
1995 1994 1993
Operating Revenues - In Thousands
Firm.............................. $283,264 $298,585 $293,542
Interruptible and other non-firm.. 18,429 20,963 5,377
Transportation.................... 2,547 1,630 1,376
Other............................. 2,713 2,390 2,349
Total......................... $306,953 $323,568 $302,644
<PAGE 26>
Unit sales and transportation volume (in billions of British thermal
units or BBTU) were as follows:
% %
1995 Change 1994 Change 1993
Residential......... 21,336 (0.8) 21,515 (3.3) 22,252
Commercial.......... 10,710 (0.2) 10,728 (1.9) 10,931
Industrial and other 6,412 1.8 6,296 4.3 6,036
Total firm....... 38,458 (0.2) 38,539 (1.7) 39,219
Off-system.......... 4,043 (36.8) 6,401 - -
Quasi-firm.......... 1,906 291.4 487 - -
Interruptible....... 1,215 (36.9) 1,927 1.6 1,896
Total sales...... 45,622 (3.7) 47,354 15.2 41,115
Transportation...... 4,024 82.2 2,208 26.0 1,753
Total............ 49,646 0.2 49,562 15.6 42,868
Customers served.... 233,000 0.4 232,000 - 232,000
For 1995, gas operating revenues decreased $16.6 million or 5.1% due
primarily to an $18.3 million (10.3%) decline in cost of gas sold that
reflects a 3.7% reduction in total sales and a $910,000 (11.8%) decline in
C&LM costs which are recovered through a Conservation Charge decimal that is
part of the existing Cost of Gas Adjustment Clause. Offsetting these
decreases were increases in revenues from transportation volume and quasi-firm
sales ($917,000). Quasi-firm sales are designed for customers with dual-fuel
capability who receive interruptible service in peak demand months and firm
service in off-peak periods. Presently these sales have no impact on net
income. A portion of the margin realized on these sales reduces the cost of
gas sold to firm customers and the remaining amount is deferred pending
approval of a margin-sharing proposal that was filed with the DPU in December
1995. A similar proposal for off-system sales is expected to be filed in
1996.
For 1994, gas operating revenues increased $20.9 million (6.9%) due
primarily to an increase in the cost of gas sold of $20.4 million (13%),
higher C&LM costs ($2.6 million), an increase in transportation revenues
($254,000) and higher interruptible sales.
For 1995, firm unit sales were virtually unchanged, decreasing less than
1% and reflecting a milder than normal first quarter. However, firm unit
sales for the fourth quarter of 1995 increased nearly 22% due to colder
weather conditions compared to the last quarter of 1994. Firm sales gains
from extreme cold weather experienced during the first quarter of 1994 (5.6%)
were substantially offset by the decline in fourth quarter sales (15%) due to
mild weather.
The variations from year to year in weather conditions, particularly
during the heating season, cause gas usage to fluctuate. The system expects
that its unit sales growth, including interruptible, quasi-firm and off-system
sales will average 1% - 2% over the next five years.
In 1995, the increase in the total number of customers reflects growth
in the residential and commercial sectors due mainly to gas conversions and
new construction. In 1994, the total number of customers remained stable.
The fluctuation in interruptible sales during the three-year period reflects
the competitive market conditions for energy resources and the conversion in
1994 of interruptible sales to quasi-firm.
<PAGE 27>
The cost of gas sold in 1995 and 1994 reflects the amortization of
Federal Energy Regulatory Commission (FERC) Order No. 636 (Order 636)
transition costs of $1.3 million and $3.6 million, respectively. Pursuant to
a DPU order issued in October 1993, transition costs related to Order 636
costs were to be recovered with carrying charges, over a four-year period that
began in November 1993. However, the DPU has since allowed Commonwealth Gas
Company to recover costs incurred to May 1, 1995 over a one-year period ending
June 30, 1996. Refer to Note 2(g) of Notes to Consolidated Financial
Statements for additional information.
Steam Operating Revenues
In 1995, steam operating revenues increased $1.6 million or nearly 12%
due primarily to a 10.6% increase in unit sales. An increase in sales to an
expanding biotechnology company contributed to the revenue increase in both
periods.
Other Operation and Maintenance
Other operation in 1995 declined $7.1 million or 3.4% due primarily to
a decline in liability insurance ($5.4 million) due to adjustments to
insurance accruals that reflect better than anticipated experience, lower C&LM
costs ($3.3 million) and a decline in the provision for bad debts reflecting
improved collection experience ($1 million). This was offset, in part, by
higher labor charges ($3.5 million) and postretirement benefit costs ($2.6
million).
In 1994, other operation was virtually unchanged due to the savings
resulting from the second quarter 1993 work force reduction ($2.7 million),
the absence of severance pay incurred in 1993 ($3.7 million) and a decline in
the provision for bad debt expense due to improved collection experience
($600,000). The impact of these factors was offset by higher levels of
insurance and employee benefit costs ($2.4 million), a $1 million increase in
C&LM costs and the impact of inflation on the cost of labor, materials and
other services.
During 1995, maintenance increased $1.9 million (5.2%) reflecting
scheduled maintenance and other repair costs to the Canal Unit 1 turbine
($930,000), maintenance and repairs to Cambridge Electric's Kendall and
Blackstone generating units ($605,000) and transmission and distribution
repairs ($331,000), offset, in part, by lower maintenance and repair costs
relative to Commonwealth Gas ($231,000).
Maintenance in 1994 declined $4.1 million (10%) due primarily to the
timing of scheduled maintenance on the Canal units.
Depreciation and Taxes
In 1995, depreciation expense increased $4 million (9%) due to higher
levels of depreciable plant-in-service. Depreciation expense in 1994
increased $1.7 million (4%) due to slightly higher rates and higher levels of
plant-in-service and the absence of a 1993 adjustment related to Canal
Electric.
Income tax expense decreased $4.6 million or 15.7% due primarily to a
Seabrook-related tax adjustment resulting from a settlement agreement
discussed later in the "Regulation" section, offset, somewhat, by a higher
level of pretax income. In 1994, this same expense increased due to a higher
level of pretax income.
For 1995, there were no significant changes in local property and
payroll and other taxes. In 1994, local property taxes increased $1.1 million
(6.8%) reflecting higher tax rates and assessments. Payroll and other taxes
in 1994 declined nearly $600,000 (6.8%) and reflected the lower number of
employees.
<PAGE 28>
Other Income
For 1995, the expense component of other income decreased due primarily
to the reversal of a reserve that had been established by Commonwealth
Electric which related to certain costs associated with its energy
conservation program, the recovery of which was subsequently approved by the
DPU. Offsetting this decrease was the recognition of a reserve ($2.7 million,
net of tax) related to a system generating station that discontinued
operations and, to a lesser extent, the absence of the equity component of
allowance for funds used during construction (AFUDC) ($341,000).
The substantial decrease in other income during 1994 was primarily due
to the absence of a 1993 reversal of a reserve ($2.5 million, net of tax)
related to Canal Electric's Seabrook 1 investment. The decision to eliminate
this reserve was prompted by the inclusion of Seabrook 1 costs in base rates
at the state level for Cambridge Electric. Also contributing to the decrease
in 1994 was the aforementioned reserve associated with Commonwealth Electric's
energy conservation program. The decline for 1994 was offset, somewhat, by
the equity component of AFUDC ($341,000).
Interest Charges
Interest charges during 1995 increased $1.1 million or 2.6% due
primarily to a higher level of interest on deferred gas costs ($2 million) and
higher short-term interest rates (6.1% for 1995 versus 4.4% in 1994). This
was offset, in part, by lower long-term interest costs ($861,000) reflecting
scheduled sinking fund payments and maturing long-term debt.
For 1994, long-term interest charges increased $2 million (5.4%) due to
a higher level of long-term debt reflecting a full year of new debt issued at
various times in 1993 by Commonwealth Electric, Commonwealth Gas and Hopkinton
LNG Corp. ($134 million). Interest on short-term borrowings declined by $2.3
million (33.5%) despite higher average interest rates (4.4% versus 3.5%) due
to the significantly lower average level of borrowings ($23.9 million versus
$103.1 million) resulting from a higher level of internally generated funds
and the 1993 financing activity.
Liquidity and Capital Resources
Overview
The System is the largest combination public utility holding company in
New England with annual revenues of nearly $1 billion and assets of
approximately $1.4 billion. Capital resources of the System and its
subsidiaries were derived principally from retained earnings and equity funds
provided through the System's Dividend Reinvestment and Common Share Purchase
Plan (DRP). During 1995, nearly 37% of the System's shareholders participated
in the DRP. Supplemental interim funds are borrowed on a short-term basis
and, when necessary, replaced with new equity and/or debt issues through
permanent financing secured on an individual company basis. The System and
its subsidiaries have over the years maintained adequate financial resources
and access to the capital markets and do not anticipate a change in 1996 or
beyond. The System purchases 100% of all subsidiary common stock issues and
provides, to the extent possible, a portion of the subsidiaries' short-term
financing needs. These combined resources provide the funds required for the
subsidiary companies' construction programs, current operations, debt service
and other capital requirements. In March 1994, the System's Board of Trustees
voted to increase the quarterly dividend per common share from 73 cents to 75
cents (2.7%) based on the System's improving financial condition and to
provide shareholders with a fair and reasonable return. The System has paid
dividends without interruption or reduction since 1947 (195 consecutive
quarters).
<PAGE 29>
Effective February 1, 1996, the System's DRP common share requirement
was fulfilled through open market purchases rather than the direct issue of
common shares. An independent purchasing representative acts on behalf of DRP
participants in buying System common shares on the open market at prevailing
market prices. This change, which was prompted by the System's improving
financial condition and reduced need for equity capital, will not effect the
status of DRP participants. The System can, however, return to a direct issue
format if conditions change.
Financial Condition
The system's cash requirements are essentially met through the
generation of cash flows from the sale of electricity, natural gas (including
liquified natural gas) and steam. Daily cash requirements are maintained
through internal generation and short-term borrowings made available through
the System's credit lines with banks. Long-term debt financings and
subsidiary equity issues are used to refinance short-term debt when deemed
appropriate by management.
The system's net cash flow from operating activities for 1995 of
approximately $124.7 million reflects a $25.5 million power contract buy-out
between Commonwealth Electric and an independent power producer that will
provide future savings for customers. Cash required for investing activities
amounted to $81.5 million and related exclusively to expenditures for
additions to property, plant and equipment. For 1995, these expenditures were
funded entirely with internally-generated funds. Cash required for financing
activities consisted primarily of the payment of preferred and common
dividends ($33.1 million) and the refunding of maturing long-term debt and
sinking fund requirements ($33.7 million). Proceeds from short-term
borrowings ($10.8 million) and the sale of common shares through the DRP ($9.5
million) helped to meet the year's cash requirements.
Capital Requirements
The system anticipates that future capital requirements, as shown below,
will be met primarily through internally-generated funds, supplemented by a
combination of debt and equity financings. As conditions warrant, the system
will refinance certain of its outstanding securities based on acceptable
market conditions that would result in a lower cost of debt. The timing and
amount of future debt and equity financings will be dictated by economic and
financial market conditions and the needs of system subsidiaries.
Capital requirements estimated for 1996 through 2000 are as follows:
1996 1997 1998 1999 2000 Total
(Dollars in Millions)
Construction expenditures
including AFUDC............... $ 69 $ 60 $ 60 $ 52 $ 52 $293
Long-term debt maturities....... 33 14 19 20 - 86
Mandatory sinking funds on long-
term debt and preferred shares. 9 8 8 8 7 40
Total........................ $111 $ 82 $ 87 $ 80 $ 59 $419
Sources of Capital
It is anticipated that approximately $378 million or 90% of the
projected capital requirements shown above will be provided from internal
sources, most of which is the collection of accounts receivable generated from
the sale of electricity, gas and steam to retail and wholesale customers.
Other cash sources include periodic short-term borrowings from banks, the sale
of Common Shares through the DRP, rental income and dividends from
investments.
<PAGE 30>
Capital financings during the five-year forecast period are projected
to be issued by subsidiary companies, including common stock issued
exclusively to the System, as follows:
1996 1997 1998 1999 Total
(Dollars in Millions)
Long-term debt..... $ 20 $ 34 $ 9 $ 18 $ 81
Common stock....... 5 - - - 5
Total........... $ 25 $ 34 $ 9 $ 18 $ 86
The System could also raise capital through the issuance of additional
series of preferred shares or additional Common Shares. However, there are no
financings of this type anticipated at this time.
Cash provided by subsidiary company operations continues to be the
primary source of funds. The proceeds from these sources were used to provide
for the payment of dividends and meet capital requirements. The System
believes its capital resources and liquidity are sufficient to meet its
current and projected requirements. In 1995, the subsidiaries of the system
provided $44.8 million to the Parent and proceeds from DRP provided $9.5
million. In 1994, these amounts were $49.7 million and $9.4 million,
respectively.
System companies also maintain lines of credit with banks. At December
31, 1995, short-term notes payable to banks were $55.6 million, an increase of
$10.8 million (24%) over last year. Bank borrowings were used to temporarily
fund construction projects and to repay maturing long-term debt ($25 million
and $10 million in 1995 and 1994, respectively). Arrangements exist for bank
lines of credit which total $80 million in committed lines and $70 million in
uncommitted lines at December 31, 1995, at which time approximately $94.4
million was available to the system. The system's level of bank borrowings is
projected to be approximately $32 million, or 3.6% of total capitalization by
December 31, 2000.
Subsidiary companies also participate in the COM/Energy Money Pool (the
Pool). This is an arrangement whereby subsidiary companies' short-term cash
surpluses are used to help meet the short-term borrowing needs of the utility
subsidiaries. In general, lenders to the Pool receive a higher rate of return
than they otherwise would on such investments, while borrowers pay a lower
interest rate than those available from banks.
Capital Structure
The system's objective is to maintain a capital structure that preserves
an appropriate balance between debt and equity. All long-term debt, preferred
shares and common equity issued by the system is ultimately used to repay
short-term debt. The system's capitalization structure, including short-term
debt, is presented below:
Estimate
1994 1995 2000
(Dollars in Thousands)
Long-term debt.... $443,307 51.2% $410,411 47.1% $368,514 41.9%
Preferred shares.. 14,660 1.7 13,840 1.6 9,740 1.1
Common equity..... 362,997 41.9 390,785 44.9 468,963 53.4
Short-term debt... 44,850 5.2 55,600 6.4 31,918 3.6
Total capitalization $865,814 100.0% $870,636 100.0% $879,135 100.0%
<PAGE 31>
Regulation
Certain System utility subsidiaries operate under the jurisdiction of
the DPU, which regulates retail rates, accounting, issuance of securities and
other matters. In addition, Canal Electric, Cambridge Electric and
Commonwealth Electric file their respective wholesale rates with the FERC.
Commonwealth Electric and Cambridge Electric file quarterly Fuel Charge
(FC) rate schedules, subject to DPU regulation, under which they are allowed
current recovery from retail customers of costs of fuel used in electric
generation and a substantial portion of purchased power, demand, transmission
and C&LM costs.
Commonwealth Gas has a standard seasonal Cost of Gas Adjustment Clause
which provides for the recovery, from firm customers, of purchased gas and
C&LM costs not recovered through base rates. These adjustment charges, which
require DPU approval, are estimated semi-annually and include credits for gas
pipeline refunds and profit margins applicable to interruptible and other non-
firm sales. Actual gas costs are reconciled annually as of October 31, and
any difference is included as an adjustment in the following year.
Revenues collected through base rates are generally designed to
reimburse system utility companies for all costs of operation other than fuel,
gas, the energy portion of purchased power, transmission and C&LM costs while
providing a fair return on capital invested in the business.
Rate Settlement Agreements
In May 1995, the DPU approved settlement proposals sponsored jointly by
Commonwealth Electric, Cambridge Electric and the Attorney General of
Massachusetts which resolved issues related to cost of service, rates,
accounting matters and generating unit performance reviews.
Commonwealth Electric's agreement: (1) implemented a $2.7 million annual
retail base rate decrease effective May 1, 1995 including its share of excess
deferred tax reserves related to Seabrook Unit 1 refunded in May 1995 to
Commonwealth Electric by Canal Electric. Further, the settlement imposes a
moratorium on retail rate filings until October 1998; (2) limits Commonwealth
Electric's return on equity as defined in the settlement, for the period
through December 31, 1997; (3) terminates several 1987-1994 generating unit
performance review proceedings pending before the DPU; (4) amends Commonwealth
Electric's current fuel charge stabilization mechanism to include the deferral
(without carrying charges) of certain long-term purchased power and
transmission capacity costs within the original limits established for the
fuel charge stabilization deferral ($16 million in any given calendar year and
$40 million over the life of the mechanism) that neutralizes the sometimes
volatile impact these costs have had on net income; (5) requires Commonwealth
Electric to fully expense costs relating to postretirement benefits other than
pensions in accordance with Statement of Financial Accounting Standards No.
106 and amortize the deferred balance of $8.6 million over a ten-year period;
(6) provides eligible Economic Development Rate customers with a discount of
up to 30% but also requires these customers to provide Commonwealth Electric
with a five-year notice if they intend to self-generate or acquire electricity
from another provider; and (7) prohibits Commonwealth Electric from seeking
recovery of the costs incurred in realizing cost savings through a 1993 work
force reduction and restructuring, totaling approximately $3 million.
Cambridge Electric's agreement: (1) implemented a $1.5 million refund to
Cambridge Electric's customers through its Fuel Charge during the third and
fourth quarters of 1995 including its share of excess deferred tax reserves
related to Seabrook Unit 1 refunded in May 1995 to Cambridge Electric by Canal
Electric; (2) allows Cambridge Electric to defer certain long-term purchased
power and transmission capacity costs in excess of the amount of such capacity
costs currently included in Cambridge Electric's base rates up to an annual
amount of $2 million for recovery in its next general retail base rate case;
(3) prohibits Cambridge Electric from seeking recovery of costs it incurred in
<PAGE 32>
obtaining cost savings through a work force reduction and restructuring,
totaling approximately $400,000; and (4) includes the DPU's withdrawal of all
related requests, appeals, motions or other issues raised by parties regarding
certain generating unit performance reviews.
The system's management is encouraged by the support provided through
the Office of the Attorney General and believes that these settlements will
eliminate the need for potentially costly litigation and regulatory
proceedings and, by moderating rate impacts and enabling the system to remain
competitive in a changing environment, the settlements are in the best
interest of the system and its customers and shareholders.
Customer Transition Charge Approved
On September 29, 1995, the DPU issued a ruling largely approving four
rate tariffs, including a Customer Transition Charge (CTC), that were filed by
Cambridge Electric on March 15, 1995 following the completion by the
Massachusetts Institute of Technology (MIT) of a 19 MW natural gas-fired
cogeneration facility that will meet approximately 94% of MIT's power, heating
and cooling requirements. The CTC will protect remaining customers from
paying certain costs, often referred to as stranded investment costs, that
were incurred in the event that Cambridge Electric's largest customers
discontinue full service, yet still remain connected for back-up and other
services. These costs include long-term power contracts entered into to meet
projected energy requirements, investments in substations, underground and
overhead lines and current and future decommissioning costs associated with
nuclear plants. This ruling is believed to be the first retail stranded cost
charge approved nationally and follows the DPU restructuring order (discussed
below) which endorsed, in principle, the recovery of stranded investment
costs.
MIT appealed the CTC ruling to the FERC and the Massachusetts Supreme
Judicial Court (SJC). On February 29, 1996, the FERC denied MIT's appeal
seeking relief from paying the CTC. The FERC ruled that the CTC does not
discriminate against MIT as a qualifying facility and that stranded costs are
to be resolved at the state level. The appeal before the SJC is still pending
but the FERC's action will be a factor that the SJC will consider.
Through the CTC, Cambridge Electric will initially recover 75% of net
stranded investment costs as calculated in its proposal. Cambridge Electric's
other rates include a Supplemental Service Rate, a Standby Service Rate and a
Maintenance Service Rate each of which were approved with only minor changes.
Cambridge Electric is encouraged by the DPU's position on recovery of stranded
investment costs and expects to address recovery of the remaining 25% in its
restructuring filing.
Electric Industry Restructuring
On August 16, 1995, the DPU issued an order calling for the
restructuring of the electric utility industry in Massachusetts. The stated
purpose of the restructuring effort is to allow customers more flexibility in
choosing their electric service provider and to develop an efficient industry
structure and regulatory framework that minimizes long-term costs to consumers
while maintaining the safety and reliability of electric services with a
minimum impact on the environment. The electric utility industry will
ultimately be functionally separated into three segments to help meet this
objective: generation, transmission and distribution.
In February 1996, certain utilities submitted required proposals
detailing how they plan to move into a competitive market structure. Since
that time, the DPU has given notice of a generic proceeding that will focus on
many of the policy issues raised in the DPU's original order. Each of the
state's electric utilities, together with other interested parties, will
participate in this proceeding. The purpose of this generic proceeding is to
establish a set of rules governing the restructuring of the electric industry
<PAGE 33>
in Massachusetts. These generic rules would set the basis for the DPU's
review of each of the utility-specific restructuring proposals. The proposal
to be submitted jointly by Commonwealth Electric and Cambridge Electric is due
in September 1996. Management is unable to predict the ultimate outcome of
these proceedings.
On February 15, 1996, in response to the DPU's initial restructuring
order, Commonwealth Electric and Cambridge Electric (the Companies) announced
one element of the proposal entitled "Competitive Challenge" in which the
Companies would voluntarily put their power capacity entitlements (1,140 MW)
to a market test in an effort to develop a competitive market whereby
customers would have the flexibility of choosing their electric supplier. The
proposal calls for the auctioning in a competitive market of entitlements in
all twenty-one contracts, including contracts held by the Companies involving
the System's generating subsidiary Canal Electric. The proposal provides for
total recovery of the difference between the current market value of the
Companies' power contracts and their original unavoidable costs. This
difference, considered to be a stranded cost, would be recovered through a
non-bypassable access charge paid over an appropriate time period by all
customers in the Companies' service areas.
The auction approach has received initial positive reviews from the
Commonwealth of Massachusetts Division of Energy Resources and the Office of
the Attorney General.
Potential Impact of Regulatory Restructuring
Based on the current regulatory framework, the system accounts for the
economic effects of regulation in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." Regulated subsidiaries of the System have
established various regulatory assets in cases where the DPU and/or the FERC
have permitted or are expected to permit recovery of specific costs over time.
These regulatory assets amounted to $129.4 million (9.3% of total assets) as
of December 31, 1995. Similarly, the regulatory liabilities established by
the system are required to be refunded to customers over time. In March 1995,
the Financial Accounting Standards Board issued SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." SFAS No. 121 imposes stricter criteria for regulatory assets by
requiring that such assets be probable of future recovery at each balance
sheet date. Management does not expect that the effects of SFAS No. 121,
which the system adopted on January 1, 1996, will have a material impact on
its financial position or results of operations. However, this conclusion may
change in the future as changes are made in the current regulatory framework
pursuant to the aforementioned electric utility restructuring order issued by
the DPU.
Competition
The system continues to develop and implement strategies that deal with
the increasingly competitive environment facing our gas and electric
businesses. The inherently high cost of providing energy services in the
Northeast has placed the region at a competitive disadvantage as more
customers begin to explore alternative energy supply options. Many state and
federal government agencies are considering implementing programs under which
utility and non-utility generators can sell electricity to customers of other
utilities without regard to previously closed franchise service areas. In
1994, the DPU began an inquiry into incentive ratemaking and in February 1995
opened an investigation into electric industry restructuring that led to the
aforementioned restructuring order.
System company actions in response to the new competitive challenges
have been well received by regulators, business groups and customers.
Commonwealth Gas and Commonwealth Electric have developed and will continue to
develop innovative pricing mechanisms designed to retain existing customers,
add new retail and wholesale customers and expand beyond current markets.
<PAGE 34>
Commonwealth Electric revised its Economic Development Rate which
benefits a number of high-use industrial customers and contributes to economic
development in the area. Another rate provides incentive for business to
expand into previously vacant space and its Rate Stabilization Plan, approved
in 1994, continues to hold the line on costs passed on to customers while
aggressively pursuing other cost reduction measures.
FERC Order 636 marked the beginning of the deregulation and
restructuring of the natural gas industry. In addition to opening up customer
markets to competition, the regulations shifted many supply-related
responsibilities to local distribution companies including direct gas
purchases from suppliers, pipelines and producers, transportation services and
storage services. Commonwealth Gas has developed a gas control and
information system that is one of the most sophisticated purchasing and
tracking systems in the industry. This ability, coupled with aggressive
planning and procurement strategies, will help to secure Commonwealth Gas'
existing market share and permit the expansion of core and non-core supply
capabilities.
Commonwealth Gas' substantial LNG and storage capabilities provide it
with the reliability needed during the coldest winter days and the flexibility
to sell capacity when supply and pricing conditions are favorable.
Commonwealth Gas was able to maximize the use of its gas supply through off-
system sales. In 1995, 4,043 BBTU of gas was sold in the off-system market
and this effort helped to reduce the cost of gas sold to Commonwealth Gas'
firm customers thereby making Commonwealth Gas more competitive in its
traditional markets.
Rate Stabilization Plan
Commonwealth Electric implemented a FC rate settlement on April 1, 1994,
amended in May 1995, that stabilizes its quarterly FC rate during the years
1994 through 1996 at 6.5 cents per KWH and no greater than 6.7 cents per KWH
during 1997. This rate stabilization is achieved through the use of a cost
deferral mechanism that was sponsored jointly by Commonwealth Electric and the
Massachusetts Attorney General and approved by the DPU. The deferred costs
are reflected as a regulatory asset to be recovered, with carrying charges,
over the subsequent six-year period beginning in 1998 pursuant to a recovery
schedule yet to be determined and subject to DPU approval. The deferred
amount, excluding carrying charges, is restricted to a maximum of $40 million
during the settlement period (1994 through 1997) and is further limited to an
annual amount of $16 million. Commonwealth Electric deferred $3,447,000 and
$15,964,000 in 1995 and 1994, respectively. In view of contract
renegotiations with independent power producers, the system does not expect
deferred amounts to exceed $20 million through 1997.
The rate stabilization mechanism is part of a long-term plan to control
Commonwealth Electric's retail rates. This plan will help eliminate the
disincentive for economic development resulting from a volatile and unpredict-
able FC rate. The stabilized FC rate should enable current and prospective
customers to better plan their business and personal finances in a more
efficient and effective manner. In addition to the Massachusetts Attorney
General, this proposal was widely supported by various business and customer
groups and other political interests.
Economic Development
Realizing a healthy regional economy benefits not only businesses but
all area residents, Commonwealth Electric actively encourages economic growth
by working in partnership with communities and businesses, providing resources
and incentives to help the region's economy. Commonwealth Electric also
funded the development of a business plan that focuses on improving
infrastructure, regulation, access to capital, marketing and promotion,
cooperation and leadership on Cape Cod.
<PAGE 35>
In an effort to foster industrial development in its service area,
Commonwealth Electric began offering an Economic Development Rate in October
1991 to new or existing industrial customers who have an electric demand of
500 kilowatts or more and meet specific financial and other criteria. As of
December 31, 1995, twenty-five commercial and industrial customers were
benefitting from this special rate. This is up approximately 17% over 1994.
The rate is available for a six-year term. Revenues were lower by $1.5
million, $1.7 million and $1.5 million in 1995, 1994 and 1993, respectively.
These amounts represent the difference between what certain commercial and
industrial customers would have paid prior to the availability of this rate.
Commonwealth Electric also offers a Vacant Space Rate that is available to
qualifying small commercial and industrial customers who establish loads in
previously unoccupied building space.
Marketing of Residential and Commercial Specialty Products
As part of its commitment to meet the demands of a new, competitive
electric market, Commonwealth Electric began marketing products specially
designed for the residential and commercial customer. Products offered to
residential customers through Commonwealth Electric include carbon monoxide
detectors and a home safety kit containing tests for: lead in paint and water;
radiation leaks from microwave ovens; drinking water safety; carbon monoxide;
and radon gas.
Products offered to smaller commercial customers include: an energy
consumption monitor that will monitor two devices simultaneously, such as
refrigeration and air-conditioning equipment and at the same time provide
information about energy consumption and cost; a voltage scanner for sensitive
equipment; electric power surge protectors; and power-plug loggers that
monitor the KWH usage on a particular piece of electrical equipment.
For larger commercial or industrial customers, enhanced services focus
on information systems, utilizing real-time monitoring software so customers
are educated about their usage patterns, electrotechnologies in manufacturing
processes so customers can increase profits and competitive advantages in the
marketplace, engineering services, energy audit services, maintenance
management programs, and demand-side management programs.
In addition, Commonwealth Electric is actively involved with the Chamber
of Commerce in each operating district as well as local and state economic
development offices. Information on foreign trade zones, tax incentive
programs and financial and lending institutions is provided to businesses to
attract and encourage relocation or expansion in Commonwealth Electric's
region. Commonwealth Electric is also involved in an outreach program that
encourages businesses in Canada to consider relocation to southeastern
Massachusetts.
Quasi-firm and Off-system Gas Sales Services, and New Technology
In August 1994, Commonwealth Gas received regulatory approval for a new
quasi-firm sales service designed for customers with dual-fuel capability that
provides a level of service between full firm and interruptible. In exchange
for prices lower than full firm service, quasi-firm customers will receive
interruptible service in peak demand months and firm service in off-peak
months. These arrangements provide Commonwealth Gas and its customers greater
flexibility in supply management and pricing options. During 1995,
Commonwealth Gas' quasi-firm customers purchased 1,906 BBTU of gas which
represented approximately 4% of total gas unit sales.
Also during 1995, Commonwealth Gas was able to maximize the use of its
gas supply portfolio through off-system sales and capacity release. For 1995,
4,043 BBTU of gas was sold in the off-system market and 10,352 BBTU of
pipeline capacity was released. These efforts helped to reduce the cost of
gas sold to Commonwealth Gas' firm customers to more competitive levels in its
traditional markets. During 1995, Commonwealth Gas continued to drive its
costs down by renegotiating a good portion of its gas supply contracts.
<PAGE 36>
Commonwealth Gas continues to reduce costs and improve service through
state-of-the-art technology. Some of the examples of cost-effective
technology presently in use include: (1) Automated Meter Reading (AMR) which
has dramatically lowered meter reading costs, improved the rate at which
meters are read, and enhanced customer convenience. To date, 80% of
Commonwealth Gas' meters are equipped with AMR technology and the read rate
has improved to nearly 100%; (2) a new trenchless technology that enables
Commonwealth Gas to maintain or upgrade its distribution system with a minimum
of cost and disturbance with a device known as a "bullet" that allows the
replacement of old gas lines with polyethylene pipe, eliminating the need for
costly and time-consuming street excavations; and (3) the use of a miniature
camera that inspects the inside walls of low pressure mains without
interrupting service to customers and replaces the more traditional method
which involved costly digging and manual inspection to find problem areas.
Environmental Matters
Commonwealth Gas is participating in the assessment of a number of
former manufactured gas plant (MGP) sites and alleged MGP waste disposal
locations to determine if and to what extent such sites have been contaminated
and whether Commonwealth Gas may be responsible for remedial actions.
The costs associated with the assessment and clean-up of these sites are
recoverable in rates through the cost of gas adjustment clause over a seven-
year amortization period without carrying costs pursuant to a 1990 DPU order.
Commonwealth Gas has recorded an estimated $2.6 million liability that
reflects its best estimate (based on current information) of the costs to be
incurred in connection with assessment and remediation activities identified
to this point. Commonwealth Gas has also recorded a regulatory asset in
anticipation of recovery of these costs. Commonwealth Gas is unable to
predict the total cost to ultimately resolve these matters, due to significant
uncertainty as to the actual site conditions and the extent of any associated
remediation activities and the assignment of responsibility. However, it is
expected that all such costs will continue to be recovered in rates as
described above.
Commonwealth Gas and certain other system subsidiaries are also involved
in other known or potentially contaminated sites where the associated costs
may not be recoverable in rates and have recorded an estimated liability (and
a charge to operations) of $1.6 million to cover the expected costs associated
with assessment and remediation activities. These estimates are reviewed and
adjusted periodically as further investigation and assignment of
responsibility occurs. The system is unable to estimate its ultimate
liability for future environmental remediation costs. However, in view of the
system's current assessment of its environmental responsibilities, existing
legal requirements and regulatory policies, management does not believe that
these matters will have a material adverse effect on the system's results of
operations or financial position.
In October 1993, Canal Electric reached an agreement with Montaup
Electric Company (the 50% owner of Canal Unit 2) and Algonquin Gas
Transmission Company (AGT) to build a natural gas pipeline that will serve the
Canal Unit 2 generating station. Unit 2 will be modified to burn gas in
addition to oil. The first phase of the project was completed in July 1995
when a 1,400 foot gas pipeline was installed 80 feet below the surface of the
Cape Cod Canal. The second phase involves the construction of a four-mile
pipeline that will ultimately connect Unit 2 to the AGT pipeline system. The
project will improve air quality on Cape Cod, enable the plant to exceed the
stringent 1995 air quality standards established by the Massachusetts
Department of Environmental Protection and will strengthen Canal Electric's
bargaining position as it seeks to secure the lowest-cost fuel for its
customers. Plant conversion and pipeline construction are expected to be
completed in mid-1996.
<PAGE 37>
MANAGEMENT'S REPORT
The consolidated financial statements presented herein are
representations of the management of Commonwealth Energy System. Management
recognizes its responsibility for the preparation and presentation of
financial statements in conformity with generally accepted accounting
principles. To fulfill this responsibility, management maintains a system of
internal accounting controls, including established policies and procedures
and a comprehensive internal auditing program to evaluate the adequacy and
effectiveness of accounting and operating controls, compliance with system
policies and procedures and the safeguarding of system assets.
The responsibility of our independent auditors' examination is limited
to the expression of an opinion as to the fairness of the consolidated
financial statements presented. The independent auditors are selected by the
Board of Trustees and report their findings thereto through the Audit
Committee, which is comprised of three outside Trustees. The Board of
Trustees is responsible for ensuring that both the independent auditors and
management fulfill their respective responsibilities as they pertain to these
consolidated financial statements.
James D. Rappoli,
Financial Vice President
February 16, 1996.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees of Commonwealth Energy System:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of COMMONWEALTH ENERGY SYSTEM (a
Massachusetts trust) and subsidiary companies as of December 31, 1995 and
1994, and the related consolidated statements of income, cash flows, changes
in common shareholders' investment and changes in redeemable preferred shares
for each of the three years in the period ended December 31, 1995. These
consolidated financial statements are the responsibility of the System and
subsidiary companies' management. Our responsibility is to express an opinion
on these consolidated 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Commonwealth Energy System and subsidiary companies as of December 31, 1995
and 1994, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
Arthur Andersen LLP
Boston, Massachusetts
February 16, 1996.
<PAGE 38>
Consolidated Statements of Income
For the Years Ended December 31, 1995, 1994 and 1993
1995 1994 1993
(Dollars in Thousands)
Operating Revenues
Electric $607,047 $639,801 $624,020
Gas 306,953 323,568 302,644
Steam and other 17,355 15,867 14,035
931,355 979,236 940,699
Operating Expenses
Fuel used in electric production,
principally oil 57,820 90,414 90,346
Electricity purchased for resale 274,795 269,418 258,490
Cost of gas sold 158,835 177,150 156,709
Other operation 200,363 207,502 207,053
Maintenance 38,414 36,522 40,574
Depreciation 48,170 44,188 42,480
Amortization 5,917 5,868 5,764
Taxes-
Local property 17,573 17,467 16,350
Income 24,574 29,154 26,921
Payroll and other 8,284 8,087 8,676
834,745 885,770 853,363
Operating Income 96,610 93,466 87,336
Other Income (Expense) (606) (1,024) 2,449
Income Before Interest Charges 96,004 92,442 89,785
Interest Charges
Long-term debt 38,581 39,442 37,416
Other interest charges 6,884 4,475 6,730
Allowance for borrowed funds used during
construction (857) (443) (195)
44,608 43,474 43,951
Net Income 51,396 48,968 45,834
Dividends on preferred shares 1,110 1,170 1,230
Earnings Applicable to Common Shares $ 50,286 $ 47,798 $ 44,604
Average Number of Common Shares
Outstanding 10,655,918 10,413,781 10,215,614
Earnings Per Common Share $4.72 $4.59 $4.37
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 39>
Consolidated Balance Sheets
December 31, 1995 and 1994
1995 1994
(Dollars in Thousands)
Assets
Property, Plant and Equipment, at original cost
Electric $1,105,502 $1,047,140
Gas 346,990 338,111
Other 63,132 59,213
1,515,624 1,444,464
Less-Accumulated depreciation and amortization 497,627 461,310
1,017,997 983,154
Construction work in progress 10,154 15,835
Nuclear fuel in process 122 139
1,028,273 999,128
Leased Property, net 14,931 15,729
Equity in Corporate Joint Ventures
Nuclear electric power companies (2.5% to 4.5%) 9,814 9,818
Other investments 3,400 3,830
13,214 13,648
Current Assets
Cash 4,319 7,722
Accounts receivable, less reserves of $8,040,000
in 1995 and $7,956,000 in 1994 105,377 92,157
Unbilled revenues 31,642 33,161
Inventories, at average cost-
Electric production fuel oil 1,683 1,689
Natural gas 17,339 24,161
Materials and supplies 6,516 7,736
Prepaid taxes 9,044 8,806
Other 6,799 5,858
182,719 181,290
Deferred Charges 150,964 134,921
$1,390,101 $1,344,716
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 40>
Consolidated Balance Sheets
December 31, 1995 and 1994
1995 1994
(Dollars in Thousands)
Capitalization and Liabilities
Capitalization (See separate statement)
Common share investment $ 390,785 $ 362,997
Redeemable preferred shares, less current
sinking fund requirements 13,840 14,660
Long-term debt, less current sinking fund
requirements and maturing debt 377,181 418,307
781,806 795,964
Capital Lease Obligations 13,291 14,098
Current Liabilities
Interim Financing-
Notes payable to banks 55,600 44,850
Maturing long-term debt 33,230 25,000
88,830 69,850
Other Current Liabilities-
Current sinking fund requirements 9,103 6,793
Accounts payable 134,908 117,953
Accrued taxes-
Local property and other 9,580 10,293
Income 22,007 7,654
Accrued interest 8,389 7,251
Dividends declared 8,073 7,894
Other 18,945 23,359
211,005 181,197
299,835 251,047
Deferred Credits
Accumulated deferred income taxes 170,182 160,944
Unamortized investment tax credits 27,903 29,304
Other 97,084 93,359
295,169 283,607
Commitments and Contingencies
$1,390,101 $1,344,716
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 41>
Consolidated Statements of Cash Flows
For the Years Ended December 31, 1995, 1994 and 1993
1995 1994 1993
(Dollars in Thousands)
Operating Activities
Net income $ 51,396 $ 48,968 $ 45,834
Effects of noncash items-
Depreciation and amortization 50,799 53,727 53,088
Deferred income taxes, net 4,182 14,846 17,059
Investment tax credits, net (1,401) (1,470) (1,500)
Earnings from corporate joint ventures (1,633) (1,750) (1,642)
Dividends from corporate joint ventures 2,067 1,651 1,981
Change in working capital, exclusive of cash-
Accounts receivable and unbilled revenues (11,701) 11,624 (3,961)
Prepaid income taxes 14,353 8,016 7,321
Prepaid (accrued) local property and
other taxes (950) 616 301
Accounts payable and other 23,274 32,437 4,642
Power contract buy-out (25,500) - -
Fuel charge stabilization deferral (3,447) (15,964) -
Deferred postretirement benefit and
pension costs (4,479) (8,536) (10,175)
Transition costs, net 11,390 (2,585) (8,805)
All other operating items 16,321 (15,017) (17,451)
Net cash provided by operating activities 124,671 126,563 86,692
Investing Activities
Additions to property, plant and
equipment (exclusive of AFUDC)-
Electric (60,841) (37,997) (29,490)
Gas (16,143) (17,993) (23,099)
Other (3,659) (1,843) (1,796)
Allowance for borrowed funds used during
construction (857) (443) (195)
Net cash used for investing activities (81,500) (58,276) (54,580)
Financing Activities
Sale of common shares 9,534 9,434 7,118
Payment of dividends (33,142) (32,475) (31,101)
Proceeds from (payment of) short-term
borrowings, net 10,750 (27,125) (93,625)
Long-term debt issues - - 134,000
Retirement of long-term debt and preferred
shares through sinking funds (8,716) (6,406) (6,419)
Long-term debt issues refunded (25,000) (10,000) (37,600)
Net cash used for financing activities (46,574) (66,572) (27,627)
Net increase (decrease) in cash (3,403) 1,715 4,485
Cash at beginning of period 7,722 6,007 1,522
Cash at end of period $ 4,319 $ 7,722 $ 6,007
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of capitalized amounts) $ 42,051 $ 41,022 $ 39,685
Income taxes $ 12,918 $ 17,563 $ 13,528
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 42>
Consolidated Statements of Capitalization
December 31, 1995 and 1994
1995 1994
(Dollars in Thousands)
Common Share Investment
Common shares, $4 par value-
Authorized-18,000,000 shares
Outstanding-10,764,134 shares in 1995
and 10,525,897 shares in 1994 $ 43,056 $ 42,103
Amounts paid in excess of par value 111,749 103,168
Retained earnings 235,980 217,726
Total common share investment 390,785 362,997
Redeemable Preferred Shares,
Cumulative, $100 Par Value
Series A, 4.80% 2,760 2,880
Series B, 8.10% 4,160 4,320
Series C, 7.75% 7,740 8,280
Less-Current sinking fund requirements (820) (820)
Total redeemable preferred shares 13,840 14,660
Long-term Debt
System
Notes due-
1995, 4.70% - 15,000
Senior Notes due-
1995, 10.39% - 10,000
1997, 10.48% 10,000 10,000
1998, 10.45% 10,000 10,000
1999, 10.58% 10,000 10,000
Less-Maturing long-term debt - (25,000)
Total System long-term debt 30,000 30,000
Subsidiary companies
Mortgage Bonds, collateralized by property of
operating subsidiaries, due-
1996, 7% 3,800 4,560
1996, 8.99% 10,000 10,000
2001, 8.99% 21,750 25,400
2006, 8.85% 35,000 35,000
2020, 7 3/8% 10,000 10,000
2020, 9 7/8% 40,000 40,000
2020, 9.95% 25,000 25,000
2033, 7.11% 35,000 35,000
Notes due-
1996, 9.97% 20,000 20,000
1997, 6 1/4% 4,320 4,380
1998, variable rate (6.5625% in 1995 and
6.75% in 1994) 9,000 9,000
1999, 8.04% 10,000 10,000
2002, 7 3/4% 2,700 2,800
2002, 9.30% 30,000 30,000
2003, 7.43% 15,000 15,000
2004, 9.50% 15,000 15,000
2007, 8.70% 5,000 5,000
2007, 9.55% 10,000 10,000
2008, 7.70% 10,000 10,000
2012, 9.37% 17,895 18,947
2013, 7.98% 25,000 25,000
2014, 9.53% 10,000 10,000
2019, 9.60% 10,000 10,000
2023, 8.47% 15,000 15,000
Less-Maturing long-term debt (33,230) -
Current sinking fund requirements (8,283) (5,973)
Unamortized discount, net (771) (807)
Total subsidiary companies' long-term debt 347,181 388,307
Total long-term debt 377,181 418,307
Total capitalization $781,806 $795,964
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 43>
Consolidated Statements of Changes in Common Shareholders' Investment
For the Years Ended December 31, 1995, 1994 and 1993
Amounts
Par Paid in
Value Excess
$4 Per of Par Retained
Shares Share Value Earnings Total
(Dollars in Thousands)
Balance December 31, 1992 10,141,675 $40,567 $ 88,152 $186,500 $315,219
Add (Deduct)-
Net income - - - 45,834 45,834
Sale of shares 153,402 613 6,505 - 7,118
Cash dividends declared-
Common shares-$2.92 per share - - - (29,871) (29,871)
Preferred shares - - - (1,230) (1,230)
Balance December 31, 1993 10,295,077 41,180 94,657 201,233 337,070
Add (Deduct)-
Net income - - - 48,968 48,968
Sale of shares 230,820 923 8,511 - 9,434
Cash dividends declared-
Common shares-$3.00 per share - - - (31,305) (31,305)
Preferred shares - - - (1,170) (1,170)
Balance December 31, 1994 10,525,897 42,103 103,168 217,726 362,997
Add (Deduct)-
Net income - - - 51,396 51,396
Sale of shares 238,237 953 8,581 - 9,534
Cash dividends declared-
Common shares-$3.00 per share - - - (32,032) (32,032)
Preferred shares - - - (1,110) (1,110)
Balance December 31, 1995 10,764,134 $43,056 $111,749 $235,980 $390,785
Consolidated Statements of Changes in Redeemable Preferred Shares
For the Years Ended December 31, 1995, 1994 and 1993
Authorized and Outstanding
Cumulative Preferred Shares-$100 Par Value
Series A Series B Series C Total
4.80% 8.10% 7.75% Shares
Balance December 31, 1992 31,200 46,400 93,600 171,200
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1993 30,000 44,800 88,200 163,000
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1994 28,800 43,200 82,800 154,800
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1995 27,600 41,600 77,400 146,600
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 44>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Significant Accounting Policies
(a) General
Commonwealth Energy System (the System) is an exempt public utility
holding company with investments in four operating public utility companies
located in central, eastern and southeastern Massachusetts. The System is the
parent company and, together with its subsidiaries, is collectively referred
to as "the system." System electric operations are involved in the production
and sale of electricity to 359,000 customers in 41 communities including New
Bedford, Plymouth, Cambridge and the geographic area comprising Cape Cod. Gas
operations serve 233,000 customers in 49 communities including New Bedford,
Cambridge, Plymouth and Worcester. In addition to the utility companies, the
system includes a steam distribution company, five real estate trusts and a
company engaged in the operation of LNG facilities.
The system has 2,096 regular employees including 1,235 (59%) who are
represented by various collective bargaining units. Agreements with three
units representing approximately 34% of regular employees are scheduled to
expire in 1996. Employee relations have generally been satisfactory.
(b) Principles of Consolidation and Accounting
The consolidated financial statements include the accounts of the System
and all of its subsidiary companies. All significant intercompany accounts
and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(c) Regulatory Assets and Liabilities
The system's operating utility companies are regulated as to rates,
accounting and other matters by various authorities, including the Federal
Energy Regulatory Commission (FERC) and the Massachusetts Department of Public
Utilities (DPU).
Based on the current regulatory framework, the system accounts for the
economic effects of regulation in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." Regulated subsidiaries of the System have
established various regulatory assets in cases where the DPU and/or the FERC
have permitted or are expected to permit recovery of specific costs over time.
Similarly, the regulatory liabilities established by the system are required
to be refunded to customers over time. In March 1995, the Financial
Accounting Standards Board issued SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No.
121 imposes stricter criteria for regulatory assets by requiring that such
assets be probable of future recovery at each balance sheet date. Management
does not expect that the effects of SFAS No. 121, which the system adopted on
January 1, 1996, will have a material impact on its financial position or
results of operations. However, this conclusion may change in the future as
changes are made in the current regulatory framework pursuant to an electric
utility restructuring order issued by the DPU in August 1995.
<PAGE 45>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The principal regulatory assets included in deferred charges at December
31, 1995 and 1994 were as follows:
1995 1994
(Dollars in Thousands)
Postretirement benefit costs including
pensions $ 24,608 $ 20,129
Power contract buy-out 23,838 -
Fuel charge stabilization 22,063 16,638
Deferred income taxes 14,106 5,537
FERC Order 636 transition costs 11,711 19,201
Yankee Atomic unrecovered plant and
decommissioning costs 10,135 18,368
Seabrook related costs 9,511 12,648
Other 13,464 19,216
$129,436 $111,737
The regulatory liabilities, reflected in the accompanying balance sheets
and related to deferred income taxes, were $14 million and $17.3 million at
December 31, 1995 and 1994, respectively.
As of December 31, 1995, $96.2 million of the system's regulatory assets
and all of its regulatory liabilities are reflected in rates charged to
customers over a weighted average period of approximately 10 years. In
addition, the fuel charge stabilization deferral is expected to be recovered
over a six-year period beginning in April 1998, pursuant to a yet to be
determined recovery schedule and subject to final DPU approval. System
companies intend to request and expect to receive approval for recovery of
their remaining regulatory assets in future rate proceedings.
(d) Equity Method of Accounting
The system uses the equity method of accounting for investments in
corporate joint ventures due, in part, to its ability to exercise significant
influence over operating and financial policies of these entities. Under this
method, it records as income the proportionate share of the net earnings of
the joint ventures with a corresponding increase in the carrying value of the
investment. The investment is reduced as cash dividends are received. The
system conducts business with the corporate joint ventures in which it has
investments, principally four nuclear generating facilities located in New
England and a 3.8% interest in Hydro-Quebec Phase II.
(e) Operating Revenues
Customers are billed for their use of electricity and gas on a cycle
basis throughout the month. To reflect revenues in the proper period, the
estimated amount of unbilled sales revenue is recorded each month.
System utility companies are generally permitted to bill customers for
costs associated with purchased power and transmission, fuel used in electric
production, gas, conservation and load management and environmental costs.
The amount of such costs incurred but not yet reflected in customers' bills,
which totaled $801,000 in 1995 and $306,000 in 1994, is recorded as unbilled
revenues.
<PAGE 46>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(f) Depreciation
Depreciation is provided using the straight-line method at rates
intended to amortize the original cost and the estimated cost of removal less
salvage of properties over their estimated economic lives. The average
composite depreciation rates were as follows:
1995 1994 1993
Electric 3.52% 3.30% 3.28%
Gas 2.90 2.98 2.95
Steam 3.91 3.94 3.61
LNG 3.20 3.12 3.07
(g) Allowance for Funds Used During Construction
Under applicable rate-making practices, system companies are permitted
to include an allowance for funds used during construction (AFUDC) as an
element of their depreciable property costs. This allowance is based on the
amount of construction work in progress that is not included in the rate base
on which utility companies earn a return. An amount equal to the AFUDC
capitalized in the current period is reflected in the accompanying
consolidated statements of income.
While AFUDC does not provide funds currently, these amounts are
recoverable in revenues over the service life of the constructed property.
The amount of AFUDC recorded was at a weighted average rate of 7.1% in 1995,
9.1% in 1994 and 3.9% in 1993.
(2) Commitments and Contingencies
(a) Construction
The system is engaged in a continuous construction program presently
estimated at $293 million for the five-year period 1996 through 2000. Of that
amount, $69.3 million is estimated for 1996. The program is subject to
periodic review and revision.
(b) Seabrook Nuclear Power Plant
The system's 3.52% interest in the Seabrook nuclear power plant is owned
by Canal Electric Company (Canal), a wholesale electric generating subsidiary,
to provide for a portion of the capacity and energy needs of affiliates
Cambridge Electric Light Company (Cambridge) and Commonwealth Electric Company
(Commonwealth Electric). Canal is recovering 100% of its Seabrook 1
investment through a power contract with Cambridge and Commonwealth Electric
pursuant to FERC and DPU approval.
<PAGE 47>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Pertinent information with respect to Canal's joint-ownership interest
in Seabrook 1 and information relating to operating expenses which are
included in the accompanying financial statements are as follows:
1995 1994
(Dollars in Thousands)
Utility plant-in-
service $232,547 $232,374 Plant capacity (MW) 1,150
Nuclear fuel 20,138 18,500 Canal's share:
Accumulated depreciation Percent interest 3.52%
and amortization (50,230) (41,654) Entitlement (MW) 40.5
Construction work in In-service date 1990
progress 946 651 Operating license
$203,401 $209,871 expiration date 2026
1995 1994 1993
(Dollars in Thousands)
Operating expenses:
Fuel $ 2,353 $ 1,939 $ 3,853
Other operation 4,292 4,340 4,580
Maintenance 1,376 1,688 893
Depreciation 6,542 6,531 6,522
Amortization 1,319 1,320 1,319
$15,882 $15,818 $17,167
Canal and the other joint owners have established a decommissioning fund
to cover decommissioning costs. The estimated cost to decommission the plant
is $431.6 million in current dollars. Canal's share of this liability
(approximately $15.2 million), less its share of the market value of the
assets held in a decommissioning trust (approximately $1.5 million), is
approximately $13.7 million at December 31, 1995.
(c) Price-Anderson Act
Under the Price-Anderson Act (the Act), owners of nuclear power plants
have the benefit of approximately $8.9 billion of public liability coverage
which would compensate the public for valid bodily injury and property loss on
a no fault basis in the event of an accident at a commercial nuclear power
plant. Under the provisions of the Act, each nuclear reactor with an
operating license can be assessed up to $79.3 million per nuclear incident
with a maximum assessment of $10 million per incident within one calendar
year. Nuclear plant owners have initiated insurance programs designed to help
cover liability claims relating to property damage, decontamination,
replacement power and business interruption costs for participating utilities
arising from a nuclear incident.
The system has an equity ownership interest in four nuclear generating
facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The
operators of these units maintain nuclear insurance coverage (on behalf of the
owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II and
NEIL III) and the combined American Nuclear Insurers/Mutual Atomic Energy
Liability Underwriters (ANI). NEIL II provides $1.4 billion of property,
boiler, machinery and decontamination insurance coverage, including accidental
premature decommissioning insurance in the amount of the shortfall in the
Decommissioning Trust Fund, in excess of the underlying $500 million policy.
NEIL III provides $850 million of additional insurance coverage. All
companies insured with NEIL are subject to retroactive assessments if losses
exceed the accumulated funds available. ANI provides $500 million of "all
risk" property damage, boiler, machinery and decontamination insurance. An
additional $200 million of primary financial protection coverage is provided
for off-site bodily injury or property damage caused by a nuclear incident.
<PAGE 48>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ANI also provides secondary financial protection liability insurance which
currently provides $8.7 billion of retrospective insurance premium benefits in
accordance with the provisions of the Act. Additional coverage provided by
ANI includes tort liability protection arising out of radiation injury claims
by nuclear workers and injury or property damage caused by the transportation
or shipment of nuclear materials or waste.
Based on its various ownership interests in the five nuclear generating
facilities, the system's retrospective premium could be as high as $1.9
million yearly or a cumulative total of $15.1 million, exclusive of the effect
of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million)
in the event that total public liability claims from a nuclear incident exceed
the funds available to pay such claims.
(d) Power Contracts
Cambridge and Commonwealth Electric have long-term contracts for the
purchase of electricity from various sources. Generally, these contracts are
for fixed periods and require payment of a demand charge for the capacity
entitlement and an energy charge to cover the cost of fuel. Pertinent
information with respect to life-of-the-unit contracts for power from
operating nuclear units in which the system has an equity ownership (Yankee
Nuclear Units) is as follows:
Connecticut Maine Vermont
Yankee Yankee Yankee
(Dollars in Thousands)
Equity Ownership (%) 4.50 4.00 2.50
Plant Entitlement (%) 4.50 3.59 2.25
Plant Capability (MW) 560.0 870.0 496.0
System Entitlement (MW) 25.2 31.2 11.2
Contract Expiration Date 2007 2008 2012
1993 Actual Cost ($) 10,016 7,050 4,076
1994 Actual Cost ($) 8,902 6,250 3,660
1995 Actual Cost ($) 9,498 7,376 4,003
Decommissioning cost estimate (100%) ($) 385,523 361,212 347,383
System's decommissioning cost ($) 17,349 12,968 7,816
Market value of assets (100%) ($) 180,388 142,116 141,300
System's market value of assets ($) 8,117 5,102 3,179
Cambridge pays its share of the decommissioning expense to each of the
operators of these nuclear facilities as a cost of electricity purchased for
resale.
The system also has long-term contracts to purchase capacity from other
generating facilities. Information relative to these contracts is as follows:
Range of
Contract
Expiration Entitlement 1995 1994 1993
Dates % MW Cost Cost Cost
(Dollars in Thousands)
Type of Unit
Cogenerating 2008-2018 * 205.3 $121,636 $137,304 $104,599
Nuclear 2012 11 73.2 40,376 41,475 40,578
Waste-to-energy 2015 100 67.0 37,526 38,107 34,189
Hydro 2014-2023 100 23.6 9,933 7,521 8,904
Total 369.1 $209,471 $224,407 $188,270
* Includes contracts to purchase power from various cogenerating units
with capacity entitlements ranging from 11.1% to 100%.
<PAGE 49>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Costs pursuant to these contracts are included in electricity purchased
for resale in the accompanying consolidated statements of income and are
recoverable in revenues.
The estimated aggregate obligations for capacity under the life-of-the-
unit contracts from the operating Yankee Nuclear Units and other long-term
purchased power contracts in effect for the five years subsequent to 1995 is
as follows:
Long-Term
Equity Owned Purchased
Nuclear Units Power Total
(Dollars in Thousands)
1996 $21,195 $211,037 $232,232
1997 21,130 216,527 237,657
1998 23,596 225,337 248,933
1999 23,153 236,470 259,623
2000 23,813 239,709 263,522
(e) Yankee Atomic Nuclear Power Plant
In 1992, Yankee Atomic Electric Company (Yankee Atomic) permanently
discontinued power operation and began the decommissioning of the Yankee
Nuclear Power Station (the plant). At December 31, 1995, Cambridge and
Commonwealth Electric's respective 2% and 2.5% investment in Yankee Atomic was
approximately $1.1 million. The companies' estimated decommissioning costs
include their unrecovered share of all costs associated with the shutdown of
the plant, recovery of their plant investment, and decommissioning and closing
the plant. The most recent cost estimate to permanently shut down the plant
is approximately $225.2 million at December 31, 1995. The companies' share of
this liability is $10.1 million and is reflected in the accompanying
consolidated balance sheets as a liability and corresponding regulatory asset.
The market value of the companies' share of assets in the plant's decommis-
sioning fund at December 31, 1995 is approximately $5.7 million.
(f) Environmental Matters
The system is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment. These
laws and regulations affect, among other things, the siting and operation of
electric generating and transmission facilities and can require the
installation of expensive air and water pollution control equipment. These
regulations have had an impact on the System's operations in the past and will
continue to have an impact on future operations, capital costs and
construction schedules of major facilities. For additional information, see
"Environmental Matters" in Management's Discussion and Analysis of Financial
Condition and Results of Operations.
(g) FERC Order No. 636
As a result of implementing FERC Order No. 636 (Order 636), each
interstate pipeline company is allowed to collect certain transition costs
from its customers that resulted from the pipelines' need to buy out gas
supply contracts entered into prior to the issuance of Order 636.
Commonwealth Gas Company (Commonwealth Gas) has been billed a total of
approximately $23.8 million from Tennessee Gas Pipeline Company, Algonquin Gas
Transmission Company and Texas Eastern Transmission Company through December
31, 1995.
Commonwealth Gas' pipeline suppliers have made certain filings with the
FERC for the collection of their respective transition costs. Commonwealth
<PAGE 50>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Gas' current best estimate of the total remaining transition costs from its
suppliers is approximately $11.7 million. This balance has been recorded as a
liability with a corresponding regulatory asset. The ultimate level of costs
is dependent upon future events, including the market price of natural gas and
final settlements between the FERC and the pipeline suppliers.
In May 1995, the DPU allowed Commonwealth Gas to accelerate recovery of
its Order 636 transition costs that were incurred to date. These costs had
been deferred and accumulated as a regulatory asset and were being recovered
through the cost of gas adjustment (CGA) over a four-year period that began in
November 1993. The costs are now being recovered through the CGA over a one-
year period that began on May 1, 1995. The accelerated recovery period was
permitted by the DPU due to the minimal impact on customers' bills. Any
further transition costs are expected to be recovered by Commonwealth Gas
through the CGA as incurred.
(3) Income Taxes
The system files a consolidated federal income tax return. For
financial reporting purposes, the System and its subsidiaries provide taxes on
a separate return basis.
The following is a summary of the consolidated provisions for income
taxes for the years ended December 31, 1995, 1994 and 1993:
1995 1994 1993
(Dollars in Thousands)
Federal
Current $15,954 $12,789 $ 9,438
Deferred 8,231 12,617 15,127
Investment tax credits, net (1,401) (1,470) (1,500)
22,784 23,936 23,065
State
Current 4,176 3,171 2,692
Deferred 1,115 2,403 2,282
5,291 5,574 4,974
28,075 29,510 28,039
Amortization of regulatory liability
relating to deferred income taxes (5,164) (174) (350)
$22,911 $29,336 $27,689
Federal and state income taxes
charged to:
Operating expense $24,574 $29,154 $26,921
Other (income) expense (1,663) 182 768
$22,911 $29,336 $27,689
Deferred tax liabilities and assets are determined based on the
difference between the financial statement and tax bases of assets and
liabilities using enacted tax rates in effect in the year in which the
differences are expected to reverse.
In May 1995, Canal refunded certain unprotected excess deferred taxes to
Commonwealth Electric and Cambridge resulting in a reduction to the 1995 tax
provision.
<PAGE 51>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accumulated deferred income taxes consisted of the following in 1995 and
1994:
1995 1994
(Dollars in Thousands)
Liabilities
Property-related $190,763 $183,019
Power contract buy-out 10,002 -
Fuel charge stabilization 8,149 6,526
Postretirement benefits plan 6,767 5,543
Transition costs, net - 4,094
Seabrook nonconstruction 3,089 4,504
All other 20,006 19,999
238,776 223,685
Assets
Investment tax credits 18,035 18,941
Pension plan 7,457 6,744
Regulatory liability 6,455 9,536
All other 21,570 19,452
53,517 54,673
Accumulated deferred income taxes, net $185,259 $169,012
The net year-end deferred income tax liability above includes a current
deferred tax liability of $15,077,000 and $8,068,000 in 1995 and 1994,
respectively, which are included in accrued income taxes in the accompanying
consolidated balance sheets.
The total income tax provision set forth previously represents 31% in
1995, 37% in 1994 and 38% in 1993 of income before such taxes. The following
table reconciles the statutory federal income tax rate to these percentages:
1995 1994 1993
(Dollars in Thousands)
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory
levels $26,007 $27,406 $25,733
Increase (Decrease) from statutory levels:
State tax net of federal tax benefit 3,439 3,623 3,233
Tax versus book depreciation 1,369 1,471 1,501
Amortization of investment tax credits (1,368) (1,457) (1,454)
Reversals of capitalized expenses (652) (654) (655)
Dividend received deduction (389) (428) (405)
Amortization of excess deferred reserves (5,164) (174) (350)
Other (331) (451) 86
$22,911 $29,336 $27,689
Effective federal income tax rate 31% 37% 38%
(4) Employee Benefit Plans
(a) Pension
The system has a noncontributory pension plan covering substantially all
regular employees who have attained the age of 21 and have completed a year of
service. Pension benefits are based on an employee's years of service and
compensation. The system makes monthly contributions to the plan consistent
with the funding requirements of the Employee Retirement Income Security Act
of 1974.
<PAGE 52>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Components of pension expense and related assumptions to develop pension
expense were as follows:
1995 1994 1993
(Dollars in Thousands)
Service cost $ 6,386 $ 7,316 $ 6,069
Interest cost 23,949 21,452 20,410
Return on plan assets-(gain)/loss (62,933) 4,544 (36,552)
Net amortization and deferral 42,928 (21,990) 20,669
Total pension expense 10,330 11,322 10,596
Less: Amounts capitalized
and deferred 1,842 2,823 2,130
Net pension expense $ 8,488 $ 8,499 $ 8,466
Discount rate 8.50% 7.25% 8.50%
Assumed rate of return 9.00 8.50 8.50
Rate of increase in future
compensation 5.00 4.50 5.50
Pension expense reflects the use of the projected unit credit method
which is also the actuarial cost method used in determining future funding of
the plan. Commonwealth Electric and Cambridge, in accordance with current
ratemaking, are deferring the difference between pension contribution, which
is reflected in base rates, and pension expense, recognized pursuant to SFAS
No. 87, "Employers' Accounting for Pensions." The funded status of the
system's pension plan (using a measurement date of December 31) is as follows:
1995 1994
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(240,585) $(200,273)
Nonvested (26,772) (23,299)
$(267,357) $(223,572)
Projected benefit obligation $(323,652) $(274,120)
Plan assets at fair market value 308,969 255,263
Projected benefit obligation
greater than plan assets (14,683) (18,857)
Unamortized transition obligation 9,643 11,250
Unrecognized prior service cost 14,792 16,227
Unrecognized gain (27,349) (24,998)
Accrued pension liability $ (17,597) $ (16,378)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1995 1994
Discount rate 7.25% 8.50%
Rate of increase in future compensation 4.25 5.00
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years.
(b) Other Postretirement Benefits
Historically, the system provided postretirement health care and life
insurance benefits to eligible retired employees. Employees became eligible
for these benefits if their age plus years of service for the system at
retirement equaled 75 or more. However, as of January 1, 1993, the system
<PAGE 53>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
eliminated postretirement health care benefits for those non-bargaining
employees who were less than 40 years of age or had less than 12 years of
service at that date. Under certain circumstances, eligible employees are
required to make contributions for postretirement benefits. In addition,
certain collective bargaining employees are also participating under these new
eligibility requirements.
The system adopted the provisions of SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" as of January 1,
1993 and the cumulative effect of implementation of SFAS No. 106 was
approximately $106.7 million which is being amortized over 20 years. Prior to
1993, the cost of postretirement benefits was recognized as benefits were
paid.
The system makes contributions to various voluntary employees'
beneficiary association trusts that were established pursuant to section
501(c)(9) of the Internal Revenue Code (the Code). The system also makes
contributions to a subaccount of its pension plan pursuant to section 401(h)
of the Code to satisfy a portion of its postretirement benefit obligation.
The system contributed approximately $14 million, $14.5 million and $12.6
million to these trusts during 1995, 1994 and 1993, respectively.
The net periodic postretirement benefit cost for the years ended
December 31, 1995, 1994 and 1993 include the following components and related
assumptions:
1995 1994 1993
(Dollars in Thousands)
Service cost $ 1,774 $ 2,198 $ 2,100
Interest cost 9,022 8,299 9,017
Return on plan assets (5,796) (186) (661)
Amortization of transition obligation
over 20 years 5,336 5,336 5,336
Net amortization and deferral 3,692 (1,118) 30
Total postretirement benefit cost 14,028 14,529 15,822
Less: Amounts capitalized and deferred 5,898 8,811 10,832
Net postretirement benefit cost $ 8,130 $ 5,718 $ 4,990
Discount rate 8.50% 7.25% 8.50%
Assumed rate of return 9.00 8.50 8.50
Rate of increase in future compensation 5.00 4.50 4.50
The funded status of the system's postretirement benefit plan using a
measurement date of December 31, 1995 and 1994 is as follows:
1995 1994
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (71,270) $ (63,280)
Fully eligible active plan participants (12,860) (10,680)
Other active plan participants (41,814) (37,396)
(125,944) (111,356)
Plan assets at fair market value 33,324 19,972
Accumulated postretirement benefit obligation
greater than plan assets (92,620) (91,384)
Unamortized transition obligation 90,703 96,039
Unrecognized (gain) loss 1,917 (4,655)
$ - $ -
<PAGE 54>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following actuarial assumptions were used in determining the plan's
estimated accumulated postretirement benefit obligation (APBO) and funded
status for 1995 and 1994:
1995 1994
Discount rate 7.25% 8.50%
Rate of increase in future compensation 4.25 5.00
Medicare Part B premiums 12.20 12.30
Medical care 8.00 8.50
Dental care 5.00 5.00
The above rates, with the exception of the dental rate which remains
constant, decrease to five percent in the year 2007 and remain at that level
thereafter. A one percent change in the medical trend rate would have a $1.4
million impact on the system's annual expense and would change the APBO by
approximately $14.8 million.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect
postretirement benefit expense in future years.
Effective with its June 1, 1993 rate order from the DPU, Cambridge was
allowed to recover its SFAS No. 106 expense in base rates over a four-year
phase-in period with carrying costs on the deferred balance. In addition,
effective May 1, 1995 the DPU approved a settlement proposal sponsored jointly
by Commonwealth Electric and the Attorney General of Massachusetts which
allows Commonwealth Electric to fully expense costs relating to SFAS No. 106
expense and to amortize its $8.6 million deferred balance to expense over a
ten-year period. In February 1996, FERC accepted for filing rate schedules
that provide for the recovery of Canal's SFAS No. 106 expense effective with
its March 1996 contract billings including the recovery of previously deferred
costs over a six-month period. Commonwealth Gas intends to seek recovery of
its deferred costs in its next rate proceeding. While the system is unable to
predict the outcome of a future rate proceeding, it believes the DPU will
authorize similar rate treatment as provided to Cambridge, Commonwealth
Electric and other Massachusetts electric and gas companies for the recovery
of the cost of these benefits. Further, based on historical DPU action, the
system believes that it is appropriate to continue to record the difference
between the amount included in rates and SFAS No. 106 expense for Commonwealth
Gas as a regulatory asset. At December 31, 1995 and 1994, the system's
deferral amounted to approximately $19.7 million and $15.7 million,
respectively.
(c) Savings Plan
The system has an Employees Savings Plan that provides for system
contributions equal to contributions by eligible employees of up to four
percent of each employee's compensation rate. Effective January 1, 1993, the
rate was increased to five percent for those employees no longer eligible for
postretirement health benefits. The total system contribution was $4,393,000
in 1995, $4,302,000 in 1994 and $4,245,000 in 1993.
(5) Interim Financing and Long-Term Debt
(a) Notes Payable to Banks
System companies maintain both committed and uncommitted lines of credit
for the short-term financing of their construction programs and other
corporate purposes. As of December 31, 1995, system companies had $80 million
of committed lines of credit that will expire at varying intervals in 1996.
These lines are normally renewed upon expiration and require annual fees of up
<PAGE 55>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
to .1875% of the individual line. At December 31, 1995, the uncommitted lines
of credit totaled $70 million. Interest rates on the outstanding borrowings
generally are at an adjusted money market rate and averaged 6.1% and 4.4% in
1995 and 1994, respectively. Notes payable to banks totaled $55,600,000 and
$44,850,000 at December 31, 1995 and 1994, respectively.
(b) Long-term Debt Maturities and Retirements
Under terms of various indentures and loan agreements, the System and
certain subsidiary companies are required to make periodic sinking fund
payments for retirement of outstanding long-term debt. These payments and
balances of maturing debt issues for the five years subsequent to December 31,
1995 are as follows:
Sinking Funds Maturing Debt Issues
Year Subsidiaries System Subsidiaries Total
(Dollars in Thousands)
1996 $8,283 $ - $33,230 $41,513
1997 7,653 10,000 4,260 21,913
1998 7,653 10,000 9,000 26,653
1999 7,653 10,000 10,000 27,653
2000 6,153 - - 6,153
(6) Redeemable Preferred Shares
Each series of the System's preferred shares was issued at par value,
$100 per share, and is subject to periodic, mandatory sinking fund payments.
The System can make additional voluntary redemptions, not exceeding the
required redemption, at par, on a non-cumulative basis, on each sinking fund
date.
Preferred shares may also be called for redemption, in whole or in
part, in excess of the required and voluntary sinking fund redemptions. The
obligation to make mandatory redemptions is cumulative and the System is not
allowed to pay dividends to common shareholders or make optional sinking fund
payments if mandatory redemptions are in arrears. Details of redemptions for
each series are contained in the following table:
Sinking Funds Optional
Dividend 1996-2000 Redemption
Rate Mandatory Optional Call Prices
(Dollars in Thousands)
Series A 4.80% $120 $120 $102
Series B 8.10 160 160 101
Series C 7.75 540 540 101
Preferred shareholders have no voting rights except in the event that
six full quarterly dividends have not been paid. In this circumstance, the
preferred shareholders are entitled, voting as a class, to elect two of the
nine Trustees of the System.
The preference of these shares in involuntary liquidation is equal to
par value. The shares are of equal rank and are entitled to cumulative
dividends at the annual rate established for each series. No dividend can be
declared on any series unless proportionate dividends are concurrently
declared on the other outstanding series and in the event that dividend
payments are in arrears, the System may not redeem any shares unless all
shares of all preferred series are redeemed.
<PAGE 56>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(7) Disclosures About Fair Value of Financial Instruments
The fair value of certain financial instruments included in the
accompanying Consolidated Balance Sheets as of December 31, 1995 and 1994 are
as follows:
1995 1994
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-term Debt $418,694 $475,661 $449,280 $449,292
Preferred Stock 14,660 16,847 15,480 14,687
The carrying amount of cash and notes payable to banks approximates the
fair value because of the short maturity of these financial instruments.
The estimated fair value of long-term debt and preferred stock are based
on quoted market prices of the same or similar issues or on the current rates
offered for debt or preferred shares with the same remaining maturity. The
fair values shown above do not purport to represent the amounts at which those
obligations would be settled.
(8) Lease Obligations
System companies lease property, transmission facilities and equipment
under agreements, some of which are capital leases. Several subsidiaries
renegotiate certain lease agreements annually. These new agreements are for a
term of one year and are renewable monthly thereafter. COM/Energy Services
Company has agreements in effect for office furniture, computer,
transportation and other equipment. Generally, these agreements require the
lessee to pay related taxes, maintenance and other costs of operation. Leases
currently in effect contain no provisions which prohibit system companies from
entering into future lease agreements or obligations.
The following is a breakdown, by major class, of property under capital
lease at December 31, 1995 and 1994:
1995 1994
(Dollars in Thousands)
Transmission facilities $13,128 $13,844
Office furniture, computer equipment and other 1,888 2,236
15,016 16,080
Less: Accumulated amortization 85 351
$14,931 $15,729
<PAGE 57>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Future minimum lease payments, by period and in the aggregate, of
capital leases and non cancelable operating leases consisted of the following
at December 31, 1995:
Capital Operating
Leases Leases
(Dollars in Thousands)
1996 $ 3,147 $10,539
1997 2,694 3,808
1998 1,869 1,854
1999 1,806 1,157
2000 1,744 782
Beyond 2000 20,672 2,230
Total future minimum lease payments 31,932 $20,370
Less: Estimated interest element
included therein 17,001
Estimated present value of future minimum
lease payments $14,931
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $12,562,000 in 1995, $13,052,000 in 1994 and
$12,701,000 in 1993. There were no contingent rentals and no sublease rentals
for the years 1995, 1994 and 1993.
(9) Dividend Restriction
At December 31, 1995, approximately $113,766,000 of consolidated
retained earnings was restricted against the payment of cash dividends by
terms of indentures and note agreements securing long-term debt.
(10) Segment Information
System companies provide electric, gas and steam services to retail
customers in communities located in central and eastern Massachusetts and, in
addition, sell electricity at wholesale to Massachusetts customers. Other
operations of the system include the development and operation of rental
properties and other activities which do not presently contribute
significantly to either revenues or operating income.
Operating income of the various industry segments includes income from
transactions with affiliates and is exclusive of interest expense, income
taxes and equity in earnings of unconsolidated corporate joint ventures.
<PAGE 58>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The amount of identifiable assets represented by the system's investment
in corporate joint ventures consists principally of a percentage ownership in
the assets of four regional electric generating plants and a 3.8% interest in
Hydro-Quebec Phase II.
1995 1994 1993
(Dollars in Thousands)
Revenues from
Unaffiliated Customers
Electric $ 607,047 $ 639,801 $ 624,020
Gas 306,953 323,568 302,644
Steam and other 17,355 15,867 14,035
Total Revenues $ 931,355 $ 979,236 $ 940,699
Capital Expenditures (including AFUDC)
Electric $ 61,643 $ 38,754 $ 29,667
Gas 16,198 18,020 23,117
Other 3,659 1,843 1,796
$ 81,500 $ 58,617 $ 54,580
Operating Income
Before Income Taxes
Electric $ 80,884 $ 87,474 $ 76,117
Gas 36,611 31,664 35,001
Steam and other 3,689 3,482 3,139
Total Operating Income Before
Income Taxes $ 121,184 $ 122,620 $ 114,257
Identifiable Assets
Electric $ 980,143 $ 930,852 $ 914,571
Gas 374,615 380,805 376,683
Steam and other 57,269 53,914 53,062
1,412,027 1,365,571 1,344,316
Intercompany eliminations (35,140) (34,503) (42,702)
Investment in corporate joint
ventures 13,214 13,648 13,549
Total Identifiable Assets $1,390,101 $1,344,716 $1,315,163
Depreciation Expense
Electric $ 36,977 $ 33,188 $ 32,188
Gas 9,656 9,559 8,939
Steam and other 1,537 1,441 1,353
Total Depreciation $ 48,170 $ 44,188 $ 42,480
<PAGE 59>
COMMONWEALTH ENERGY SYSTEM
SELECTED FINANCIAL DATA
1995 1994 1993 1992 1991
(Dollars In Thousands Except Common Share Data)
Operating Revenues
Electric $ 607,047 $ 639,801 $ 624,020 $ 597,269 $ 607,371
Gas 306,953 323,568 302,644 294,874 252,239
Steam and other 17,355 15,867 14,035 14,307 13,824
Total $ 931,355 $ 979,236 $ 940,699 $ 906,450 $ 873,434
Net Income $ 51,396 $ 48,968 $ 45,834 $ 39,897 $ 19,472
Common Share Data-
Earnings per share $4.72 $4.59 $4.37 $3.83 $1.82
Dividends declared
per share $3.00 $3.00 $2.92 $2.92 $2.92
Average shares
outstanding 10,655,918 10,413,781 10,215,614 10,081,868 9,944,433
Total Assets $1,390,101 $1,344,716 $1,315,163 $1,272,019 $1,247,386
Long-term debt $ 377,181 $ 418,307 $ 448,893 $ 361,092 $ 366,010
Redeemable preferred
share investment 13,840 14,660 15,480 16,300 17,120
Common share
investment 390,785 362,997 337,070 315,219 300,859
Total Capitalization $ 781,806 $ 795,964 $ 801,443 $ 692,611 $ 683,989
1995 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $265,614 $209,254 $208,136 $248,351
Operating Income 30,400 17,715 17,520 30,975
Income Before Interest Charges 31,913 17,738 17,945 28,408
Net Income 20,933 6,430 7,116 16,917
Earnings per Common Share 1.95 .58 .64 1.55
Dividends Declared per
Common Share .75 .75 .75 .75
Closing Price of Common Shares-
High 41 7/8 41 1/2 43 3/8 47 1/8
Low 35 5/8 37 3/4 35 3/8 41
1994 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $312,906 $213,741 $223,536 $229,053
Operating Income 38,135 14,310 17,876 23,145
Income Before Interest Charges 38,745 14,399 16,880 22,418
Net Income 27,951 3,760 6,216 11,041
Earnings per Common Share 2.68 .32 .57 1.02
Dividends Declared per
Common Share .75 .75 .75 .75
Closing Price of Common Shares-
High 45 1/2 43 3/4 40 3/4 38 3/4
Low 42 7/8 39 1/2 37 1/2 35 3/8
<PAGE 60>
Commonwealth Energy System
One Main Street
Post Office Box 9150
Cambridge, Massachusetts 02142-9150
Telephone (617) 225-4000
<PAGE 61>
APPENDICES
COMMONWEALTH ENERGY SYSTEM
Proxy-Annual Meeting of Shareholders-May 2, 1996
This Proxy is Solicited on Behalf of the Board of Trustees
The undersigned hereby appoints Sheldon A. Buckler, Henry Dormitzer and
William G. Poist, and each or any of them, with power of substitution, as
proxies to attend the Annual Meeting of Shareholders of the System to be held
on Thursday, May 2, 1996 and at any adjournment thereof and to vote the number
of shares which the shareholder(s) would be entitled to vote if personally
present:
To vote your shares for all Trustee nominees, mark the "FOR" box on
item 1. To withhold voting for all nominees, mark the "WITHHELD" box. If you
do not wish your shares voted "FOR" a particular nominee, mark the
"EXCEPTION" box and enter name(s) of the exception(s) in the space provided.
_____________________________________________________________________________
The Trustees recommend a vote "FOR" #1 and #2
1. Election of Trustees
Nominees: P. H. Cressy, W. J. O'Brien, W. G. Poist
[ ] FOR [ ] WITHHELD [ ] EXCEPTIONS
EXCEPTIONS: ____________________
2. Consent to a two-for-one share split and to amend
Sections 5 and 22 of the Declaration of Trust.
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
The Trustees recommend a vote "AGAINST" #3
3. Shareholder Proposal
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
4. Upon any other business that may properly come before the meeting.
_____________________________________________________________________________
This Proxy will be voted as directed above. If no other indication
is made, this proxy will be voted FOR proposals #1 AND 2,
and AGAINST proposal #3.
Any proxy or proxies to vote such shares at said meeting
heretofore given by the shareholder(s) are hereby revoked.
PLEASE SIGN AND DATE ON REVERSE SIDE
____________________________________________________
____________________________________________________
Signature(s) should agree
with name(s) printed below
(When signing as attorney, executor or administrator, trustee or
guardian, etc., please indicate your full title as such.)
Acct. No. No. of Shares
Dated_______________________, 1996
PLEASE SIGN, DATE AND RETURN IN ENCLOSED PREPAID ENVELOPE