SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K/A
Amendment No. 2
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission Registrants, State of Incorporation I.R.S. Employer
File Number Address; and Telephone Number Identification
No.
1-5366 EASTERN UTILITIES ASSOCIATES 04-1271872
(A Massachusetts voluntary association)
One Liberty Square
Boston, Massachusetts 02109
Telephone (617) 357-9590
0-2602 Blackstone Valley Electric Company 05-0108587
(A Rhode Island Corporation)
750 W. Center Street
West Bridgewater, Massachusetts 02379
Telephone (508) 559-1000
0-8480 Eastern Edison Company 04-1123095
(A Massachusetts Corporation)
750 W. Center Street
West Bridgewater, Massachusetts 02379
Telephone (508) 559-1000
Securities registered pursuant to Section 12(b) of the Act:
Name of each Exchange
Registrant Title of Each Class on which registered
Eastern Utilities Common Shares, New York Stock Exchange
Associates par value $5 per share Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
Blackstone Valley 4.25% Non-Redeemable Preferred Stock,
Electric Company $100 Par Value
5.60% Non-Redeemable Preferred Stock,
$100 Par Value
Eastern Edison 6.625% Redeemable Preferred Stock,
Company $100 Par Value
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
State the aggregate market value of the voting stock held by non-affiliates of
the registrants. As of March 15, 1999:
Eastern Utilities Associates Common Shares, $5 par value - $579,871,415
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Eastern Utilities Associates Common Shares
Outstanding at March 15, 1999: 20,435,997
Blackstone Valley Electric Company Common Shares
Outstanding at March 15, 1999: 184,062
Eastern Edison Company Common Shares
Outstanding at March 15, 1999: 2,339,401
Portions of the Annual Reports to Shareholders of Eastern Utilities Associates,
Blackstone Valley Electric Company, and Eastern Edison Company for the year
ended December 31, 1998, are incorporated by reference into Part II. Portions
of the Eastern Utilities Associates Proxy Statement, to be filed on or about
April 14, 1999 are incorporated by reference into Part III.
EXPLANATORY NOTE
Eastern Utilities Associates hereby amends its Annual Report on Form 10-K
for the year ended December 31, 1998 to reflect changes to Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations, and Part II, Item 8. Financial Statements and Supplementary Data.
Except for the Items identified below, the content of the Registrants' original
1998 Form 10-K filed on March 31, 1999, is otherwise unchanged.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrants have duly caused this amendment to be signed on
its behalf by the undersigned, thereunto duly authorized.
EASTERN UTILITIES ASSOCIATES
By: /s/ John R. Stevens
President and Chief Operating Officer
(Principal Accounting Officer)
BLACKTONE VALLEY ELECTRIC
By: /s/ John R. Stevens
Vice Chairman and Director
(Principal Accounting Officer)
EASTERN EDISON COMPANY
By: /s/ John R. Stevens
Vice Chairman and Director
(Principal Accounting Officer)
April 16, 1999
Part II - Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
This item is amended and restated in its entirety as follows:
The information required by this Item with respect to Blackstone and Eastern
Edison is incorporated herein by reference to pages 3 through 10 in the 1998
Blackstone Annual Report and pages 3 through 14 in the 1998 Eastern Edison
Annual Report (Exhibits 13-1.01 and 13-1.08) for Blackstone and Eastern Edison,
respectively, as previously filed with the Registrants' Form 10-K.
The information required by this Item with respect to EUA previously
incorporated herein by reference to pages 7 through 24 in the 1998 EUA Annual
Report to Shareholders (Exhibit 13-1.03 of the Registrants' 1998 Form 10-K) is
replaced in its entirety by the following:
Eastern Utilities Associates
Management's Discussion and Analysis of Financial Condition and Review of
Operations
Proposed Merger Agreement - On February 1, 1999, EUA and New England Electric
System (NEES) announced a merger agreement under which NEES will acquire all
outstanding shares of EUA for $31 per share in cash. The merger agreement,
which is subject to the approval of EUA shareholders and various regulatory
agencies, values the equity of EUA at approximately $634 million, which
represents a 23% premium above the price of EUA shares on December 4, 1998, the
last trading day before other regional merger announcements affected EUA's
share price. EUA shareholders will continue to receive dividends at the
current level, as declared by the Board of Trustees, until closing of the
merger, expected by early 2000.
1998 Operations Overview - Consolidated net earnings for 1998 were $34.7
million, or $1.70 per share, on revenues of $538.8 million, an 8.6% decrease
from 1997 earnings of $38.0 million on revenues of $568.5 million. 1998
results include the impacts of the 1998 EUA Cogenex Settlement and tax audit
adjustments. 1997 results include the one-time earnings impact of a joint
venture termination in 1997. These items are discussed below and listed in the
following table.
<TABLE>
Net Earnings and Earnings Per Share by business unit for 1998 and 1997 were as
follows:
<CAPTION>
1998 1997
<S> <C> <C> <C> <C>
Net Earnings (Loss) Earnings (Loss) Net Earnings Earnings
(000's) Per Share (000's) Per Share
Core Electric Business $35,160 $1.72 $36,025 $1.77
Energy Related Business (792) (0.04) 49 0.00
Corporate 541 0.03 406 0.02
From Operations 34,909 1.71 36,480 1.79
One-Time Impacts:
Cogenex Settlement (2,062) (0.10)
Tax Audit Adjustments 1,863 0.09
Joint Venture Termination 1,480 0.07
Consolidated $34,710 $1.70 $37,960 $1.86
</TABLE>
Major impacts on earnings by business unit are described in the following
paragraphs.
Cogenex Settlement - EUA Cogenex recorded an after-tax charge of $2.1 million
to earnings related to an arbitration panel's decision in a matter involving
the 1995 sale of a portfolio of cogeneration units by EUA Cogenex to
Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed that
financial and other warranties in the purchase and sale agreement had been
breached. EUA Cogenex entered counterclaims seeking recovery of costs of
certain services performed for Ridgewood. The arbitration panel found for the
buyer on some of the warranty claims, and awarded damages of approximately $2.6
million plus interest. EUA Cogenex was awarded approximately $400,000 plus
interest on its counterclaim. EUA Cogenex paid the arbitration panel's net
award less interest and recorded this charge to earnings during the fourth
quarter of 1998. EUA Cogenex continues to contest the panel's findings with
respect to the interest and legal fees.
Tax Audit adjustments - In January 1997, the Internal Revenue Service (IRS)
issued a report in connection with its examination of the consolidated federal
income tax returns of EUA for 1992 and 1993. This report included an
adjustment to disallow EUA's inclusion of its investment in EUA Power's
Preferred Stock as a deduction in determining Excess Loss Account (ELA) taxable
income in 1992 relating to EUA Power's Common and Preferred Stock that was
redeemed in 1993. EUA filed an administrative appeal contesting the IRS
position. In January 1999, EUA reached an understanding with the IRS Appeals
Office concerning settlement of this matter. Reductions in EUA's tax reserves,
to reflect this and other items, resulted in a net $1.9 million addition to
fourth quarter 1998 earnings.
Termination of power marketing joint venture - In the third quarter of 1997,
EUA announced the termination of a power marketing joint venture with an
affiliate of Duke Energy Corporation, the establishment of contingency reserves
related to certain of its energy-related business activities and other
expenses. Collectively, these actions resulted in a net after-tax gain of $1.5
million in third quarter 1997 earnings.
<TABLE>
Revenues - Total Operating Revenues by business unit for 1998, 1997 and 1996
were as follows:
<CAPTION>
($ in millions) 1998 1997 1996
<S> <C> <C> <C>
Core Electric $480.1 $506.7 $470.7
Energy Related 58.7 61.8 56.4
Corporate - - -
Total $538.8 $568.5 $527.1
</TABLE>
Core Electric Business: Core Electric Revenues decreased by $26.6 million in
1998 due to the following: Generation related revenues decreased by $24.6
million as a result of rate reductions to all of EUA's retail customers,
pursuant to electric industry restructuring legislation and settlement
agreements effective January 1, 1998, and March 1, 1998, in Rhode Island and
Massachusetts, respectively. Of this decrease, $21.5 million relates to
decreased fuel and purchased power expenses in 1998. The remaining change in
generation related revenues was due to the net impacts of rate reductions and
accrued revenues as prescribed in the previously mentioned settlement
agreements. Distribution revenues decreased by $4.2 million in 1998 due to the
net impacts of restructured rates, a 1.7% increase in primary kilowatthour
(kWh) sales and a $2.2 million increase in conservation and load management
(C&LM) recoveries.
Core Electric Revenues increased by $36 million in 1997 due to recoveries of
increased fuel, purchased power and C&LM expenses aggregating $22.9 million and
increased retail distribution revenues of $13.8 million resulting from
increased kWh sales and rate increases effective January 1, 1997 for Blackstone
and Newport.
Energy Related Business: Energy Related Revenues decreased by $3.1 million in
1998 due primarily to decreased EUA Cogenex project sales of $8.1 million
offset by increased paid-from-savings revenues and installation and fabrication
revenues totalling $5.6 million.
Energy Related Revenues increased by $5.5 million in 1997 as result of
increased EUA Cogenex project sales of $9.1 million offset by decreased paid-
from-savings and installation and fabrication revenues totaling $4.1 million.
In addition, EUA TransCapacity revenue increased by $500,000 in 1997.
Core Electric Business kWh Sales - Primary kWh sales of electricity by EUA's
Core Electric Business unit increased approximately 1.7% in 1998 compared to
1997. This change was led by increases of 2.9% and 2.2% in the industrial and
commercial classes, respectively. Total energy sales increased 9.5% in 1998,
due mainly to increased sales to the New England Power Pool (NEPOOL) and
increased short-term unit contract energy sales. These NEPOOL interchange and
short-term unit contract sales essentially recover fuel costs and have little
or no earnings impacts. Primary kWh sales of electricity increased 1.4% in 1997
compared to the prior year. This change was led by increases of 2.4% in the
residential and industrial customer classes. Total energy sales including
NEPOOL interchange and short-term unit contract sales increased 4.6% in 1997.
Percentage changes in kWh Sales by class of customer for the past two years
were as follows:
<TABLE>
Percent Increase (Decrease) from Prior Year
<CAPTION>
1998 1997
<S> <C> <C>
Residential 0.3 2.4
Commercial 2.2 (0.7)
Industrial 2.9 2.4
Other 4.9 7.4
Total Primary Sales 1.7 1.4
Other Electric Utilities* (100.0) (9.0)
Losses and Company Use 13.0 5.1
Total System Requirements 0.5 1.4
Unit Contracts* 71.5 33.7
Total Energy Sales 9.5 4.6
</TABLE>
* Effective January 1998, Middleboro and Pascoag are no longer contract demand
customers of Montaup. Energy sales to these customers are now included with
unit contracts.
Expenses - Fuel and Purchased Power: The EUA System's most significant expense
items continue to be fuel and purchased power expenses of our Core Electric
Business which together comprised about 44% of total operating expenses in
1998.
Fuel expense of the Core Electric Business decreased by approximately $10.9
million or 9.9% in 1998. Increased nuclear generation and a 17.1% decrease in
the cost of fossil fuels resulted in an 18.7% decrease in the average cost of
fuel compared to 1997. Somewhat offsetting the decrease in the average price
of fuel was a 9.5% increase in total energy generated and purchased in 1998
compared to 1997. Fuel expense increased by approximately $18.6 million or
20.1% in 1997, due primarily to a 4.6 % increase in total energy generated and
purchased and outages of nuclear units in 1997 which contributed to a greater
dependence on higher cost fossil fuels for energy requirements, resulting in an
increase in average fuel costs of 16.3%.
Purchased Power demand expense decreased approximately $10.5 million or 8.8% in
1998 compared to 1997. This decrease was primarily due to decreased billings
from the Maine Yankee, Connecticut Yankee and Pilgrim Nuclear units aggregating
approximately $8.5 million, and from Ocean State Power (OSP) of approximately
$1.9 million. Purchased Power demand expense increased approximately $700,000
or less than 1% in 1997.
Other Operation and Maintenance (O&M): O&M expenses for 1998 decreased by
$16.8 million or 8.7% compared to 1997. Total O&M expenses are comprised of
three components: Direct Controllable, Indirect and Energy Related.
<TABLE>
O&M expenses by component for 1998, 1997 and 1996 were as follows:
<CAPTION>
($ in millions) 1998 1997 1996
<S> <C> <C> <C>
Direct Controllable $ 87.7 $ 89.1 $ 87.5
Indirect 40.5 51.1 36.7
Energy Related 47.9 52.7 55.7
Total O&M $176.1 $192.9 $179.9
</TABLE>
Direct Controllable expenses of our Core Electric and Corporate Business units
represent 49.8% of total 1998 O&M expenses and include expense items such as
salaries, fringe benefits, insurance and maintenance. In 1998, direct expenses
decreased approximately $1.4 million compared to 1997. This change is
primarily the result of increased expenses in 1997 related to an April 1997
storm which struck Eastern Edison's service territory.
Indirect expenses include items over which we have limited short-term control.
Indirects include such expense items as O&M expenses related to Montaup
Electric Company's (Montaup) joint ownership interests in generating facilities
such as Seabrook I and Millstone 3 (see Note H of Notes to Consolidated
Financial Statements for other jointly-owned units), power contracts where
transmission rental fees are fixed and C&LM expenses that are fully recovered
in revenues.
Indirect expenses decreased by approximately $10.6 million in 1998. Jointly
owned units expenses decreased approximately $9.4 million in 1998, due largely
to the return to service of Millstone 3 in July of 1998 and decreased expenses
of Canal Unit 2 and Seabrook I. In addition, charges from other utilities
decreased approximately $1.9 million and Other Post-Retirement Benefits and
Pension expenses decreased approximately $1.4 million collectively in 1998.
These decreases were offset by increased C&LM expense of approximately $2.2
million. Indirect expenses increased by approximately $14.4 million in 1997.
This change was primarily due to increased jointly owned unit expenses of
approximately $9.0 million, of which approximately $5.0 million was related to
the Millstone 3 outage and the remainder was due to increased expenses related
to the scheduled maintenance outages at the Canal and Seabrook I units. Also
impacting the 1997 change were increased C&LM expenses of approximately $3.3
million, approximately $1.2 million of transmission expenses related to new
transmission tariffs implemented by FERC in 1997 to accommodate utility
industry restructuring, and increased pension related expenses of approximately
$700,000.
The Energy Related component relates to O&M expenses of our Energy Related
Business unit where changes are tied to changes in business activity. EUA
Cogenex continues to be the most active of our Energy Related businesses and
incurred 82% of the total O&M expenses of this business unit in 1998. Expenses
of the Energy Related Business Unit decreased by approximately $5.2 million in
1998. Expenses of EUA Cogenex decreased approximately $10.3 million in 1998,
due primarily to decreased expenses of Cogenex West, Cogenex Canada, Citizens
and the Cogenex Partnerships of $9.9 million in aggregate, largely the result
of decreased operating activity in 1998. In addition, EUA Cogenex expenses
reflect the impact of the sale of RENOVA operations to EUA Energy Investment in
May 1998 and ongoing cost control efforts at the Cogenex division which were
offset by increased operating expenses at EUA Day in connection with its
development of Day Matrix, a division which provides energy metering and
control systems. EUA Energy Investment expenses increased by $4.9 million in
1998 due primarily to the impact of the RENOVA sale. Energy Related expenses
decreased by approximately $3.0 million in 1997. This decrease was due
primarily to decreased employee levels and other ongoing cost control efforts
of the EUA Cogenex Division of approximately $2.2 million, decreased expenses
of RENOVA of approximately $1.6 million, resulting from decreased operating
activity, offset by increased expenses of Cogenex-West of approximately
$300,000 as a result of increased marketing activity.
Voluntary Retirement Incentives: In June 1997, an early retirement offer was
accepted by a group of nine employees who were eligible for but not offered a
Voluntary Retirement Incentive offer completed in 1995. The pre-tax cost of
the 1997 offer, recorded in that year's second quarter, was approximately $1.4
million.
Depreciation and Amortization: Depreciation and Amortization expense increased
by approximately $4.1 million or 8.8% in 1998 as compared to 1997. This
increase is due largely to increased depreciation at EUA Cogenex directly
related to an increase in number of projects placed in service, and
amortization of certain regulatory assets at the Core Electric Business
pursuant to restructuring settlement agreements. Depreciation and Amortization
expense increased by approximately $1.5 million in 1997, due primarily to
higher depreciable plant balances at our Core Electric companies and a $500,000
increase in EUA Cogenex depreciation.
Income Taxes: EUA files a consolidated federal income tax return for the EUA
System. The composite federal and state effective income tax rate for 1998 was
34.5% versus 35.8% in 1997. The effects of accelerated reversal of timing
differences pursuant to restructuring settlement agreements were offset in 1998
by the previously discussed tax audit adjustments and the reversal of
unamortized investment tax credits related to Canal 2 at the time of its sale,
which occurred on December 30, 1998.
Other Income (Deductions) - Net: Other Income and (Deductions) - Net decreased
by approximately $6.0 million, or 55.0% in 1998 as compared to 1997. This
decrease is due largely to the absence of the impacts of the 1997 power
marketing joint venture termination and the 1997 favorable resolution of a
Massachusetts corporate income tax dispute. Also contributing to the 1998
decrease were non-operating expenses of $2.5 million related to Montaup's
divestiture efforts and approximately $800,000 of expenses related to
opposition of a 1998 Massachusetts referendum to repeal deregulation
legislation. Other Income and (Deductions) - Net increased approximately $5.9
million in 1997. This was primarily due to the net positive impact of the
power marketing joint venture termination in 1997, increased interest income
related to the favorable resolution of a Massachusetts corporate income tax
dispute in 1997, and the impact of changes to the EUA Cogenex pension and post-
retirement welfare benefit plans offset by gains recorded in 1996 from the sale
of Seabrook II equipment jointly owned by Montaup. The tax issue in question
relates to a 1989 Massachusetts State income tax audit which assessed tax
liability for certain intercompany transactions. In order to contest the tax
assessment, EUA paid the disputed tax liability in 1989. Final resolution of
this matter was reached in 1997 in favor of EUA. The disputed tax amount,
along with related interest, was returned to EUA in 1997. The one-time benefit
to 1997 earnings relates to the interest portion of the refund.
Interest Charges: Net Interest charges decreased by approximately $2.0 million
or 5.0% in 1998 compared to 1997. Interest on long term debt decreased as a
result of normal cash sinking fund payments and the maturities of Eastern
Edison's $20 million, 5 7/8% First Mortgage Bonds in May 1998 and $40 million,
5 3/4% First Mortgage Bonds in July 1998. This decrease was partially offset by
interest expense on increased short term borrowings, which were used to finance
Eastern Edison's long-term debt maturities. Net interest charges for 1997 were
relatively unchanged from the 1996 level. Decreased long-term debt interest
expense in 1997 resulting from normal cash sinking fund payments was offset by
higher interest expense related to increased short-term debt and decreased
capitalized interest by EUA Cogenex.
FINANCIAL CONDITION AND LIQUIDITY - The EUA System's need for permanent capital
is primarily related to investments in facilities required to meet the needs of
its existing and future customers.
Core Electric Business: For 1998, 1997 and 1996, Core Electric Business cash
construction expenditures were $22.9 million, $21.9 million and $33.3 million,
respectively.
Internally generated funds available after the payment of dividends supplied
approximately 250%, 133%, and 118% of these cash construction requirements in
1998, 1997 and 1996, respectively. Various laws, regulations and contract
provisions limit the use of EUA's internally generated funds such that the
funds generated by one subsidiary are not generally available to fund the
operations of another subsidiary.
Cash construction expenditures of the Core Electric Business for 1999, 2000 and
2001 are estimated to be approximately $33.4 million, $32.5 million and $33.3
million, respectively, and are expected to be financed with internally
generated funds.
In addition to construction expenditures, projected requirements for scheduled
cash sinking fund payments and mandatory redemption of securities of the Core
Electric Business for 1999 through 2003 are $11.6 million, $2.3 million, $4.1
million, $38.4 million and $51.4 million, respectively, none of which relates
to Blackstone's or Newport's variable rate bonds.
Energy Related Business: Capital expenditures of our Energy Related Business
amounted to $26.8 million, $51.9 million and $28.1 million, in 1998, 1997 and
1996, respectively. Internally generated funds supplied 143%, 88%, and 72% of
cash capital requirements in 1998, 1997, and 1996, respectively. Estimated
capital expenditures of the Energy Related Business are $52.7 million, $55.9
million, and $61.3 million in 1999, 2000 and 2001, respectively. Internally
generated funds are expected to supply approximately 100% of 1999 estimated
capital requirements.
In addition to capital expenditures and energy related investments, projected
requirements for scheduled cash sinking fund payments and mandatory redemption
of securities of the Energy Related Business are $9.2 million in 1999, $59.2
million in 2000, $9.2 million in 2001, $6.0 million in 2002 and $6.0 million in
2003.
Corporate: Construction activity of the Corporate Business unit is minimal.
Projected requirements for scheduled cash sinking fund payments for the
corporate operations for each of the five years following 1998 are $1.1
million.
Short-Term Lines of Credit: In July 1997, several EUA System companies entered
into a three-year revolving credit agreement allowing for borrowings in
aggregate of up to $145 million from all sources of short-term credit. As of
December 31, 1998, various financial institutions have committed up to $75
million under the revolving credit facility. In addition to the $75 million
available under the revolving credit facility, EUA System companies maintain
short-term lines of credit with various banks totaling $90 million, for an
aggregate amount available of $165 million.
Year-End Short-Term Debt outstanding by business unit:
($ in thousands) 1998 1997
Core Electric Business $ 2,220 $ 7,075
Energy Related Business 19,354 44,609
Corporate 42,000 9,800
Total $63,574 $61,484
During 1998, Eastern Edison used available funds and short-term borrowings to
fund $60 million of long-term debt maturities. On December 30, 1998, Montaup
received $75.9 million of proceeds from the sale of its 50% ownership share of
the Canal 2 generating Station to Southern Energy. Those funds were used to
redeem $55 million of debenture bonds and pay a special dividend to Montaup's
parent company, Eastern Edison. Eastern Edison used these proceeds to repay
its outstanding short-term debt and make short-term investments of $25.6
million. EUA expects to repay the outstanding balances of short-term
indebtedness with internally generated funds.
Dividend Payments: The preferred stock provisions of the Retail Subsidiaries
place certain restrictions upon the payment of dividends on common stock of the
respective Retail Subsidiary to EUA. These restrictions relate to cumulative
retained earnings available for the payment of such common dividends. At
December 31, 1998 and 1997 each of the Retail Subsidiaries was in excess of the
minimum requirements which would make these restrictions effective. These
restrictions have not, and are not expected to have, an impact on EUA's ability
to meet its cash obligations.
Interest Rate Risk: EUA is exposed to interest rate risk primarily related to
Blackstone's and Newport's variable rate bonds. Refer to the Consolidated
Statements of Indebtedness for a listing of EUA's long-term fixed and variable
rate debt.
Energy Related Businesses - Net Earnings and Earnings Per Share contributions
of EUA's Energy Related Businesses for 1998 and 1997 were as follows:
<TABLE>
1998 1997
<CAPTION>
Net Earnings Earnings Net Earnings Earnings
(Loss) (Loss) (Loss) (Loss)
(000's) Per Share (000's) Per Share
<S> <C> <C> <C> <C>
EUA Cogenex $ 763 $ 0.04 $ 202 $ 0.01
EUA Ocean State 4,066 0.20 3,967 0.19
EUA Energy Investment (5,287) (0.26) (3,741) (0.18)
EUA Energy Services (228) (0.01) (354) (0.02)
EUA Telecommunications (106) (0.01) (25) (0.00)
From Operations (792) (0.04) 49 0.00
Cogenex Settlement (2,062) (0.10)
Total Energy Related Business $(2,854) $(0.14) $ 49 $ 0.00
</TABLE>
EUA Cogenex: EUA Cogenex provides energy efficiency products and energy
management services throughout North America. EUA Cogenex's net earnings
increased approximately $600,000 in 1998 due largely to the transfer of RENOVA
operations to EUA Energy Investment Corporation effective May 1, 1998 and to
decreased interest expense.
EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which
developed and operate Units I and II of OSP, twin 250-megawatt (mw) gas-fired
generating units in northern Rhode Island. Both units have provided a premium
return since their respective in-service dates of December 31, 1990, and
October 1, 1991. The slight increase in EUA Ocean State earnings contribution
was due primarily to increased availability bonuses in 1998.
EUA Energy Investment: EUA Energy Investment was organized to seek out
investments in energy related businesses. The change in EUA Energy Investment
earnings contribution was due to the sale of RENOVA operations to EUA Energy
Investment in 1998. Also impacting this change were increased losses at EUA
Transcapacity and EUA BIOTEN in 1998 compared to 1997. EUA BIOTEN is currently
in negotiations with a third party investor for the restructuring of BIOTEN
Partnership into a corporation. EUA BIOTEN intends to transfer its total
partnership investment of $13.5 million at December 31, 1998, into a non-voting
preferred equity ownership interest in a newly-formed corporation. Effective
March 1, 1999, EUA BIOTEN will no longer have any funding obligations to the
BIOTEN partnership or the restructured entity. EUA Energy Investment is
continuing in its efforts to negotiate strategic alliances or sales of its
other energy related investments, including EUA Transcapacity and RENOVA. EUA
can not predict the outcome of these negotiations.
EUA Energy Services: The change in earnings of EUA Energy Services is due to
reduced operating costs since the power marketing joint venture with an
affiliate of Duke Energy Corporation was terminated in 1997.
EUA Telecommunications: The slight change in earnings of EUA
Telecommunications is due to increased expenses since the company was
established in mid-1997.
Electric Utility Industry Restructuring - Legislation enacted in Rhode Island
in 1996 and Massachusetts in 1997 along with approved electric utility industry
restructuring settlement agreements in both states and at the federal level,
granted EUA's Rhode Island and Massachusetts electric customers with choice of
electricity supplier and rate reductions commencing January 1, 1998 and March
1, 1998, respectively. Until a customer chooses an alternative supplier, that
customer will receive standard offer service from the retail distribution
company. Blackstone and Newport are required to arrange for standard offer
service through December 31, 2009 and Eastern Edison must arrange for this
service through February 28, 2005. Under the approved settlement agreements,
Montaup had guaranteed standard offer supply at a fixed price schedule for the
duration of the standard offer periods and Blackstone, Newport and Eastern
Edison agreed to subject their standard offer requirements to a competitive
bidding process in which competitive suppliers would bid against the guaranteed
price. Through its successful divestiture process, combined with a competitive
bidding process conducted in late 1998, Montaup has assigned 100% of its
standard offer obligation to purchasers of its generating assets. The
guaranteed standard offer price will increase over time to encourage customers
to leave standard offer service and enter the competitive power supply market.
Provisions of the approved settlement agreements also allowed Montaup to
replace its all-requirements wholesale contracts with its affiliated retail
distribution companies with a contract termination charge (CTC) which permits
Montaup to recover, among other things, its above market investments and
commitments in generation assets. Montaup began billing the CTC coincident
with retail access and the distribution companies are recovering the CTC
through a non-bypassable transition charge to all of their distribution
customers.
As part of the approved settlement agreements, Montaup agreed to divest its
entire generation portfolio. The net proceeds of the sale, as defined in the
settlement agreements, will be used to mitigate Montaup's CTC to its retail
affiliates via a Residual Value Credit (RVC). The RVC will reduce the fixed
component of the CTC by an amount equal to the net proceeds, with a return,
over the period commencing on the date the RVC is implemented through December
31, 2009. Montaup has filed to implement the RVC effective April 1, 1999 and
is awaiting approval.
Generation Divestiture - Montaup now has agreements to sell all of its non-
nuclear power generation assets and its 2.9% ownership share of the Seabrook
Nuclear Station and has agreements to transfer all of its remaining purchased
power contracts with the exception of its purchase power commitment with the
Vermont Yankee Nuclear Station.
On January 5, 1999, EUA announced that Montaup had agreed to transfer its
remaining non-nuclear power purchase contracts, amounting to approximately 177
mw, to Constellation Power Source, Inc. In addition, Montaup has entered into
agreements to sell: its 160-mw Somerset, Massachusetts electric generating
station for approximately $55 million to NRG Energy, Inc.; its 2.6% (16 mw)
share of the W. F. Wyman Unit 4 in Yarmouth, Maine to the Florida based FPL
Group for approximately $2.4 million; and; its 2.9% share (34 mw) of the
Seabrook Station nuclear power plant to the Great Bay Power Corporation, a
subsidiary of BayCorp Holdings, Ltd. for $3.2 million. Montaup has also signed
agreements for the transfer of power purchase contracts for approximately 170
mw between Montaup and Ocean State Power and for the buyout of its 11% (73 mw)
power entitlement from the Pilgrim Nuclear Power Station in Plymouth,
Massachusetts. All of the sale and contract transfer agreements are subject to
federal and/or state regulatory approvals, including that of the Nuclear
Regulatory Commission with respect to the Seabrook sale. Closing of the non-
nuclear sale agreements are anticipated to take place in the first quarter of
1999. The Seabrook sale and Pilgrim buyout are expected to take place later in
1999.
Also, the sale of Montaup's 50% share (280 mw) of Unit 2 of the Canal
generating station in Sandwich, Massachusetts to Southern Energy for $75
million, which was announced in May 1998, was completed on December 30, 1998,
and the sale of two diesel-powered generating units (totaling approximately 16
mw) owned by Newport to Illinois-based Wabash Power Equipment Co. for $1.5
million closed on October 1, 1998.
Montaup's remaining generating capacity includes approximately 46 mw from its
4.0% joint ownership share of Millstone 3 nuclear unit and 12 mw from its 2.25%
equity ownership of the Vermont Yankee nuclear facility.
Environmental Matters - EUA's Core Electric Business subsidiaries and other
companies owning generating units from which power is obtained are subject,
like other electric utilities, to environmental and land use regulations at the
federal, state and local levels. The federal Environmental Protection Agency
(EPA), and certain state and local authorities, have jurisdiction over releases
of pollutants, contaminants and hazardous substances into the environment and
have broad authority to set rules and regulations in connection therewith, such
as the Clean Air Act Amendments of 1990, which could require installation of
pollution control devices and remedial actions. In 1994, EUA instituted an
environmental audit program to ensure compliance with environmental laws and
regulations and to identify and reduce liability with respect to those
requirements.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by such authorities. The EUA System
typically provides for the disposal of such substances through licensed
contractors, but statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for clean-up costs.
Subsidiaries of EUA have been notified with respect to a number of sites where
they may be responsible for such costs, including sites where they may have
joint and several liability with other responsible parties. It is the policy
of the EUA System companies to notify liability insurers and to initiate
claims. However, EUA is unable to predict whether liability, if any, will be
assumed by, or can be enforced against, insurance carriers in these matters.
As of December 31, 1998, the EUA System had incurred costs of approximately
$7.7 million in connection with these sites. These amounts have been financed
primarily by internally generated cash. The EUA System is currently amortizing
substantially all of its incurred costs over a five-year period consistent with
prior regulatory recovery periods and is recovering certain of those costs in
rates.
EUA estimates that additional costs of up to $2.5 million may be incurred at
these sites through 1999 by its subsidiaries. Estimates beyond 1999 cannot be
made since site studies, which are the basis of these estimates, have not been
completed.
In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million. The clean-up costs were incurred by the Commonwealth of
Massachusetts at a site in which Blackstone has been named as a responsible
party. See Note J of "Notes to Consolidated Financial Statements" for further
discussion.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found everywhere there is electricity. Research to date has not conclusively
established a direct causal relationship between EMF exposure and human health.
Additional studies, which are intended to provide a better understanding of the
subject, are continuing. Management cannot predict the ultimate outcome of the
EMF issue.
Nuclear Power Issues - Montaup has a 4.01% ownership interest in Millstone 3,
an 1,154 mw nuclear unit that is jointly owned by a number of New England
utilities, including subsidiaries of Northeast Utilities (Northeast).
Subsidiaries of Northeast are the lead participants in Millstone 3. On March
30, 1996, it was necessary to shut down the unit following an engineering
evaluation which determined that four safety-related valves would not be able
to perform their design function during certain postulated events.
In October 1996, the NRC, which had raised numerous issues with respect to
Millstone 3 and certain of the other nuclear units in which Northeast and its
subsidiaries, either individually or collectively, have the largest ownership
shares, informed Northeast that it was establishing a Special Projects Office
to oversee inspection and licensing activities at Millstone. The Special
Projects Office was responsible for (1) licensing and inspection activities at
Northeast's Connecticut plants, (2) oversight of an Independent Corrective
Action Verification Program (ICAVP), (3) oversight of Northeast's corrective
actions related to safety issues involving employee concerns, and (4)
inspections necessary to implement NRC oversight of the plant's restart
activities. Also, the NRC directed Northeast to submit a plan for disposition
of safety issues raised by employees and retain an independent third-party to
oversee implementation of this plan.
On April 8, 1998, Northeast announced that Millstone 3 was ready for NRC
inspection, indicating that virtually all of the restart-required physical work
had been completed. On June 29, 1998, the NRC authorized Northeast to begin
restart activities of Millstone 3. The authorization was given after the NRC
staff verified that several final technical and programmatic issues were
resolved. Millstone 3 was restarted during the first week of July, and
returned to full power operation on July 14, 1998. The NRC will continue to
closely monitor Millstone 3's performance.
In August 1997, nine non-operating owners, including Montaup, who together own
approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
that agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC. The
arbitration and lawsuits seek to recover costs associated with replacement
power and operation and maintenance (O&M) costs resulting from the shutdown of
Millstone 3. The non-operating owners conservatively estimate that their
losses exceed $200 million. Montaup's share of this estimate is approximately
$8.0 million. In December 1997, Northeast filed a motion to dismiss the non-
operating owners' claims, or alternatively to stay the pending arbitration
until after the resolution of the arbitration case. These requests were denied
in July 1998.
Montaup paid its share of Millstone 3's O&M expenses during the prolonged
outage on a reservation of right basis. The fact that Montaup paid these
expenses is not an admission of financial responsibility for expenses incurred
during the outage.
EUA cannot predict the ultimate outcome of legal proceedings brought against
CL&P, WMECO and Northeast or the impact they may have on Montaup and the EUA
system.
Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating
facility in the process of decommissioning. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning, and recovery of
the investment in Connecticut Yankee is approximately $23.8 million and is
included with Other Liabilities on the Consolidated Balance Sheet as of
December 31, 1998. Also, due to anticipated recoverability, a regulatory asset
has been recorded for the same amount and is included with Other Assets.
On August 31, 1998, a FERC law judge rejected Connecticut Yankee's plan to
decommission the plant. The judge claimed that estimates of clean-up costs
were flawed and certain restoration costs were not supported. The judge also
said Connecticut Yankee could not pass on spent fuel storage costs to rate-
payers. The judge recommended that Connecticut Yankee withdraw its
decommissioning plan and submit a new plan which addresses the issues cited by
him. FERC will review the judge's recommendations and issue a decision on this
case in the coming months. If FERC concurs with the judge's recommendation,
this may result in a write down of certain Connecticut Yankee plant
investments. Montaup cannot predict the ultimate outcome of FERC's review .
On August 6, 1997, as the result of an economic evaluation, the Maine Yankee
Board of Directors voted to permanently close that nuclear plant. Montaup has
a 4.0% equity ownership in Maine Yankee. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning, and recovery of
the remaining investment in Maine Yankee is approximately $31.0 million and is
included with Other Liabilities on the Consolidated Balance Sheet as of
December 31, 1998. Also, due to recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets.
On November 6, 1997, Maine Yankee submitted an estimate of its costs, including
recovery of unamortized plant investment (including fuel), to FERC reflecting
the fact that the plant was no longer operating and had entered the
decommissioning phase. On January 14, 1998, the FERC accepted the new rates,
subject to refund, and amounts of Maine Yankee's collections for
decommissioning. FERC also granted intervention requests and ordered a public
hearing on the prudency of Maine Yankee's decision to shut down the plant and
on the reasonableness of the proposed rate amendments. On January 19, 1999,
Maine Yankee and the active intervening parties, including the Secondary
Purchasers, filed an Offer of Settlement with FERC which was supported by FERC
trial staff on February 8, 1999. Upon commission approval, this agreement will
constitute full settlement of issues raised in this proceeding.
Also, as a result of the August 1997 shutdown, Montaup and the other equity
owners were notified by the Secondary Purchasers that they would no longer make
payments for purchased power to Maine Yankee. The Secondary Purchase Contracts
are between the equity owners as a group and 30 municipalities throughout New
England. Presently, the equity owners are making payments to Maine Yankee to
cover the payments that would be made by the municipals. Prior to shutdown,
the municipals had been assigned 0.41% of Montaup's 4.0% share and Montaup had
retained a 3.59% share.
On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation of
Arbitration to the equity owners of Maine Yankee. On December 15, 1997, the
equity owners as a group filed at FERC a Complaint and Petition for
Investigation, Contract Modification, and Declaratory Order. On April 7, 1998,
a Maine judge denied the Secondary Purchasers' motion to compel arbitration and
indicated the jurisdictional question should be first decided by FERC. On
April 15, 1998, the Secondary Purchasers notified FERC of the judge's decision
and asked for expedited action on the pending complaint against them for non-
payment. A separately negotiated Settlement Agreement filed with FERC on
February 5, 1999, upon approval, would resolve issues raised by the Secondary
Purchasers by limiting the amount they will pay for decommissioning and
settling other points of contention.
Management does not believe that these settlements, if approved, will have a
material effect on EUA's future operating results or financial position.
On August 4, 1998, the Maine Yankee Board of Directors selected Stone & Webster
Engineering Corporation to execute a $250 million contract for the
decommissioning and decontamination of Maine Yankee. The decommissioning plan
includes an option for Stone & Webster to repower the Maine Yankee site with a
gas-fired plant.
Recent actions by the NRC, some of which are cited above, indicate that the NRC
has become more critical and active in its oversight of nuclear power plants.
EUA is unable to predict at this time what, if any, ramifications these NRC
actions will have on any of the other nuclear power plants in which Montaup has
an ownership interest or power contract.
Montaup is recovering through rates its share of estimated decommissioning
costs for the Millstone 3 and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
3 is approximately $22.4 million in 1998 dollars and Seabrook I is
approximately $14.4 million in 1998 dollars. These figures are based on
studies performed for the lead owners of the units. Montaup also pays into
decommissioning reserves, pursuant to contractual arrangements, at other
nuclear generating facilities in which it has an equity ownership interest or
life-of-unit entitlement. Such expenses are currently recovered through rates.
In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in federal
appeals court seeking a court order to require the Department of Energy (DOE)
to immediately establish a program for the disposal of spent nuclear fuel.
Under the Nuclear Waste Policy Act of 1992, the DOE was to provide for the
disposal of radioactive wastes and spent nuclear fuel starting in 1998 and has
collected funds from owners of nuclear facilities to do so. On February 19,
1998, Maine Yankee also filed a petition in the U.S. Court of Appeals seeking
to compel the Department of Energy to remove and dispose of the spent fuel at
the Maine Yankee site. Under their Standard Contract, the DOE had a deadline
for beginning the removal process at all nuclear plants on January 31, 1998,
which was not met. On May 5, 1998, the Court of Appeals denied several motions
brought in the proceeding, including several motions for injunctive relief
brought by the utility petitioners. In particular, the Court denied the
requests to require the DOE to immediately establish a program for the disposal
of spent nuclear fuel.
Also, Yankee Atomic, Connecticut Yankee, and Maine Yankee filed lawsuits
against the DOE in the U.S. Court of Federal Claims seeking damages of $70
million, $90 million and $128 million, respectively, as a result of the DOE's
refusal to accept the spent nuclear fuel.
In late October and early November 1998, the U.S. Court of Federal Claims
issued rulings with respect to Yankee Atomic, Maine Yankee, and Connecticut
Yankee finding that the DOE was financially responsible for failing to accept
spent nuclear fuel. These rulings clear the way for Yankee Atomic, Connecticut
Yankee and Maine Yankee to pursue at trial their individual damage claims.
Management cannot predict at this time the ultimate outcome of these actions.
The Year 2000 Issue - EUA's Year 2000 Program (the Program) is proceeding on
schedule. The Program is addressing the potential impact on computer systems
and embedded systems and components resulting from a common software program
code convention that utilizes two digits instead of four to represent a year.
If not addressed, the year 2000 may be systemically recognized as the year
1900, which could cause system or equipment failures or malfunctions, and
ultimately result in disruptions to Company operations.
EUA's State of Readiness: To address potential Year 2000 issues, EUA has
divided the focus of its Year 2000 Program into three major categories of
business activity: the generation and delivery of electricity to customers, the
acquisition of goods and services (including purchased power), and ongoing
general and administrative activities relating to the corporate infrastructure
and support functions, which includes among other things, billings and
collections.
EUA has adopted a four phase approach in addressing information technology (IT)
issues. The four phases are: Analysis, Remediation, Unit Testing and
Integration Testing. The Analysis phase consisted of two stages. The first
stage consisted of conducting an inventory of all products, applications and
services, department by department. The second stage consisted of an
assessment of the risk (potential impact and likelihood of failure) of each
item identified in the inventory. Items identified as not being Year 2000
ready are repaired or replaced during the Remediation phase. The Unit Testing
phase involves testing at the module, program and application level to assure
that each such item still functions properly after repair or replacement.
Finally, in the Integration Testing phase, dates are moved ahead, data are
aged, and all date conditions pertinent to each application or product are
tested "end-to-end" to assure that each item is tested in its final complete
environment. As of January 31, 1999, each phase described above was at the
following percentage of completion: Analysis-100%; Remediation-79%; Unit
Testing-78%; Integration Testing-11%. EUA is on schedule to achieve Year 2000
readiness for 100% of mission critical projects by June 30, 1999. For non-IT
projects, approximately 90% are either Year 2000 ready or not affected by the
Year 2000. The remaining items are in the process of being remediated and
tested and are scheduled to be Year 2000 ready by June 30, 1999.
Based on work completed as of December 31, 1998, the following date sensitive
IT systems and remediation needs were identified:
> Central Applications: 54 date sensitive items consisting of
centralized computing software that addresses major business
and operational needs were identified; 67% required repair or
replacement.
> Server Based Networks: 22 date sensitive items consisting of
networked applications, as well as supporting computing and
communications equipment were identified; 55% required repair
or replacement.
> Desktops: 48 categories of items typically consisting of
personal computer hardware and software were identified; 52% of
the such categories required repair or replacement.
> Infrastructure: 44 items consisting of components of central
IT operations (e.g., the mainframe computer, its operating
system and centralized database) were identified; 57% required
repair or replacement.
> Embedded Systems and Components: 3,977 items were identified;
96.3% are Y2K ready or inert. 3.7% must be tested -- any
failing will be replaced.
EUA has an ongoing process to identify and assess the Year 2000 readiness of
third parties with which it has a material relationship. First, a list of all
vendors utilized over the prior two years was developed from the accounts
payable system. Sub-lists were then developed and distributed to departments
based on the departmental allocation of charges for goods and services.
Departmental managements worked with the purchasing department to rank vendors
as critical, important or convenient. Approximately 150 vendors were
identified as being critical or important.
All vendors, regardless of rank, were contacted in writing requesting
information regarding their Year 2000 status. Vendors ranked as critical or
important were selected for additional inquiry, in the form of additional
written inquiry, telephone inquiries, review of vendor literature, review of
regulatory agency filings and web site reviews. Critical vendors included
providers of a variety of goods and services, such as telecommunications,
banking and other financial services, computer products and services,
equipment, fuel and mail delivery. As a result of this process, the purchasing
department and/or the department(s) utilizing the goods or services in question
have been able to confirm to their satisfaction that a significant majority of
the vendors have provided adequate evidence of their Year 2000 readiness. All
remaining vendors are being monitored as the process of gathering their Year
2000 readiness information continues. Where necessary, contingency plans will
be developed. This process is on schedule to be completed by June 30, 1999.
All critical vendors except one are Year 2000 ready or on schedule to be ready
by December 31, 1999. The single exception is the municipality which provides
infrastructure services to EUA Service Corporation. Contingency plans are in
the process of being developed for this municipality, as well as for all other
critical vendors. Such plans will identify workarounds for any critical vendor
for which there is not an alternative source.
Costs to Address EUA's Year 2000 Issues: Through December 31, 1998, EUA has
incurred costs of approximately $3.0 million to address Year 2000 issues,
including approximately $1.5 million of non-incremental labor, $1.2 million of
capital expenditures and $300,000 of consulting and other costs. Due to their
nature, the capital expenditures and the consulting and other costs are not
allocable to the various phases of EUA's Year 2000 Program identified above;
however, the $1.5 million non-incremental labor costs can be assigned to
particular phases of the Company's Year 2000 project, in the following amounts:
Analysis --$600,000; Remediation--$400,000; Unit Testing--$400,000; and
Integration Testing--$100,000. EUA estimates it will incur additional costs
approximating $7.0 million during the period January 1, 1999 through March 31,
2000, to complete its resolution of Year 2000 issues, including approximately
$5.5 million of non-incremental labor, $500,000 of capital expenditures and
$1.0 million of consulting and other costs. Again, due to the nature of the
capital, consulting and other costs, they are generally not allocable to
particular phases of EUA's Year 2000 Program; however, certain non-incremental
labor costs may be assigned as follows: Remediation--$150,000; Unit Testing--
$150,000; Integration Testing--$4 million. In addition, EUA estimates it will
incur approximately $1.2 million in non-incremental labor costs during the
period July 1, 1999 through March 31, 2000 for year 2000 related activities
such as: retesting, documentation review, communications outreach and customer
and vendor awareness programs, training, maintaining a "clean room"
environment, transition weekend preparations, transition weekend activities,
and post-transition weekend problem resolution. Because 70% of the total
estimated costs associated with the Year 2000 issue relate to non-incremental
internal labor, management continues to believe that the Year 2000 will not
present a material incremental impact to future operating results or financial
condition.
Risks of EUA's Year 2000 Issues: EUA's first priority continues to be the
minimization of any potential disruptions to electric service as a result of
the Year 2000. The provision of electric service depends in large part on the
viability of the New England power grid which is managed by ISO/NEPOOL. EUA is
actively participating on ISO/NEPOOL's Year 2000 operating and oversight
committees. EUA's assessment of its own transmission and distribution
equipment and facilities indicated that the risk of failure of this equipment
does not appear to be significant. However, due to the interconnectivity of
the New England power grid, and the reliance on many other entities also
connected to the grid, it is not possible to conclude with certainty that there
will be no significant interruptions in service.
In addition, dependable voice and data telecommunications are critical to EUA's
ongoing operations. EUA's internal telecommunications systems are either Year
2000 ready now, or on schedule to become Year 2000 ready by June 30, 1999. EUA
also relies heavily on external telecommunication systems, i.e., the local and
regional telephone systems, and has identified these providers as critical
vendors. EUA has gathered extensive documentation regarding the Year 2000
efforts and status of the regional telephone companies upon which it relies.
In addition, EUA has also had face-to-face meetings with representatives of
these companies and attended public conferences sponsored by these companies,
at which they have described their Year 2000 process and progress. Each of
these companies anticipates being Year 2000 ready and devoid of major system
failures. Nevertheless, EUA has provided for several methods for maintaining
adequate communications. For example, if the regional, land-line telephone
systems were not in service, EUA could rely on mobile or cellular telephones.
If those failed, EUA maintains mobile radios. Further, all of EUA's operating
locations, including EUA Service Corporation's, are linked through a captive
microwave telecommunications system.
No other significant reasonably likely failure scenarios stemming solely from
Year 2000 related problems have been identified thus far. Accordingly, EUA
does not currently believe that any Year 2000 related risks in and of
themselves constitute reasonably likely worst case scenarios. Rather, EUA's
most reasonably likely Year 2000 related worst case scenario would be the
occurrence of isolated year 2000 failures such as described above in
conjunction with a severe winter storm. However, EUA believes that such year
2000 failures would not likely affect whether the storm event would have a
material impact on EUA's business or financial condition. In this context, and
based on its communications with key vendors and customers and its long
experience with storm events, EUA does not currently anticipate significant
adverse effects on its relationships with its customers or vendors, or any
resulting material adverse effects on its business or operations.
Year 2000 Contingency Plans: Contingency planning teams consisting of managers
and employees experienced in system reliability, disaster recovery and risk
have been established and are responsible for developing contingency plans.
The overall strategy will be to identify Year 2000 risks, both internal and
external to EUA, that could have a material impact on EUA's operations or
financial well being. Preliminary plans are expected by the end of the first
quarter of 1999. Final plans are scheduled to be in place and ready to
implement, if necessary, by June 30, 1999.
Summary: The amount of effort and resources necessary to address Year 2000
issues and make EUA Year 2000 ready is significant. There are dedicated teams
in place to ensure EUA's transition into the next century occurs with minimal
disruption. By the end of December 1998, EUA had the equivalent of twenty full
time employees working on its Year 2000 project. Beginning in 1999, during peak
times, up to 7 contract programmers have been added to help EUA's permanent IT
staff deal with internal Year 2000 activities. Also, more than 12
vendor-provided IT professionals have been used to help with various short
duration Year 2000 projects specifically targeting that vendor's products.
EUA's Year 2000 program is on schedule and in accordance with time tables and
program points published by the North American Electric Reliability Council.
In addition, EUA is utilizing outside technical consultants and other experts
to help ensure that its Year 2000 program remains on schedule and effective and
that risk and resource issues are appropriately assessed and addressed.
Management believes EUA's Year 2000 project is well managed and has the
appropriate resources and plans in place to ensure the Company is positioned
for a successful transition to the Year 2000.
The foregoing constitutes a Year 2000 Statement and Readiness Disclosure
subject to the protections afforded it as such by the federal Year 2000
Information and Readiness Disclosure Act of 1998.
New Accounting Standards - In March 1998, The Accounting Standards Executive
Committee of the American Institute of Certified Public Accountants (AICPA)
issued Statement of Position 98-1, Accounting For the Costs of Computer
Software Developed or Obtained for Internal Use (SOP 98-1), effective in 1999.
SOP 98-1 provides specific guidance on whether to capitalize or expense costs
within its scope. The Company does not expect SOP 98-1 to have a material
impact on its financial position or results of operations.
In April 1998, the AICPA issued SOP 98-5, "Reporting on the Costs of Start-Up
Activities." EUA is required to adopt the SOP for 1999. SOP 98-5 defines
start-up activities as one-time activities an entity undertakes when it opens a
new facility, introduces a new product line or service, conducts business in a
new territory or with a new class of customer or beneficiary, initiates a new
process in an existing facility or commences some new operation. The statement
covers the accounting for organization costs and decrees that any such costs
should be expensed as incurred in the same manner as the other start-up costs.
The statement requires entities to expense previously capitalized costs in the
year of adopting SOP 98-5. Although EUA can not currently quantify the impact
of adoption as of January 1, 1999, Management estimates the application of SOP
98-5 will not have a material impact on the financial statements.
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities," which is
effective in 2000. This statement requires the recognition of all derivative
instruments as either assets or liabilities in the statement of financial
position and the measurement of those instruments at fair value. The Company
is currently evaluating the impact SFAS 133 will have on its financial position
or results of operations.
Other - A pending class action, filed on March 2, 1998, in the Massachusetts
Supreme Judicial Court naming all Massachusetts electric distribution
companies, including Eastern Edison, and certain Massachusetts state agencies
as defendants, seeks to invalidate certain sections of the Electric Utility
Restructuring Act of 1997. The Act directs the Massachusetts Department of
Telecommunications and Energy to impose mandatory charges on all electricity
sold to customers, except those served by a municipal lighting plant, to fund
energy efficiency activities and to promote renewable energy projects. In
addition to declaratory judgment, plaintiffs seek remittance of monies paid to
each distribution company by customers along with any interest earned. The
outcome of this class action is unknown at this time however, Eastern Edison is
vigorously defending the lawsuit.
EUA occasionally makes forward-looking projections of expected future
performance or statements of our plans and objectives. These forward-looking
statements may be contained in filings with the SEC, press releases and oral
statements. This report contains information about the Company's future
business prospects including, without limitation, statements about the
potential impact of Year 2000 issues on the Company's financial condition or
results. These statements are considered "forward-looking" within the meaning
of the Private Securities Litigation Reform Act. These statements are based on
the Company's current plans and expectations and involve risks and
uncertainties that could cause actual future activities and results of oper-
ations to be materially different from those set forth in the forward-looking
statements. The Company expressly undertakes no duty to update any forward-
looking statement.
"Management's Discussion and Analysis of Financial Condition and Review of
Operations" provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Consolidated Financial Statements" and "Notes to Consolidated Financial
Statements" to arrive at a more complete understanding of such matters.
Part II - Item 8. Financial Statements and Supplementary Data
This item is amended and restated in its entirety as follows:
The information required by this Item with respect to Blackstone and Eastern
Edison is incorporated herein by reference to page 2 and pages 12 through 31 in
the 1998 Blackstone Annual Report and page 2 and pages 16 through 39 in the
1998 Eastern Edison Annual Report (Exhibits 13-1.01 and 13-1.08) for Blackstone
and Eastern Edison, respectively, as previously filed with the Registrants'
Form 10-K.
The information required by this Item with respect to EUA previously
incorporated herein by reference to pages 26 through 41 in the 1998 EUA Annual
Report to Shareholders (Exhibit 13-1.03 of the Registrants' 1998 Form 10-K) is
replaced in its entirety by the following:
<TABLE>
Consolidated Statements of Income
($ in thousands except Common Shares and per Share Amounts)
<CAPTION>
Years Ended December 31, 1998 1997 1996
<S> <C> <C> <C>
OPERATING REVENUES $538,801 $568,513 $527,068
OPERATING EXPENSES:
Fuel 99,781 110,724 92,166
Purchased Power-Demand 108,936 119,485 118,830
Other Operations 155,943 162,464 154,831
Voluntary Retirement Incentives 1,416
Maintenance 20,143 30,432 25,047
Depreciation and Amortization 51,079 46,941 45,478
Taxes - Other Than Income 23,323 24,021 23,933
Income Taxes 17,957 14,223 10,942
Total Operating Expenses 477,162 509,706 471,227
Operating Income 61,639 58,807 55,841
Equity in Earnings of Jointly
Owned Companies 9,524 9,466 10,698
Allowance for Other Funds Used
During Construction 173 162 452
Loss on Disposal of Cogeneration
Operations (3,172)
Income Tax Impact of Loss on
Disposal of Cogeneration Operations 1,110
Other Income - Net 4,940 10,986 5,054
Income Before Interest Charges 74,214 79,421 72,045
INTEREST CHARGES:
Interest on Long-Term Debt 28,288 32,198 34,035
Amortization of Debt Expense
and Premium - Net 1,813 2,548 2,620
Other Interest Expense 7,745 5,245 4,199
Allowance for Borrowed Funds Used
During Construction (Credit) (647) (835) (1,735)
Net Interest Charges 37,199 39,156 39,119
Net Income 37,015 40,265 32,926
Preferred Dividends of Subsidiaries 2,305 2,305 2,312
Consolidated Net Earnings $34,710 $37,960 $30,614
Average Common Shares Outstanding 20,435,997 20,435,997 20,436,217
Consolidated Basic and Diluted
Earnings per Share $1.70 $1.86 $1.50
Dividends Paid per Share $1.66 $1.66 $1.645
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Years Ended December 31,
($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $37,015 $40,265 $32,926
Adjustments to Reconcile Net Income
to Net Cash Provided from
Operating Activities:
Depreciation and Amortization 56,308 51,615 50,690
Amortization of Nuclear Fuel 1,265 1,067 1,676
Deferred Taxes (17,854) (6,317) 11,610
Non-cash Expenses/(Gains) on
Sales of Investments in
Energy Savings Projects 10,002 15,993 8,262
Investment Tax Credit, Net (3,081) (1,201) (1,207)
Allowance for Other Funds Used
During Construction (173) (162) (452)
Collections and Sales of Project
Notes and Leases Receivable 17,261 19,148 7,776
Other - Net (1,514) (5,726) 6,373
Changes in Operating Assets and Liabilities:
Accounts Receivable (2,621) (2,494) (5,777)
Materials and Supplies (2,232) 2,929 2,385
Accounts Payable (6,018) 1,225 (1,958)
Taxes Accrued 11,145 59 (1,539)
Other - Net (2,563) (664) 4,930
Net Cash Provided from
Operating Activities 96,940 115,737 115,695
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (51,201) (76,118) (62,730)
Proceeds from Divestiture of
Generation Assets 76,873
Collections on Notes and Lease
Receivables of EUA Cogenex 11,558 10,076 3,665
Other Investments (2,071) 312 (3,889)
Net Cash Provided from
(Used in) Investing Activities 35,159 (65,730) (62,954)
CASH FLOW FROM FINANCING ACTIVITIES
Redemptions:
Long-Term Debt (73,122) (28,617) (20,617)
Preferred Stock - (90)
Premium on Reacquisition and
Financing Expenses - (15)
EUA Common Share Dividends Paid (33,924) (33,924) (33,618)
Subsidiary Preferred Dividends Paid (2,305) (2,305) (2,314)
Net Increase in Short-Term Debt 2,090 9,636 12,308
Net Cash (Used in)
Financing Activities (107,261) (55,210) (44,346)
NET INCREASE (DECREASE) IN CASH AND
TEMPORARY CASH INVESTMENTS: 24,838 (5,203) 8,395
Cash and Temporary Cash Investments at
Beginning of Year 7,252 12,455 4,060
Cash and Temporary Cash Investments at
End of Year $32,090 $7,252 $12,455
Cash Paid during the year for:
Interest (Net of Amounts
Capitalized) $37,087 $40,172 $40,658
Income Taxes $25,976 $28,921 $11,530
Conversion of Investments in Energy
Savings Projects to Notes and
Leases Receivable $4,529 $5,404 $7,779
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
Years Ended December 31, ($ in thousands) 1998 1997
<S> <C> <C>
ASSETS
Utility Plant and Other Investments:
Utility Plant in Service $1,000,243 $1,079,361
Less Accumulated Provisions for
Depreciation and Amortization 353,780 376,722
Net Utility Plant in Service 646,463 702,639
Construction Work in Progress 5,151 5,538
Net Utility Plant 651,614 708,177
Non-utility Property - Net 55,274 71,516
Investments in Jointly Owned Companies 69,485 69,749
Other 55,320 62,834
Total Utility Plant and Other
Investments 831,693 912,276
Current Assets:
Cash and Temporary Cash Investments 32,090 7,252
Accounts Receivable:
Customers, Net 55,286 64,214
Accrued Unbilled Revenues 10,655 14,103
Other 29,326 14,329
Notes Receivable 27,078 27,693
Materials and Supplies (at average cost):
Fuel 6,024 4,304
Plant Materials and Operating Supplies 7,410 6,897
Other Current Assets 8,448 7,177
Total Current Assets 176,317 145,969
Other Assets 294,628 212,507
Total Assets $1,302,638 $1,270,752
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $373,674 $373,467
Non-Redeemable Preferred Stock of
Subsidiaries - Net 6,900 6,900
Redeemable Preferred Stock of
Subsidiaries - Net 27,995 27,612
Long-Term Debt - Net 310,346 332,802
Total Capitalization 718,915 740,781
Current Liabilities:
Short-Term Debt 63,574 61,484
Long-Term Debt Due Within One Year 21,911 72,518
Accounts Payable 29,018 35,036
Taxes Accrued 14,208 3,063
Interest Accrued 6,997 8,624
Other Current Liabilities 34,908 33,327
Total Current Liabilities 170,616 214,052
Other Liabilities 271,078 152,526
Accumulated Deferred Taxes 142,029 163,393
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $1,302,638 $1,270,752
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
Years Ended December 31, ($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
Retained Earnings - Beginning of Year $56,062 $52,404 $56,228
Consolidated Net Earnings 34,710 37,960 30,614
Total 90,772 90,364 86,842
Dividends Paid - EUA Common Shares 33,924 33,924 33,618
Other 382 378 820
Retained Earnings - Accumulated since
June 1991 Accounting Reorganization $56,466 $56,062 $52,404
</TABLE>
<TABLE>
Consolidated Statements of Equity Capital & Preferred Stock
<CAPTION>
Years Ended December 31, ($ in thousands) 1998 1997
<S> <C> <C>
EASTERN UTILITIES ASSOCIATES:
Common Shares:
$5 par value 36,000,000 shares authorized,
20,435,997 shares outstanding in 1998 and 1997 $102,180 $102,180
Other Paid-In Capital 218,959 219,156
Common Share Expense (3,931) (3,931)
Retained Earnings - Accumulated since June 1991
Accounting Reorganization 56,466 56,062
Total Common Equity 373,674 373,467
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
Non-Redeemable Preferred:
Blackstone Valley Electric Company:
4.25% $100 par value 35,000 shares <F1> 3,500 3,500
5.60% $100 par value 25,000 shares <F1> 2,500 2,500
Premium 129 129
Newport Electric Corporation:
3.75% $100 par value 7,689 shares <F1> 769 769
Premium 2 2
Total Non-Redeemable Preferred Stock 6,900 6,900
Redeemable Preferred:
Eastern Edison Company:
65/8% $100 par value 300,000 shares <F2> 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Costs (1,670) (2,053)
Total Redeemable Preferred Stock 27,995 27,612
Total Preferred Stock of Subsidiaries $34,895 $34,512
<FN>
<F1> Authorized and Outstanding.
<F2> Authorized 400,000 shares. 300,000 shares outstanding at December 31, 1998.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Indebtedness
<CAPTION>
Years Ended December 31, ($ in thousands) 1998 1997
<S> <C> <C>
EUA Service Corporation:
10.2% Secured Notes due 2008 $6,200 $7,900
EUA Cogenex Corporation:
7.0% Unsecured Notes due 2000 50,000 50,000
9.6% Unsecured Notes due 2001 9,600 12,800
10.56% Unsecured Notes due 2005 24,500 28,000
EUA Ocean State Corporation:
9.59% Unsecured Notes due 2011 26,114 28,590
Blackstone Valley Electric Company:
First Mortgage Bonds:
9 1/2% due 2004 (Series B) 9,000 10,500
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds due 2014 <F1> 6,500 6,500
Eastern Edison Company
First Mortgage and Collateral Trust Bonds:
5 7/8% due 1998 - 20,000
5 3/4% due 1998 - 40,000
7.78 % Secured Medium Term Notes due 2002 35,000 35,000
6 7/8% due 2003 40,000 40,000
6.35% due 2003 8,000 8,000
8.0% due 2023 40,000 40,000
Pollution Control Revenue Bonds:
5 7/8% due 2008 40,000 40,000
Newport Electric Corporation:
First Mortgage Bonds:
9.0% due 1999 1,386 1,386
9.8% due 1999 8,000 8,000
8.95% due 2001 1,950 2,600
Small Business Administration Loan:
6.5% due 2005 533 628
Variable Rate Revenue Refunding
Bonds due 2011 <F1> 7,925 7,925
Unamortized (Discount) - Net (451) (509)
332,257 405,320
Less Portion Due Within One Year 21,911 72,518
Total Long-Term Debt - Net $310,346 $332,802
<FN>
<F1> Weighted average interest rate was 3.6% for 1998 and 3.7% for 1997.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
Notes to Consolidated Financial Statements December 31, 1998, 1997 and 1996
(A) Nature of Operations and Summary of Significant Accounting Policies:
General: Eastern Utilities Associates (EUA) is a public utility holding
company headquartered in Boston, Massachusetts. Its subsidiaries are
principally engaged in the generation, transmission, distribution and sale of
electricity; energy related services such as energy management; and promoting
the conservation and efficient use of energy. See "Generation Divestiture"
below for a discussion of EUA's planned divestiture of generating capacity.
Estimates: 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.
Basis of Consolidation: The consolidated financial statements include the
accounts of EUA and all subsidiaries. All material intercompany transactions
between the consolidated subsidiaries have been eliminated.
System of Accounts: The accounts of EUA and its consolidated subsidiaries are
maintained in accordance with the uniform system of accounts prescribed by the
regulatory bodies having jurisdiction.
Jointly Owned Companies: Montaup Electric Company (Montaup) follows the equity
method of accounting for its stock ownership investments in jointly owned
companies including four regional nuclear generating companies. Montaup's
investments in these nuclear generating companies range from 2.5% to 4.5%.
Three of the four facilities, Yankee Atomic, Connecticut Yankee and Maine
Yankee, have been permanently shut down and are in the process of
decommissioning. Montaup's share of total estimated costs for the permanent
shutdown, decommissioning and recovery of the investment in Yankee Atomic,
Connecticut Yankee and Maine Yankee is $3.7 million, $23.8 million and $31.0
million, respectively. These amounts are included with Other Liabilities on
the Consolidated Balance Sheet as of December 31, 1998. Also, due to
anticipated recoverability, a regulatory asset has been recorded for the same
amount and is included with Other Assets. Montaup is entitled to electricity
produced from the remaining facility, Vermont Yankee, based on its ownership
interest and is billed for its entitlement pursuant to a contractual agreement
which is approved by the Federal Energy Regulatory Commission (FERC).
Montaup also has a stock ownership investment of 3.27% in each of two companies
which own and operate certain transmission facilities between the Hydro Quebec
electric system and New England.
EUA Ocean State Corporation (EUA Ocean State) follows the equity method of
accounting for its 29.9% partnership interest in the Ocean State Power Project
(OSP). Also, EUA Energy Investment follows the equity method of accounting for
its partnership interest in BIOTEN, G.P. and for its 20% stock ownership in
Separation Technologies, Inc. EUA is attempting to restructure its partnership
interest in the BIOTEN, G.P. to a preferred equity position. These ownership
interests and Montaup's stock ownership investments are included in
"Investments in Jointly Owned Companies" on the Consolidated Balance Sheet.
Plant and Depreciation: Utility plant is stated at original cost. The cost of
additions to utility plant includes contracted work, direct labor and material,
allocable overhead, allowance for funds used during construction and indirect
charges for engineering and supervision. For financial statement purposes,
depreciation is computed on the straight-line method based on estimated useful
lives of the various classes of property. On a consolidated basis, provisions
for depreciation on utility plant were equivalent to a composite rate of
approximately 3.5% in 1998, 3.6% in 1997, 3.7% in 1996 based on the average
depreciable property balances at the beginning and end of each year. Beginning
in 1998, coincident with billing a contract termination charge (CTC) to its
retail affiliates, Montaup commenced recovery of its net investment in
generation related assets through the CTC over a twelve-year period. The
difference between the annual recovery and annual depreciation expense pursu-
ant to Generally Accepted Accounting Principles is being deferred. Non-utility
property and equipment of EUA Cogenex Corporation (EUA Cogenex) is stated at
original cost. For financial statement purposes, depreciation on office
furniture and equipment, computer equipment and real property is computed on
the straight-line method based on estimated useful lives ranging from five to
forty years. Project equipment is depreciated over the term of the applicable
contracts or based on the estimated useful lives, whichever is shorter, ranging
from five to fifteen years.
Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest:
AFUDC represents the estimated cost of borrowed and equity funds used to
finance the EUA System's construction program. In accordance with regulatory
accounting, AFUDC is capitalized as a cost of utility plant in the same manner
as certain general and administrative costs. AFUDC is not an item of current
cash income but is recovered over the service life of utility plant in the form
of increased revenues collected as a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 8.0% in 1998 and 1997, and 9.0%
in 1996. The caption "Allowance for Borrowed Funds Used During Construction"
also includes interest capitalized for non-regulated entities in accordance
with FASB Statement No. 34.
Operating Revenues: Utility revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison Company
(Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue
the estimated amount of unbilled revenues at the end of each month to match
costs and revenues more closely. Montaup recognizes revenues when billed. In
1998, Montaup and the Retail Subsidiaries also began recording revenues in an
amount management believes to be recoverable pursuant to provisions of approved
settlement agreements and enabling state legislation. Provisions of the
approved restructuring settlement agreements in conjunction with accounting
provisions of SFAS 71 allow Montaup and the retail subsidiaries
to accrue and/or defer revenue related to the future recovery of certain items.
Montaup has accrued revenues and recorded associated regulatory assets and
liabilities for certain items during 1998 commencing with the implementation of
the aforementioned settlement agreements and billing of the Contract
Termination Charge (CTC), January 1, 1998 in Rhode Island and March 1, 1998 in
Massachusetts. Montaup was authorized to accrue an amount of lost revenue equal
to the difference in revenues Montaup would have collected under its previously
approved rates and revenues collected pursuant to the settlement agreements.
The settlements also provide Montaup with a nuclear PBR provision under which
Montaup normalizes expenses and revenues for 80% of going forward operations of
Montaup's nuclear interests. Montaup was also allowed to accrue a return
enhancement related to stranded investments charged to its Rhode Island retail
affiliates during the generation divestiture period as an incentive to divest.
Also, Montaup is normalizing the difference between GAAP depreciation expense
on generation plant assets prior to divestiture and the recovery level included
in the settlement agreements. Montaup has also accrued revenue related to the
two-month delay in implementing the Massachusetts settlement agreement from
January 1, 1998 to March 1, 1998. Finally, Montaup normalizes for the
difference in actual versus estimated CTC variable components costs and
revenues.
Settlement provisions and SFAS 71 also provide for Eastern Edison to accrue
revenue equal to the approved deferral of standard offer costs which will be
collected in the future.
The following table reflects the nature and amount of accrued and/or deferred
revenue and the associated balance sheet placement.
Amount Balance
Accrued Sheet
(Deferred) Placement
$000
Lost revenue $ 18,527 Other Asset/Accrued CTC Assets
Mass. Delay Credit 768 Other Asset/Accrued CTC Assets
R.I. Return True-up 1,970 Other Asset/Accrued CTC Assets
Depr. Norm. (12 yr S/L vs.
CTC Level) 10,933 Other Asset/Accrued CTC Assets
Depr. Norm (GAAP vs.
12 yr S/L) (14,294) Other Liab./Reg. Liab.
Nuclear PBR 3,933 Other Asset/Other Reg. Assets
CTC Variable
Component Norm. (23,793) Other Liab./Reg. Liab.
Eastern Edison Standard
Offer Deferral 8,782 Other Accts. Rec./Reg. Assets
EUA Cogenex's revenues are recognized based on financial arrangements
established by each individual contract. Under paid-from-savings contracts,
revenues are recognized as energy savings are realized by customers. Revenue
from the sale of energy savings projects and sales-type leases are recognized
when the sales are complete. Interest on the financing portion of the
contracts is recognized as earned at rates established at the outset of the
financing arrangement. All construction and installation costs are recognized
as contract expenses when the contract revenues are recorded. In circumstances
in which material uncertainties exist as to contract profitability, cost
recovery accounting is followed and revenues received under such contracts are
first accounted for as recovery of costs to the extent incurred.
Federal Income Taxes: EUA and its subsidiaries generally reflect in income the
estimated amount of taxes currently payable, and provide for deferred taxes on
certain items subject to temporary timing differences to the extent permitted
by the various regulatory agencies. EUA's rate-regulated subsidiaries
amortize previously deferred investment tax credits (ITC) over the productive
lives of the related assets. Beginning in 1998, Montaup is amortizing
previously deferred ITC related to generation investments recoverable through
the CTC over a twelve-year period. Unamortized ITC related to the Canal 2
generating unit was reversed at the time of the Canal 2 sale, December 30,
1998.
Cash and Temporary Cash Investments: EUA considers all highly liquid
investments and temporary cash investments with a maturity of three months or
less when acquired to be cash equivalents.
Other Assets: The components of Other Assets at December 31, 1998 and 1997 are
detailed as follows:
<TABLE>
<CAPTION>
($ in thousands) 1998 1997
<S> <C> <C>
Regulatory Assets:
Unamortized losses on reacquired debt $10,979 $12,299
Unrecovered plant and
decommissioning costs 66,934 68,345
Deferred FAS 109 costs (Note B) 50,167 57,732
Deferred FAS 106 costs 9,167 3,310
Mendon Road judgment (Note J) 6,154 6,154
Unrecovered CTC assets 33,161
Accrued CTC assets 32,198
Other regulatory assets 21,947 15,524
Total regulatory assets 230,707 163,364
Other deferred charges and assets:
Split dollar life insurance premiums 24,803 15,502
Unamortized debt expenses 3,381 3,954
Goodwill 6,436 6,642
Other 29,301 23,045
Total Other Assets $294,628 $212,507
</TABLE>
Regulatory assets represent deferred costs for which future revenues are
expected in accordance with regulatory practices. These costs are expensed
when the corresponding revenues are received in order to appropriately match
revenues and expenses.
Regulatory Accounting: Core Electric companies are subject to certain
accounting rules that are not applicable to other industries. These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact of
certain costs that are expected to be recovered in future rates. In light of
approved restructuring settlement agreements and restructuring legislation in
both Massachusetts and Rhode Island, EUA has determined that Montaup no longer
will apply the provisions of Financial Accounting Standards Board's (FASB)
Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting for the
Effects of Certain Types of Regulation" for the generation portion of its
business. Montaup ceased applying SFAS 71 to its ongoing generation portion of
its business effective January 1, 1998. Approved restructuring settlement
agreements with parties in Massachusetts and Rhode Island, the two states in
which Montaup operates, allow Montaup full recovery or stranded generation
investments as of December 31, 1997 and as such Montaup incurred no asset
impairment. As disclosed in Footnote A under the caption "GENERATION
DIVESTITURE", Montaup has agreements to divest all of its generation assets and
power purchase agreements with the exception of its 4.0% (46mw) ownership
interest in the Millstone 3 nuclear station and is 12 mw entitlement from the
Vermont Yankee nuclear unit. Post-divestiture ongoing generation operations
will include the two aforementioned nuclear units in which Montaup will
continue to have an interest. The approved settlement agreements also provide
Montaup with recovery of 100% of embedded nuclear investments as of December
31, 1997 and recovery of 80% of its post 1997 on going nuclear generation
operations. Because only 20% of Montaup's remaining nuclear operations will no
longer be subject to the accounting treatment pursuant to SFAS 71 and would be
subject to market risk, Management believes that the discontinuation of SFAS 71
for Montaup's post-divestiture generation business will not have a material
impact on EUA's results of operations or financial position. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
Generation Divestiture: Terms of approved electric utility restructuring
settlement agreements provide that EUA exit the electric generation business.
Through separately negotiated agreements, EUA has agreements to divest all of
its generation assets and power purchase contracts, with the exception of its
4.0% (46 mw) ownership interest in the Millstone 3 nuclear station and its 12
mw entitlement from Vermont Yankee. All of the agreements are subject to
approval of various state and federal regulatory agencies.
EUA has agreed to sell generating assets totaling 509 mw to various parties for
$133.2 million in aggregate. The net proceeds from the sales, as defined in
the settlement agreements, will be recorded as a regulatory liability at the
time of sale and will be returned to customers via a Residual Value Credit
(RVC) through the year 2009.
EUA has also agreed to make contribution payments to two parties in exchange
for their assumption of all future obligations under six purchased power
contracts. These fixed monthly payments ranging from $850,000 to $2.6 million,
will be made from the effective date through 2009. EUA may be required to
record a liability for these fixed contributions, but in such an event would
record a regulatory asset for a like amount due to recoverability. In
addition, EUA has agreed to a buyout of its obligations under the Pilgrim
Nuclear purchased power contract in conjunction with the sale of the unit by
Boston Edison Co. (BEC) to Entergy Nuclear Generating Co. (Entergy). This
agreement provides for a buyout payment by EUA to BEC of $115.8 million ,
assuming a June 30, 1999 closing, along with a short-term, fixed-price
purchased power agreement with Entergy for declining shares of the unit's
output beginning with 11% in 1999 and ending with 5.5% in 2004. Entergy will
assume all future operating and decommissioning obligations.
EUA will continue to attempt to sell and/or transfer its minority interests in
Millstone 3 and Vermont Yankee. Until such time as these units are divested,
EUA will share 80% of the operating costs and revenues associated with the
units with customers and 20% with shareholders.
(B) Income Taxes:
EUA adopted FASB Statement No. 109, "Accounting for Income Taxes" (FAS109),
which requires recognition of deferred income taxes for temporary differences
that are reported in different years for financial reporting and tax purposes
using the liability method. Under the liability method, deferred tax
liabilities or assets are computed using the tax rates that will be in effect
when temporary differences reverse. Generally, for regulated companies, the
change in tax rates may not be immediately recognized in operating results
because of ratemaking treatment and provisions in the Tax Reform Act of 1986.
Total deferred tax assets and liabilities for 1998 and 1997 include the
following:
<TABLE>
Deferred Tax Deferred Tax
Assets Liabilities
<CAPTION>
($ in thousands) 1998 1997 1998 1997
<S> <C> <C> <C> <C>
Plant Related Plant Related
Differences $22,776 $18,947 Differences $185,590 $191,274
Deregulation 23,301 Refinancing
Costs 1,325 1,406
NOL Deregulation 12,993
Carryforward 1,973 2,294 Employee
Benefit
Employee Accruals 4,481 3,670
Benefit
Accruals 5,294 4,975
Acquisitions 3,334 3,650
Other 14,075 14,157 Other 8,393 11,066
Total $70,753 $44,023 Total $212,782 $207,416
</TABLE>
As of December 31, 1998 and 1997, EUA has recorded on its Consolidated Balance
Sheet a regulatory liability to ratepayers of approximately $15.5 million and
$18.8 million respectively. These amounts primarily represent excess deferred
income taxes resulting from the reduction in the federal income tax rate and
also include deferred taxes provided on investment tax credits. Also at
December 31, 1998 and 1997, a regulatory asset of approximately $50.2 million
and $57.7 million, respectively, has been recorded, representing the cumulative
amount of federal income taxes on temporary depreciation differences which were
previously flowed through to ratepayers.
<TABLE>
Components of income tax expense for the year 1998, 1997, and 1996 are as
follows:
<CAPTION>
($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
Federal:
Current $30,755 $17,249 $ (231)
Deferred (14,054) (4,901) 9,838
Investment Tax Credit, Net (3,000) (1,120) (1,125)
13,701 11,228 8,482
State:
Current 5,217 3,623 2,823
Deferred (961) (628) (363)
4,256 2,995 2,460
Charged to Operations 17,957 14,223 10,942
Charged to Other Income:
Current 4,416 9,142 4,798
Deferred (2,839) (789) 2,135
Investment Tax Credit, Net (81) (81) (82)
1,496 8,272 6,851
Total Income Tax Expense $19,453 $22,495 $17,793
</TABLE>
Total income tax expense was different from the amounts computed by applying
federal income tax statutory rates to book income subject to tax for the
following reasons:
<TABLE>
<CAPTION>
($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
Federal Income Tax Computed
at Statutory Rates $19,764 $21,966 $17,751
(Decrease) Increase in Tax from:
Equity Component of AFUDC (60) (57) (189)
Depreciation Differences 1,320 (12) 2
Amortization of ITC (3,081) (1,201) (1,207)
State Taxes, Net of Federal
Income Tax Benefit 2,803 2,092 1,952
Other (1,293) (293) (516)
Total Income Tax Expense $19,453 $22,495 $17,793
</TABLE>
(C) Capital Stock:
The Agreement and Plan of Merger dated February 1, 1999 by and among New
England Electric System (NEES) and EUA, which is subject to EUA shareholder and
various regulatory agencies' approval, provides for NEES to purchase all of the
outstanding EUA shares for $31 per share in cash. The transaction is expected
to be completed by early 2000.
There was no change in the number of common shares outstanding during 1998 and
1997.
As permitted, the Company accounts for its stock-based compensation, as
discussed below, using the method prescribed in Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" (APB25) and as
permitted under FASB Statement No. 123, "Accounting for Stock-Based
Compensation" (FAS123).
The Company established a Restricted Stock Plan in 1989. Under the Restricted
Stock Plan, executives and certain key employees may be granted restricted
common shares of the Company. In 1998, 1997 and 1995, approximately 74,000
shares, 95,000 shares and 61,000 shares, respectively, of restricted common
shares, valued at approximately $1.8 million, $2.4 million and $1.4 million,
respectively, were granted. The issued shares are restricted for a period
ranging from two to five years and all shares are subject to forfeiture if
specified employment services are not met. There are no exercise prices
related to these share grants. During the applicable restriction period, the
recipient has all the voting, dividend, and other rights of a record holder
except that the shares are nontransferable. The annual compensation expense
related to these grant awards was approximately $1.6 million in 1998 and was
immaterial for 1997 and 1996. There are no material differences in the Company
recording its annual compensation expense under APB25 from the requirements
under FAS123. All of the restricted shares will become immediately vested upon
the completion of EUA's plan of merger with NEES.
The preferred stock provisions of the Retail Subsidiaries place certain
restrictions upon the payment of dividends on common stock by each company. At
December 31, 1998 and 1997, each company was in excess of the minimum
requirements which would make these restrictions effective.
In the event of involuntary liquidation, the holders of non-redeemable
preferred stock of the Retail Subsidiaries are entitled to $100 per share plus
accrued dividends. In the event of voluntary liquidation, or if redeemed
at the option of these companies, each share of the non-redeemable preferred
stock is entitled to accrued dividends plus the following:
Company Issue Amount
Blackstone: 4.25% issue $104.40
5.60% issue 103.82
Newport: 3.75% issue 103.50
(D) Redeemable Preferred Stock:
Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003. The redemption price is $100 per share plus accrued dividends. All
outstanding shares of the 6 5/8% issue are subject to mandatory redemption on
September 1, 2008, at a price of $100 per share plus accrued dividends. In the
event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred Stock
are entitled to $100 per share plus accrued dividends.
(E) Long-Term Debt:
The various mortgage bond issues of Blackstone, Eastern Edison, and Newport are
collateralized by substantially all of their utility plant.
In addition, Eastern Edison's bonds are collateralized by securities of
Montaup, which are wholly-owned by Eastern Edison. On December 30, 1998,
Montaup redeemed $55 million of debenture bonds and paid a $19 million special
dividend to Eastern Edison with proceeds received from the sale of its 50%
ownership share of the Canal 2 generating station. The principal amount of
Montaup securities wholly-owned by Eastern Edison at December 31, 1998 was
approximately $181 million.
Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable
Letter of Credit which expires on January 21, 2000. The letter of credit
permits an extension of one year upon mutual agreement of the bank and
Blackstone.
Newport's Variable Rate Electric Energy Facilities Revenue Refunding Bonds are
collateralized by an irrevocable Letter of Credit which expires on January 6,
2000, and permits an extension of one year upon mutual agreement of the bank
and Newport. EUA Service Corporation's (EUA Service) 10.2% Secured Notes due
2008 are collateralized by certain real estate and property of the company.
In July, Eastern Edison used short-term borrowings to redeem $20 million of
5 7/8% and $40 million of 5 3/4%, First Mortgage and Collateral Trust Bonds at
maturity. On December 30, 1998, Eastern repaid outstanding short-term
borrowings with proceeds received from the redemption of Montaup securities.
The EUA System's aggregate amount of current cash sinking fund requirements and
maturities of long-term debt, (excluding amounts that may be satisfied by
available property additions) for each of the five years following 1998 are:
$21.9 million in 19 99, $62.5 million in 2000, $14.3 million in 2001, $46
million in 2002, and $60 million in 2003.
(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short-term maturity of these instruments.
Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair
value of these assets are based on market rates of similar securities.
Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the
System redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1998 and 1997.
The estimated fair values of the System's financial instruments at December 31,
1998 and 1997, were as follows:
<TABLE>
Carrying Amount Fair Value
<CAPTION>
($ in thousands) 1998 1997 1998 1997
<S> <C> <C> <C> <C>
Cash and Temporary
Cash Investments $32,090 $7,252 $32,090 $7,252
Long-Term Notes Receivable
and Net Investment
in Sales-Type Leases 40,934 46,192 42,052 47,200
Redeemable Preferred Stock 30,000 30,000 32,625 31,613
Long-Term Debt 332,708 405,829 350,392 429,035
</TABLE>
(G) Lines Of Credit:
In July 1997, several EUA System companies entered into a three-year revolving
credit agreement allowing for borrowings in aggregate of up to $145 million
from all sources of short-term credit. As of December 31, 1998, various
financial institutions have committed up to $75 million under the revolving
credit facility. In addition to the $75 million available under the revolving
credit facility, EUA System companies maintain short-term lines of credit with
various banks totaling $90 million for an aggregate amount available of $165
million. At December 31, 1998, the EUA System had unused short-term lines of
credit of approximately $101.4 million. During 1998, the weighted average
interest rate for short-term borrowings was 5.8%.
(H) Jointly Owned Facilities:
At December 31, 1998, in addition to the stock ownership interests discussed in
Note A, Nature of Operations and Summary of Significant Accounting Policies -
Jointly Owned Companies, Montaup and Newport had direct ownership interests in
the following electric generating facilities:
<TABLE>
<CAPTION>
Accumulated Net
Utility Provision for Utility Construction
Percent Plant in Depreciation Plant in Work in
($ in thousands) Owned Service & Amortization Service Progress
<S> <C> <C> <C> <C> <C>
Montaup:
Wyman Unit 4 1.96% $4,041 $2,388 $1,653 $
Seabrook Unit I 2.90% 194,169 47,277 146,892 480
Millstone Unit 3 4.01% 178,598 65,705 112,893 347
Newport:
Wyman Unit 4 0.67% 1,312 805 507
</TABLE>
The foregoing amounts represent Montaup's and Newport's interest in each
facility, including nuclear fuel where appropriate, and are included on the
like-captioned lines on the Consolidated Balance Sheet. At December 31, 1998,
Montaup's total net investment in nuclear fuel of the Seabrook and Millstone
Units amounted to $2.5 million and $1.9 million, respectively.
Montaup's and Newport's shares of related operating and maintenance expenses
with respect to units reflected in the preceding table are included in the
corresponding operating expenses.
EUA has entered into agreements to sell its joint ownership shares in Wyman
Unit 4 and Seabrook Unit I. Closing of the Wyman sale is expected in the first
quarter of 1999 and the Seabrook sale is expected to close later in 1999. Both
agreements are subject to approval of various regulatory agencies.
(I) Financial Information By Business Segments:
Statement of Financial Accounting Standards No. 131, Disclosures about Segments
of an Enterprise and Related Information (SFAS 131), requires disclosure of
certain financial and descriptive information by operating segments. The Core
Electric Business includes results of the electric utility operations of
Blackstone, Eastern Edison, Newport and Montaup.
Energy Related Business includes results of our diversified energy-
related subsidiaries, EUA Cogenex, EUA Ocean State, EUA Energy Investment
Corporation (EUA Energy), EUA Energy services and EUA Telecommunications.
Corporate results include the operations of EUA Service and EUA Parent. EUA
does not have any intersegment revenues. Financial data for the business
segments are as follows:
<TABLE>
<CAPTION>
Pre-Tax Depreciation Cash Equity in Net Net
Operating Operating Income and Construction Subsidiary Interest Interest
($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings Charges Income
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year Ended
December 31, 1998
Core Electric $480,080 $84,586 $22,685 $38,804 $22,888 $1,390 $23,593 $528
Energy Related 58,721 (2,945) (1,387) 12,267 26,801 8,134 12,219 7,210
Corporate (2,045) (1,845) 8 1,512 1,387 63
Total $538,801 $79,596 $19,453 $51,079 $51,201 $9,524 $37,199 $7,801
Year Ended
December 31, 1997
Core Electric $506,696 $78,795 $20,303 $36,069 $21,870 $1,599 $24,668 $1,678
Energy Related 61,817 (3,785) 547 10,858 51,941 7,867 13,295 8,854
Corporate (1,980) 1,645 14 2,307 1,193 16
Total $568,513 $73,030 $22,495 $46,941 $76,118 $9,466 $39,156 $10,548
Year Ended
December 31, 1996
Core Electric $470,719 $80,042 $21,039 $35,178 $33,337 $1,587 $24,290 $ 394
Energy Related 56,349 (11,536) (3,888) 10,290 28,121 9,111 13,494 7,212
Corporate (1,723) 642 10 1,272 1,335 156
Total $ 527,068 $66,783 $17,793 $45,478 $62,730 $10,698 $39,119 $7,762
</TABLE>
<TABLE>
<CAPTION>
Years ended December 31, ($ in thousands) 1998 1997
<S> <C> <C>
Total Plant and Other Investments
Core Electric $648,281 $703,132
Energy Related 164,439 187,752
Corporate 18,973 21,392
Total Plant and Other Investments 831,693 912,276
Other Assets
Core Electric 370,360 257,888
Energy Related 67,780 73,109
Corporate 32,805 27,479
Total Other Assets 470,945 358,476
Total Assets $1,302,638 $1,270,752
</TABLE>
(J) Commitments And Contingencies:
Plan of Merger Agreement: On February 1, 1999, EUA and New England Electric
System (NEES) entered into an Agreement and Plan of Merger under which NEES
will acquire all outstanding shares of EUA for $31 per share in cash. Under
certain terms of the merger agreement, if the merger agreement is terminated by
EUA, EUA would pay NEES a termination fee of $20 million plus up to $5 million
for documented out-of-pocket expenses.
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs: The owners (or
lead participants) of the nuclear units in which Montaup has an interest have
made, or expect to make, various arrangements for the acquisition of uranium
concentrate, the conversion, enrichment, fabrication and utilization of nuclear
fuel and the disposition of that fuel after use. The owners (or lead
participants) of United States nuclear units have entered into contracts with
the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance
with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject
to various contingencies) that the federal government design, license,
construct and operate a permanent repository for high level radioactive wastes
and spent nuclear fuel and establish a prescribed fee for the disposal of such
wastes and nuclear fuel. The NWPA specifies that the DOE provide for the
disposal of such waste and spent nuclear fuel starting in 1998. Objections on
environmental and other grounds have been asserted against proposals for
storage as well as disposal of spent nuclear fuel. The DOE now estimates that
a permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. In early 1998, a number of
utilities filed suit in federal appeals court seeking, among other things, an
order requiring the DOE to immediately establish a program for the disposal of
spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9%
interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone 3 has sufficient on-site storage facilities which,
with rack additions, can accommodate its spent fuel for the projected life of
the unit. At the Seabrook Project, there is on-site storage capacity which,
with rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through rates.
Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating
facility which is in the process of decommissioning. Montaup's share of the
total estimated costs for the permanent shutdown, decommissioning, and recovery
of the investment in Connecticut Yankee is approximately $23.8 million. On
August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to
decommission the plant. The judge claimed that estimates of clean-up costs
were flawed and certain restoration costs were not supported. The judge also
said Connecticut Yankee could not pass on spent fuel storage costs to rate-
payers. The judge recommended that Connecticut Yankee withdraw its
decommissioning plan and submit a new plan which addresses the issues cited by
him. FERC will review the judge's recommendations and issue a decision on this
case in the coming months. If FERC concurs with the judge's recommendation,
this may result in a write down of certain of Connecticut Yankee plant
investments. Montaup cannot predict the ultimate outcome of FERC's review.
In August 1997, as the result of an economic evaluation, the Maine Yankee Board
of Directors voted to permanently close that nuclear plant. Montaup has a 4.0%
equity ownership in Maine Yankee. Montaup's share of the total estimated costs
for the permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee is approximately $31.0 million. In January 1998,
FERC accepted Maine Yankee's rate filing, subject to refund, for the recovery
of its costs during the decommissioning period. On January 19, 1999, Maine
Yankee and the active intervening parties filed an Offer of Settlement with
FERC which was supported by FERC trial staff. Upon commission approval, this
agreement will constitute full settlement of issues raised in this proceeding.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $22.4 million in
1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures
are based on studies performed for the lead owners of the units. Montaup also
pays into decommissioning reserves pursuant to contractual arrangements with
other nuclear generating facilities in which it has an equity ownership
interest or life of the unit entitlement. Such expenses are currently
recoverable through rates.
Pensions: EUA maintains a noncontributory defined benefit pension plan
covering most of the employees of the EUA System (Retirement Plan). Retirement
Plan benefits are based on years of service and average compensation over the
four years prior to retirement. It is the EUA System's policy to fund the
Retirement Plan on a current basis in amounts determined to meet the funding
standards established by the Employee Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including an amount
related to the 1997 voluntary retirement incentive offer, for 1998, 1997 and
1996 included the following components:
<TABLE>
<CAPTION>
($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
Service cost $2,929 $2,816 $3,126
Interest cost 10,390 10,116 9,765
Expected return on assets (15,033) (13,761) (12,817)
Net amortization:
Prior service cost 671 667 700
Net actuarial (gain) (395) (183)
Transition obligation (asset) (274) (274) (274)
Net periodic pension
(income) expense (1,712) (619) 500
Subsidiary Curtailment (131)
Total periodic pension
(income) expense $(1,712) $(750) $500
Assumptions used to determine pension costs:
Discount Rate 7.25% 7.50% 7.25%
Compensation Increase Rate 4.25% 4.25% 4.25%
Long-Term Return on Assets 9.50% 9.50% 9.50%
</TABLE>
The following tables set forth the actuarial present value of projected benefit
obligations, fair value of assets and funded status at December 31, 1998 and
1997:
<TABLE>
Reconciliation of Projected Benefit Obligation
<CAPTION>
($ in thousands) 1998 1997
<S> <C> <C>
Beginning of Year Benefit Obligation $144,915 $136,286
Service Cost 2,929 2,816
Interest Cost 10,390 10,116
Actuarial loss 9,256 4,519
Disbursements (8,032) (8,403)
Settlements or curtailments (419)
End of year benefit obligation $159,458 $144,915
Reconciliation of Fair Value of Assets
($ in thousands) 1998 1997
Beginning of Year Fair Value of Assets $182,795 $161,300
Actual return on plan assets 38,074 29,898
Disbursements (8,032) (8,403)
End of Year Fair Value of Assets $212,837 $182,795
Reconciliation of Funded Status
($ in thousands) 1998 1997
Projected benefit obligation (PBO) $(159,458) $(144,915)
Fair value of plan assets (FVA) 212,837 182,795
PBO less than FVA (funded status) 53,379 37,880
Unrecognized prior service cost 4,153 4,768
Unrecognized net transition obligation (asset) (662) (936)
Unrecognized net actuarial (gain) (54,845) (41,399)
Net amount recognized $2,025 $313
</TABLE>
The discount rate used to determine pension obligations, effective January 1,
1999 was changed from 7.25% to 6.75% and was used to calculate the plan's
funded status at December 31, 1998.
The voluntary retirement incentive also resulted in $1.3 million of non-
qualified pension benefits which were expensed in 1997. At December 31, 1998,
approximately $2.7 million was included in other liabilities for these unfunded
benefits.
EUA also maintains non-qualified supplemental retirement plans for certain
officers and trustees of the EUA System (Supplemental Plans). Benefits
provided under the Supplemental Plans are based primarily on compensation at
retirement date. EUA maintains life insurance on certain participants of the
Supplemental Plans, and policy cash values and death benefits may be available
to offset EUA's obligations under the Supplemental Plans. As of December 31,
1998, approximately $6.5 million was included in accrued expenses and other
liabilities for these plans. Expenses related to the Supplemental Plans were
$1.1 million in 1998, $1.9 million in 1997, and $1.5 million in 1996.
EUA also provides a defined contribution 401(k) savings plan for substantially
all employees. EUA's matching percentage of employees' voluntary contributions
to the plan, amounted to $1.5 million in 1998 and 1997, and $1.3 million in
1996.
Post-Retirement Benefits: Retired employees are entitled to participate in
health care and life insurance benefit plans. Health care benefits are subject
to deductibles and other limitations. Health care and life insurance benefits
are partially funded by EUA System companies for all qualified employees.
The total cost of post-retirement benefits other than pensions, including an
amount related to the 1997 voluntary retirement incentive offer, for 1998, 1997
and 1996 includes the following components:
<TABLE>
<CAPTION>
($ in thousands) 1998 1997 1996
<S> <C> <C> <C>
Service cost $967 $949 $1,123
Interest cost 4,526 4,434 4,449
Expected return on assets (1,849) (1,254) (847)
Net amortization:
Net actuarial (gain) (780) (842) (617)
Transition obligation 3,289 3,289 3,313
Net periodic postretirement
benefit cost 6,153 6,576 7,421
Subsidiary Curtailment (548)
Voluntary Retirement Incentive 172
Total periodic postretirement
Benefit cost $6,153 $6,200 $7,421
Assumptions used to determine post-retirement costs
Discount rate 7.25% 7.50% 7.25%
Health care cost trend rate
- near-term 6.00% 7.00% 9.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.25% 4.25%
Long-term return on assets
- union 8.50% 8.75% 8.50%
- non-union 7.50% 7.75% 7.50%
</TABLE>
The following tables forth the actuarial present value of accumulated
postretirement benefit obligation, fair value of assets and funded status
at December 31, 1998.
Reconciliation of Accumulated Post-retirement Benefit Obligation
($ in thousands) 1998 1997
Beginning of Year Benefit Obligation $ 64,826 $ 62,122
Service Cost 967 949
Interest Cost 4,526 4,434
Participant Contributions 151 211
Actuarial Loss 2,644 242
Disbursements (3,486) (2,791)
Settlements or Curtailments (341)
End of Year Benefit Obligation $ 69,628 $ 64,826
Reconciliation of Fair Value Assets
($ in thousands) 1998 1997
Beginning of Year Fair Value of Assets $ 23,729 $ 17,743
Actual return on plan assets 3,007 1,433
Company contributions 6,794 7,133
Participant contributions 151 211
Disbursements (3,486) (2,791)
End of Year Fair Value of Assets $ 30,195 $ 23,729
Reconciliation of Funded Status
($ in thousands) 1998 1997
Accumulated post-retirement benefit
obligation (APBO) $(69,628) $(64,826)
Fair value of plan assets (FVA) 30,195 23,729
APBO (in excess of) FVA (Funded Status) (39,433) (41,097)
Unrecognized net transition
obligation (asset) 46,046 49,335
Unrecognized net actuarial (gain) (13,967) (16,233)
Net amount recognized $(7,354) $(7,995)
Effect of 1% Change in Assumed Health Care Cost Trend Rate
One Percentage Point
($ in thousands) Increase Decrease
Effect on 1998 service and interest cost
components of net-periodic costs $814 $(649)
Effect on 1998 accumulated post-retirement
benefit obligation $8,578 $(6,996)
The discount rate used to determine post-retirement benefit obligations
effective January 1, 1999 was changed from 7.25% to 6.75% and was used to
calculate the funded status of post-retirement benefits at December 31, 1998.
Long-Term Purchased Power Contracts: The EUA System is committed under long-
term purchased power contracts, expiring on various dates through September
2021, to pay demand charges whether or not energy is received. Under terms in
effect at December 31, 1998, the aggregate annual minimum commitments for such
contracts are approximately $111 million in 1999, $109 million in 2000, $111
million in 2001, $108 million in 2002, $101 million in 2003 and will aggregate
approximately $927 million for the ensuing years. In addition, the EUA System
is required to pay additional amounts depending on the actual amount of energy
received under contracts in effect. The demand costs associated with these
contracts are reflected as Purchased Power-Demand on the Consolidated Statement
of Income. Such costs are currently recoverable through rates. Pending
regulatory approval, certain power contract transfers related to the
divestiture of EUA's generating assets will become effective in 1999. Upon
completion of the power contract transfers, the demand charges will be reduced
to $54 million in 1999, $43 million in 2000, $40 million in 2001, $42 million
in 2002, $26 million in 2003, and $162 million in the ensuing years.
Environmental Matters: There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities. The EUA System generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. Subsidi-
aries of EUA have been notified with respect to a number of sites where they
may be responsible for such costs, including sites where they may have joint
and several liability with other responsible parties. It is the policy of the
EUA System companies to notify liability insurers and to initiate claims. EUA
is unable to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carriers in these matters.
On December 13, 1994, the United States District Court for the District of
Massachusetts (District Court) issued a judgment against Blackstone, finding
Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the
full amount of response costs incurred by the Commonwealth in the cleanup of a
by-product of manufactured gas at a site at Mendon Road in Attleboro,
Massachusetts. The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment. The total liability is
approximately $5.9 million, including approximately $3.6 million in interest
which had accumulated since 1985. Due to the uncertainty of the ultimate
outcome of this proceeding and anticipated recoverability whether through
rates, insurance providers or other parties, Blackstone recorded an asset for
the amount funded under the escrow agreement (discussed below) consistent with
provisions of SFAS 5, specifically paragraphs 3, 10, and 13 and SFAS 71,
specifically paragraphs 3 and 9. This amount is included with Other Assets on
the Consolidated Balance Sheets at December 31, 1998 and 1997. Should the EPA
determine the substance to be non-toxic, the company may be able to retain the
entire escrowed amount and would relieve both the asset and liability from its
balance sheet at that time. However should the EPA determine that the
substance is hazardous, the company would amortize its asset, net of amounts
recovered through insurance proceeds or from other parties, over a five year
period in accordance with the company's established rate recovery mechanisms of
similar costs.
Blackstone filed a Notice of Appeal of the District Court Judgment and filed
its brief with the United States Court of Appeals for the First Circuit (First
Circuit) on February 24, 1995. On October 6, 1995, the First Circuit vacated
the District Court's judgment and ordered the District Court to refer the
matter to the EPA to determine whether the chemical substance, ferric
ferrocyanide (FFC), contained within the by-product is a hazardous substance.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
On January 28, 1994, Blackstone filed a complaint in the District Court,
seeking, among other relief, contribution and reimbursement from Stone &
Webster Inc., of New York City and several of its affiliated companies (Stone &
Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any
damages incurred by Blackstone regarding the Mendon Road site. On November 7,
1994, the Court denied motions to dismiss the complaint which were filed by
Stone & Webster and Valley. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance.
In addition, Blackstone has notified certain liability insurers and has filed
claims with respect to the Mendon Road site, as well as other sites. Blackstone
reached settlement with one carrier for reimbursement of legal costs related to
the Mendon Road case. In January 1996, Blackstone received the proceeds of the
settlement.
As of December 31, 1998, the EUA System had incurred costs of approximately
$7.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with the investigation and clean-up of these sites, substantially all of which
relate to Blackstone. These amounts have been financed primarily by internally
generated cash. Blackstone is currently amortizing all of its incurred costs
over a five-year period consistent with prior regulatory recovery periods and
is recovering certain of those costs in rates.
EUA estimates that additional costs of up to $2.5 million (excluding the $5.9
million Mendon Road judgment) may be incurred at these sites through 1999,
substantially all of which relates to sites at which Blackstone is a
potentially responsible party. Estimates beyond 1999 cannot be made since site
studies, which are the basis of these estimates, have not been completed. As a
result of the recoverability of cleanup costs in rates and the uncertainty
regarding both its estimated liability, as well as its potential contributions
from insurance carriers and other responsible parties, EUA does not believe
that the ultimate impact of the environmental costs will be material to the
financial position of the EUA System or to any individual subsidiary and thus
no loss provision is required at this time.
The Clean Air Act Amendments created new regulatory programs and generally
updated and strengthened air pollution control laws. These amendments expanded
the regulatory role of the EPA regarding emissions from electric generating
facilities and a host of other sources. EUA System generating facilities were
first affected in 1995, when EPA regulations took effect for facilities owned
by the EUA System. Montaup's coal-fired Somerset Unit 6 is utilizing lower
sulfur content coal to meet the 1995 air standards. EUA does not anticipate
the impact from the Amendments to be material to the financial position of the
EUA System.
In July 1997, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards. The effect that such standards will
have on the EUA System cannot be determined by management at this time.
Eastern Edison, Montaup, the Massachusetts Attorney General and Division of
Energy Resources entered into a settlement regarding electric utility industry
restructuring in Massachusetts. The settlement includes a plan for emissions
reductions related to Montaup's Somerset Station Units 5 and 6. The basis for
SO2 and NOx emission reductions in the proposed settlement is an allowance cap
calculation. Montaup may meet its allowance caps by any combination of control
technologies, fuel switching, operational changes, and/or the use of purchased
or surplus allowances. The settlement was approved by FERC on December 19,
1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight northeast states including
Massachusetts and Rhode Island, issued recommendations for NOx controls for
existing utility boilers required to meet the ozone non-attainment requirements
of the Clean Air Act. The NESCAUM recommendations are more restrictive than
the Clean Air Act requirements. The Massachusetts Department of Environmental
Management has amended its regulations to require that Reasonably Available
Control Technology (RACT) be implemented at all stationary sources potentially
emitting 50 tons or more per year of NOx. Similar regulations have been issued
in Rhode Island. Montaup has initiated compliance, through, among other
things, selective noncatalytic reduction processes.
See Note A regarding EUA's planned divestiture of generation assets.
A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. Some states have enacted regulations to limit the strength of
magnetic fields at the edge of transmission line rights-of-way. Rhode Island
has enacted a statute which authorizes and directs the Energy Facility Siting
Board to establish rules and regulations governing construction of high voltage
transmission lines of 69 kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
Guarantee of Financial Obligations: EUA has guaranteed or entered into equity
maintenance agreements in connection with certain obligations of its
subsidiaries. EUA has guaranteed the repayment of EUA Cogenex's $24.5 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $26.1 million,
9.59% unsecured long-term notes due 2011. In addition, EUA has entered into
equity maintenance agreements in connection with the issuance of EUA Service's
10.2% Secured Notes and EUA Cogenex's 9.6% Unsecured Notes. Under the December
1992 settlement agreement with EUA Power, EUA reaffirmed its guarantee of up to
$10 million of EUA Power's share of the decommissioning costs of Seabrook I and
any costs of cancellation of Seabrook I or Seabrook II. EUA guaranteed this
obligation in 1990 in order to secure the release to EUA Power of a $10 million
fund established by EUA Power at the time EUA Power acquired its Seabrook
interest. EUA has not provided a reserve for this guarantee because management
believes it unlikely that EUA will ever be required to honor the guarantee.
Montaup is a 3.27% equity participant in two companies which own and operate
transmission facilities interconnecting New England and the Hydro Quebec system
in Canada. Montaup has guaranteed approximately $4.1 million of the
outstanding debt of these two companies. In addition, Montaup and Newport have
minimum rental commitments which total approximately $11.2 million and $1.4
million, respectively, under a noncancelable transmission facilities support
agreement for years subsequent to 1998.
Other: Since early 1997, fourteen plaintiffs brought suits against numerous
defendants, including EUA, for injuries and illness allegedly caused by
exposure to asbestos over approximately a thirty-year period, at premises,
including some owned by EUA companies. The total damages claimed in all of
these complaints was $34 million in compensatory and punitive damages, plus
exemplary damages and interest and costs. Each complaint names between fifteen
and twenty-eight defendants, including EUA. These complaints have been
referred to the applicable insurance companies. Counsel has been retained by
the insurers and is actively defending all cases. Four cases have been
dismissed as against the EUA Companies. EUA cannot predict the ultimate
outcome of this matter at this time.
A pending class action, filed on March 2, 1998, in the Massachusetts Supreme
Judicial Court naming all Massachusetts electric distribution companies,
including Eastern Edison, and certain Massachusetts state agencies as
defendants, seeks to invalidate certain sections of the Electric Utility
Restructuring Act of 1997. The Act directs the Massachusetts Department of
Telecommunications and Energy to impose mandatory charges on all electricity
sold to customers, except those served by a municipal lighting plant, to fund
energy efficiency activities and to promote renewable energy projects. In
addition to declaratory judgment, plaintiffs seek remittance of monies paid to
each distribution company by customers along with any interest earned. The
outcome of this class action is unknown at this time however, Eastern Edison is
vigorously defending the lawsuit.
Cogenex Settlement - EUA Cogenex recorded an after-tax charge of $2.1 million
to earnings related to an arbitration panel's decision in a matter involving
the 1995 sale of a portfolio of cogeneration units by EUA Cogenex to
Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed that
financial and other warranties in the purchase and sale agreement had been
breached. EUA Cogenex entered counterclaims seeking recovery of costs of
certain services performed for Ridgewood. The arbitration panel found for the
buyer on some of the warranty claims, and awarded damages of approximately $2.6
million plus interest. EUA Cogenex was awarded approximately $400,000 plus
interest on its counterclaim. EUA Cogenex paid the arbitration panel's net
award less interest and recorded this charge to earnings during the fourth
quarter of 1998. EUA Cogenex continues to contest the panel's findings with
respect to the interest and legal fees.
Termination of Power Marketing Joint Venture - In the third quarter of 1997,
EUA announced the termination of a power marketing joint venture with an
affiliate of Duke Energy Corporation, the establishment of contingency reserves
related to certain of its energy-related business activities and other
expenses. Collectively, these actions resulted in a net after-tax gain of $1.5
million in third quarter 1997 earnings. The gross pre-tax gain related to the
joint venture termination was $6.6 million. The gain was offset by contingency
reserves for EUA's non-core business operations, industry restructuring
matters, the Millstone 3 outage, interest and insurance aggregating $4.4
million. Also, EUA recorded expenses of $200,000 related to industry
restructuring efforts.
Report of Independent Accountants
To the Trustees and Shareholders of Eastern Utilities Associates
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of equity capital and preferred stock and indebtedness
present fairly, in all material respects, the financial position of Eastern
Utilities Associates (the Company) and its subsidiaries at December 31, 1998
and 1997, and their consolidated statements of income, retained earnings and
cash flows present fairly their results of operations and cash flows for each
of the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which 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, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
March 5, 1999
Report of Management
The management of Eastern Utilities Associates is responsible for the
consolidated financial statements and related information included in this
annual report. The financial statements are prepared in accordance with
generally accepted accounting principles and include amounts based on the best
estimates and judgments of management, giving appropriate consideration to
materiality. Financial information included elsewhere in this annual report is
consistent with the financial statements.
The EUA System maintains an accounting system and related internal controls
which are designed to provide reasonable assurances as to the reliability of
financial records and the protection of assets. The System's staff of internal
auditors conducts reviews to maintain the effectiveness of internal control
procedures.
PricewaterhouseCoopers LLP an independent accounting firm, is engaged by EUA to
audit and express an opinion on our financial statements. Their audit includes
a review of internal controls to the extent required by generally accepted
auditing standards for such audit.
The Audit Committee of the Board of Trustees, which consists solely
of outside Trustees, meets with management, internal auditors
and PricewaterhouseCoopers LLP to discuss auditing, internal controls and
financial reporting matters. The internal auditors and PricewaterhouseCoopers
LLP have free access to the Audit Committee without management present.
Quarterly Financial and Common Share Information (unaudited)
($ in thousands except per Share and Share Price Amounts)
<TABLE>
<CAPTION>
Basic and
Diluted Earnings Dividends Common Share
Consolidated per Average Paid per Market Price
Operating Operating Net Net Common Common
Revenues Income Income Earnings Share Share High Low
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FOR THE QUARTERS
ENDED 1998:
December 31 $133,416 $15,153 $9,085 $8,509 $0.42 $0.415 28 1/4 24 5/8
September 30 136,033 15,461 9,788 9,212 0.45 0.415 26 15/16 24 5/16
June 30 130,046 12,531 6,449 5,872 0.29 0.415 27 3/8 24 7/16
March 31 139,306 18,492 11,693 11,117 0.54 0.415 27 11/16 23 11/16
FOR THE QUARTERS
ENDED 1997:
December 31 $145,878 $15,378 $11,158 $10,582 $0.52 $0.415 26 5/8 20 1/8
September 30 142,026 15,896 11,542 10,966 0.54 0.415 19 15/16 18 7/16
June 30 138,856 11,327 6,510 5,933 0.29 0.415 18 1/2 16 3/8
March 31 141,753 16,206 11,055 10,479 0.51 0.415 19 5/8 17 1/4
</TABLE>
