FORM 10-K/A
(AMENDMENT NO. 1)
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission Registrant; State of Incorporation; I.R.S Employer
File Number Address; and Telephone Number Identification No.
1-5324 NORTHEAST UTILITIES 04-2147929
(a Massachusetts voluntary association)
174 BRUSH HILL AVENUE
WEST SPRINGFIELD, MASSACHUSETTS 01090-2010
Telephone: (413) 785-5871
0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
(a Connecticut corporation)
107 SELDEN STREET
BERLIN, CONNECTICUT 06037-1616
Telephone: (860) 665-5000
1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
(a New Hampshire corporation)
1000 ELM STREET
MANCHESTER, NEW HAMPSHIRE 03105-0330
Telephone: (603) 669-4000
0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
(a Massachusetts corporation)
174 BRUSH HILL AVENUE
WEST SPRINGFIELD, MASSACHUSETTS 01090-2010
Telephone: (413) 785-5871
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
NORTHEAST UTILITIES Common Shares, $5.00 New York Stock Exchange, Inc.
par value
THE CONNECTICUT LIGHT 9.3% Cumulative New York Stock Exchange, Inc.
AND POWER COMPANY Monthly Income
Preferred Securities
Series A (1)
(1) Issued by CL&P Capital, L.P., a wholly owned subsidiary of The Connecticut
Light and Power Company ("CL&P"), and guaranteed by CL&P.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
THE CONNECTICUT LIGHT Preferred Stock, par value $50.00 per share,
AND POWER COMPANY issuable in series, of which the following
series are outstanding:
$1.90 Series of 1947 4.96% Series of 1958
$2.00 Series of 1947 4.50% Series of 1963
$2.04 Series of 1949 5.28% Series of 1967
$2.20 Series of 1949 6.56% Series of 1968
3.90% Series of 1949 $3.24 Series G of 1968
$2.06 Series E of 1954 7.23% Series of 1992
$2.09 Series F of 1955 5.30% Series of 1993
4.50% Series of 1956
PUBLIC SERVICE Preferred Stock, par value $25.00 per share,
COMPANY OF issuable in series, of which the following series
NEW HAMPSHIRE are outstanding:
10.60% Series A of 1991
WESTERN MASSACHUSETTS Preferred Stock, par value $100.00 per share,
ELECTRIC COMPANY issuable in series, of which the following series
is outstanding:
7.72% Series B of 1971
Class A Preferred Stock, par value $25.00 per share,
issuable in series, of which the following series
are outstanding:
7.60% Series of 1987
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 the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of NORTHEAST UTILITIES' Common Share, $5.00 Par
Value, held by nonaffiliates, was $2,181,626,490 based on a closing sales price
of $15.94 per share for the 136,886,368 common shares outstanding on May 29,
1998. NORTHEAST UTILITIES holds all of the 12,222,930 shares, 1,000 shares and
1,072,471 shares of the outstanding common stock of THE CONNECTICUT LIGHT AND
POWER COMPANY, PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND WESTERN MASSACHUSETTS
ELECTRIC COMPANY, respectively.
Documents Incorporated by Reference:
Part of Form 10-K
into Which Document
Description is Incorporated
Portions of Annual Reports to Shareholders
of the following companies for the year
ended December 31, 1997:
Northeast Utilities Part II
The Connecticut Light and Power Company Part II
Public Service Company of New Hampshire Part II
Western Massachusetts Electric Company Part II
Explanatory Note: Securities and Exchange Commission
Inquiry and Amendment of the Form 10-Ks of NU, CL&P, PSNH and WMECO
In a letter dated March 25, 1998, the SEC inquired into the NU system's
accounting for nuclear compliance costs. These costs are the unavoidable
incremental costs associated with the current nuclear outages required to be
incurred prior to restart of the units in accordance with correspondence
received from the NRC early in 1996. The SEC's view is that these unavoidable
costs associated with nuclear outages and procedures to be implemented at
nuclear power plants in response to regulatory requirements required prior to
restart of the units should be expensed as incurred. During 1996 and 1997, NU,
CL&P, PSNH and WMECO reserved for these unavoidable incremental costs that they
expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and
WMECO to reflect these costs as they are incurred. While NU and its independent
auditors, Arthur Andersen LLP, believed the accounting was required by, and was
in accordance with, generally accepted accounting principles, the company has
agreed to adjust its accounting for nuclear compliance costs and amend its 1996
and 1997 Form 10-K filings. This amendment on Form 10-K/A reflects the change
in accounting.
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms
that are found throughout this report:
NU.............................. Northeast Utilities
CL&P............................ The Connecticut Light and Power Company
Charter Oak or COE.............. Charter Oak Energy, Inc.
WMECO........................... Western Massachusetts Electric Company
HWP............................. Holyoke Water Power Company
NUSCO or the Service Company.... Northeast Utilities Service Company
NNECO........................... Northeast Nuclear Energy Company
NAEC............................ North Atlantic Energy Corporation
NAESCO or North Atlantic........ North Atlantic Energy Service Corporation
PSNH............................ Public Service Company of New Hampshire
RRR............................. The Rocky River Realty Company
Select Enery.................... Select Energy, Inc., formerly NUSCO
Energy Partners, Inc.
Mode 1.......................... Mode 1 Communications, Inc.
HEC............................. HEC Inc.
Quinnehtuk...................... The Quinnehtuk Company
the System...................... The Northeast Utilities System
CYAPC........................... Connecticut Yankee Atomic Power Company
MYAPC........................... Maine Yankee Atomic Power Company
VYNPC........................... Vermont Yankee Nuclear Power Corporation
YAEC............................ Yankee Atomic Electric Company
the Yankee Companies............ CYAPC, MYAPC, VYNPC, and YAEC
GENERATING UNITS
Millstone 1..................... Millstone Unit No. 1, a 660-MW nuclear
generating unit completed in 1970
Millstone 2..................... Millstone Unit No. 2, an 870-MW nuclear
electric generating unit completed in 1975
Millstone 3..................... Millstone Unit No. 3, a 1,154-MW nuclear
electric generating unit completed in 1986
Seabrook or Seabrook 1.......... Seabrook Unit No. 1, a 1,148-MW nuclear
electric generating unit completed in 1986.
Seabrook 1 went into service in 1990.
REGULATORS
DOE............................. U.S. Department of Energy
DTE............................. Massachusetts Department of Telecommunications
and Energy, formerly the Massachusetts
Department of Public Utilities (DPU)
DPUC............................ Connecticut Department of Public Utility
Control
MDEP............................ Massachusetts Department of Environmental
CDEP............................ Connecticut Department of Environmental
Protection
EPA............................. U.S. Environmental Protection Agency
FERC............................ Federal Energy Regulatory Commission
NHDES........................... New Hampshire Department of Environmental
Services
NHPUC........................... New Hampshire Public Utilities Commission
NRC............................. Nuclear Regulatory Commission
SEC............................. Securities and Exchange Commission
OTHER
1935 Act........................ Public Utility Holding Company Act of 1935
CAAA............................ Clean Air Act Amendments of 1990
DSM............................. Demand-Side Management
Energy Act...................... Energy Policy Act of 1992
EWG............................. Exempt wholesale generator
EAC............................. Energy Adjustment Clause (CL&P)
FAC............................. Fuel Adjustment Clause (WMECO)
FPPAC........................... Fuel and purchased power adjustment clause
(PSNH)
FUCO............................ Foreign utility company
kWh............................. Kilowatt-hour
MW.............................. Megawatt
NBFT............................ Niantic Bay Fuel Trust, lessor of nuclear fuel
used by CL&P and WMECO
ISO............................. Independent System Operator, successor to the
New England Power Pool (NEPOOL)
NEPOOL.......................... New England Power Pool
NUGs............................ Nonutility generators
NUG&T........................... Northeast Utilities Generation and
Transmission Agreement
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
1997 Form 10-K/A Annual Report
Table of Contents
PART II
Page
Item 6. Selected Financial Data...................................... 1
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................... 1
Item 8. Financial Statements and Supplementary Data.................. 1
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.......................................... 3
Item 6. Selected Financial Data
NU. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 65 of NU's Amended 1997 Annual
Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Selected
Financial Data" contained on page 54 of CL&P's Amended 1997 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected
Financial Data" contained on pages 50 and 51 of PSNH's Amended 1997 Annual
Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected
Financial Data" contained on page 51 of WMECO's Amended 1997 Annual Report,
which information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
NU. Reference is made to information under the heading "Management's
Discussion and Analysis" contained on pages 48 through 63 in NU's Amended 1997
Annual Report to Shareholders, which information is incorporated herein by
reference.
CL&P. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 42 through 53 in CL&P's Amended 1997 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made toinformation under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 42 through 49 in PSNH's Amended 1997 Annual Report, which
information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 40 through 50 in WMECO's Amended 1997 Annual Report, which
information is incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data
NU. Reference is made to information under the headings "Company Report,"
"Report of Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Cash Flows," "Consolidated Statements of Income
Taxes," "Consolidated Balance Sheets," "Consolidated Statements of
Capitalization," "Consolidated Statements of Common Shareholders' Equity,"
"Notes to Consolidated Financial Statements," and "Consolidated Statements of
Quarterly Financial Data" contained on pages 2 through 47 and page 64 in NU's
Amended 1997 Amended Report to Shareholders, which information is incorporated
herein by reference.
CL&P. Reference is made to information under the headings "Consolidated
Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements
of Cash Flows," "Consolidated Statements of Common Stockholder's Equity," "Notes
to Consolidated Financial Statements," "Report of Independent Public
Accountants," and "Statements of Quarterly Financial Data" contained on pages 2
through 41 and page 54 in CL&P's Amended 1997 Annual Report, which information
is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Balance
Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of
Common Equity," "Notes to Financial Statements," "Report of Independent
Public Accountants," and "Statements of Quarterly Financial Data" contained on
pages 2 through 41 and page 52 in PSNH's Amended 1997 Annual Report, which
information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Consolidated
Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements
of Cash Flows," "Consolidated Statements of Common Stockholder's Equity,"
"Notes to Consolidated Financial Statements," "Report of Independent Public
Accountants," and "Statements of Quarterly Financial Data" contained on pages 2
through 39 and page 51 in WMECO's Amended 1997 Annual Report, which information
is incorporated herein by reference.
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K.
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial
statements of NU, CL&P, PSNH and WMECO are hereby incorporated by
reference and made a part of this report (see "Item 8. Financial
Statements and Supplementary Data").
Report of Independent Public Accountants
on Schedules S-1
Consent of Independent Public Accountants S-3
2. Schedules:
Amended Financial Statement Schedules for NU (Parent),
NU and Subsidiaries, CL&P and Subsidiaries,
PSNH and WMECO and Subsidiary are listed in
the Index to Financial Statements Schedules S-4
3. Exhibits Index E-1
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
NORTHEAST UTILITIES
(Registrant)
Date: June 10, 1998 By: /s/ Michael G. Morris
Michael G. Morris
Chairman of the Board
and President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
June 10, 1998 Chairman of the Board, /s/ Michael G. Morris
President and Michael G. Morris
Chief Executive Officer
and a Trustee
June 10, 1998 Executive Vice /s/ John H. Forsgren
President and Chief John H. Forsgren
Financial Officer
June 10, 1998 Vice President and /s/ John J. Roman
Controller John J. Roman
NORTHEAST UTILITIES
SIGNATURES (CONT'D)
Date Title Signature
June 10, 1998 Trustee /s/ Cotton M. Cleveland
Cotton M. Cleveland
June 10, 1998 Trustee /s/ William F. Conway
William F. Conway
June 10, 1998 Trustee /s/ E. Gail de Planque
E. Gail de Planque
June 10, 1998 Trustee /s/ Elizabeth T. Kennan
Elizabeth T. Kennan
June 10, 1998 Trustee /s/ William J. Pape II
William J. Pape II
June 10, 1998 Trustee /s/ Robert E. Patricelli
Robert E. Patricelli
June 10, 1998 Trustee /s/ John F. Swope
John F. Swope
June 10, 1998 Trustee /s/ John F. Turner
John F. Turner
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
(Registrant)
Date: June 10, 1998 By: /s/ Michael G. Morris
Michael G. Morris
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
7
Date Title Signature
June 10, 1998 Chairman and /s/ Michael G. Morris
a Director Michael G. Morris
June 10, 1998 President and /s/ Hugh C. MacKenzie
a Director Hugh C. MacKenzie
June 10, 1998 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
June 10, 1998 Vice President /s/ John J. Roman
and Controller John J. Roman
June 10, 1998 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(Registrant)
Date: June 10, 1998 By: /s/ Michael G. Morris
Michael G. Morris
Chairman and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
June 10, 1998 Chairman and Chief /s/ Michael G. Morris
Executive Officer Michael G. Morris
and a Director
June 10, 1998 President and /s/ William T. Frain, Jr.
Chief Operating William T. Frain, Jr.
Officer and
a Director
June 10, 1998 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
June 10, 1998 Vice President /s/ John J. Roman
and Controller John J. Roman
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES (CONT'D)
Date Title Signature
June 10, 1998 Director /s/ John C. Collins
John C. Collins
June 10, 1998 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
June 10, 1998 Director /s/ Gerald Letendre
Gerald Letendre
June 10, 1998 Director /s/ Hugh C. MacKenzie
Hugh C. MacKenzie
June 10, 1998 Director /s/ Jane E. Newman
Jane E. Newman
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
(Registrant)
Date: June 10, 1998 By: /s/ Michael G. Morris
Michael G. Morris
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
June 10, 1998 Chairman and /s/ Michael G. Morris
a Director Michael G. Morris
June 10, 1998 President and /s/ Hugh C. MacKenzie
a Director Hugh C. MacKenzie
June 10, 1998 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
June 10, 1998 Vice President /s/ John J. Roman
and Controller John J. Roman
June 10, 1998 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
We have audited in accordance with generally accepted auditing standards, the
restated financial statements of Northeast Utilities, The Connecticut Light and
Power Company and Western Massachusetts Electric Company incorporated by
reference in this Form 10-K/A, and have issued our report thereon dated February
20, 1998 (except with respect to the matter discussed in Note 1, as to which
the date is June 10, 1998). Our audit was made for the purpose of forming an
opinion on the basic financial statements taken as a whole. The schedules, as
restated - see Note 1, listed in the accompanying Index to Financial Statements
Schedules are the responsibility of the companies' management and are presented
for purposes of complying with the Securities and Exchange Commission's rules
and are not part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in the audit of the basic financial
statements and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in
Note 1, as to which the date is June 10, 1998)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
We have audited in accordance with generally accepted auditing standards, the
restated financial statements of Public Service Company of New Hampshire,
incorporated by reference in this Form 10-K/A and have issued our report thereon
dated February 20, 1998 (except with respect to the matter discussed in Note 1
as to which the date is June 10, 1998). Our report includes an explanatory
paragraph regarding the existence of conditions which raise substantial doubt
about the company's ability to continue as a going concern. Our audit was made
for the purpose of forming an opinion on the basic financial statements taken as
a whole. The schedules, as restated - see Note 1, listed in the accompanying
Index to Financial Statements Schedules are the responsibility of the company's
management and are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial statements.
These schedules have been subjected to the auditing procedures applied in the
audit of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in
Note 1, as to which the date is June 10, 1998)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our reports included (or incorporated by reference) in this Form 10-K/A, into
the Company's previously filed Registration Statements No. 33-55279 of The
Connecticut Light and Power Company, No. 33-56537 of CL&P Capital, LP and No.
33-34622, No. 33-44814, No. 33-63023, No. 33-40156, No. 333-52413, and No.
333-52415 of Northeast Utilities.
/s/ ARTHUR ANDERSEN LLP
Hartford, Connecticut
June 10, 1998
INDEX TO FINANCIAL STATMENTS SCHEDULES
Schedule
I. Amended Financial Information of Registrant:
Northeast Utilities (Parent) Balance
Sheets 1997 and 1996 S-5
Northeast Utilities (Parent) Statements
of Income 1997, 1996, and 1995 S-6
Northeast Utilities (Parent) Statements
of Cash Flows 1997, 1996, and 1995 S-7
II. Amended Valuation and Qualifying Accounts
and Reserves 1997, 1996, and 1995:
Northeast Utilities and Subsidiaries S-8 - S-10
The Connecticut Light and Power Company
and Subsidiaries S-11 - S-13
Public Service Company of New Hampshire S-14 - S-16
Western Massachusetts Electric Company
and Subsidiary S-17 - S-19
All other schedules of the companies' for which provision is made in
the applicable regulations of the Securities and Exchange Commission are not
required under the related instructions or are not applicable, and therefore
have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 1997 AND 1996
(Thousands of Dollars)
<TABLE>
<CAPTION>
1997 1996
(Restated) (Restated)
---------- ----------
<S> <C> <C>
ASSETS
- ------
Other Property and Investments:
Investments in subsidiary companies, at
equity............................................... $2,314,746 $2,543,352
Investments in transmission companies, at equity...... 19,635 21,186
Other, at cost........................................ 402 413
----------- -----------
2,334,783 2,564,951
----------- -----------
Current Assets:
Cash.................................................. 10 10
Notes receivable from affiliated companies............ 34,200 5,475
Notes and accounts receivable......................... 711 813
Receivables from affiliated companies................. 961 7,106
Prepayments........................................... 265 224
----------- -----------
36,147 13,628
----------- -----------
Deferred Charges:
Accumulated deferred income taxes..................... 5,692 5,293
Unamortized debt expense.............................. 232 524
Other................................................. 47 46
----------- -----------
5,971 5,863
----------- -----------
Total Assets..................................... $2,376,901 $2,584,442
=========== ===========
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common Shareholders' Equity:
Common shares, $5 par value--Authorized
225,000,000 shares; 136,842,170 shares issued and
130,182,736 shares outstanding in 1997 and
136,051,938 shares issued and
128,444,373 outstanding in 1996..................... $ 684,211 $ 680,260
Capital surplus, paid in.............................. 932,493 940,446
Deferred contribution plan--employee stock ownership
plan (ESOP)......................................... (154,141) (176,091)
Retained earnings..................................... 707,522 869,618
----------- -----------
Total common shareholders' equity................... 2,170,085 2,314,233
Long-term debt........................................ 177,000 194,000
----------- -----------
Total capitalization................................ 2,347,085 2,508,233
----------- -----------
Current Liabilities:
Notes payable to banks................................ - 38,750
Long-term debt and preferred stock--current portion... 17,000 16,000
Accounts payable...................................... 1,857 15,504
Accounts payable to affiliated companies.............. 216 600
Accrued taxes......................................... 7,860 2,158
Accrued interest...................................... 2,343 2,602
Dividend reinvestment plan............................ 90 -
Other................................................. - 2
----------- -----------
29,366 75,616
----------- -----------
Other Deferred Credits.................................. 450 593
----------- -----------
Total Capitalization and Liabilities $2,376,901 $2,584,442
=========== ===========
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
(Thousands of Dollars Except Share Information)
<TABLE>
<CAPTION>
1997 1996
(Restated) (Restated) 1995
------------- ------------- -------------
<S> <C> <C> <C>
Operating Revenues.................. $ - $ - $ -
------------- ------------- -------------
Operating Expenses:
Other............................. 8,657 8,920 14,267
Federal income taxes.............. (10,697) (10,390) (8,585)
------------- ------------- -------------
Total operating expenses......... (2,040) (1,470) 5,682
------------- ------------- -------------
Operating Income (Loss)............. 2,040 1,470 (5,682)
------------- ------------- -------------
Other Income:
Equity in earnings of
subsidiaries..................... (118,195) 55,370 310,025
Equity in earnings of
transmission companies........... 2,968 3,306 3,561
Other, net........................ 2,184 368 329
------------- ------------- -------------
Other income, net............... (113,043) 59,044 313,915
------------- ------------- -------------
(Loss) Income before
interest charges.............. (111,003) 60,514 308,233
------------- ------------- -------------
Interest Charges.................... 18,959 21,585 25,799
------------- ------------- -------------
Net (Loss)/Income................... $ (129,962) $ 38,929 $ 282,434
============= ============= =============
(Loss)/Earnings Per Common Share.... $ (1.01) $ 0.30 $ 2.24
============= ============= =============
Common Shares Outstanding
(average).......................... 129,567,708 127,960,382 126,083,645
============= ============= =============
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997, 1996, 1995
(Thousands of Dollars)
<TABLE> 1997 1996
<CAPTION> (Restated) (Restated) 1995
------------ -------------- --------------
<S> <C> <C> <C>
Operating Activities:
Net (loss) income...................................... $ (129,962) $ 38,929 $ 282,434
Adjustments to reconcile to net cash
from operating activities:
Equity in earnings of subsidiary companies........... 118,195 (55,370) (310,025)
Cash dividends received from subsidiary companies.... 132,994 247,101 272,350
Deferred income taxes................................ 1,558 3,868 772
Other sources of cash................................ 11,738 17,961 6,916
Other uses of cash................................... (2,101) (3,065) (528)
Changes in working capital:
Receivables........................................ 6,247 (7,312) 1,991
Accounts payable................................... (14,031) (3,183) 15,381
Other working capital (excludes cash).............. 5,490 (13,724) 7,396
------------ -------------- --------------
Net cash flows from operating activities................. 130,128 225,205 276,687
------------ -------------- --------------
Financing Activities:
Issuance of common shares.............................. 6,502 10,622 47,218
Net decrease in short-term debt........................ (38,750) (18,750) (46,500)
Reacquisitions and retirements of long-term debt....... (16,000) (14,000) (12,000)
Cash dividends on common shares........................ (32,134) (176,276) (221,701)
------------ -------------- --------------
Net cash flows used for financing activities............. (80,382) (198,404) (232,983)
------------ -------------- --------------
Investment Activities:
NU System Money Pool................................... (28,725) 4,200 (7,700)
Investment in subsidiaries............................. (22,583) (33,217) (38,963)
Other investment activities, net....................... 1,562 2,208 2,935
------------ -------------- --------------
Net cash flows used for investments...................... (49,746) (26,809) (43,728)
------------ -------------- --------------
Net decrease in cash for the period...................... 0 (8) (24)
Cash - beginning of period............................... 10 18 42
------------ -------------- --------------
Cash - end of period..................................... $ 10 $ 10 $ 18
============ ============== ==============
Supplemental Cash Flow Information
Cash paid during the year for:
Interest, net of amounts capitalized................... $ 18,960 $ 21,770 $ 26,430
============ ============== ==============
Income taxes (refund).................................. $ (16,000) $ (7,700) $ (8,418)
============ ============== ==============
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 17,062 $ 14,854 $ - $ 29,864 (a) $ 2,052
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 36,260 $ 9,542 $ - $ 11,365 (b) $ 34,437
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 14,379 $ 21,761 $ - $ 19,078 (a) $ 17,062
========= ========= ========= ========== ==========
Asset valuation reserves $ 10,266 $ $ - $ 10,266 $ 0
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 38,409 $ 8,397 $ - $ 10,546 (b) $ 36,260
========= ========= ========= ========== ==========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1995
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 16,826 $ 18,010 $ - $ 20,458 (a)$ 14,378
========= ========= ========= ========= =========
Asset valuation reserves $ 8,684 $ 1,582 $ - $ - $ 10,266
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 34,721 $ 11,475 $ - $ 7,787 (b)$ 38,409
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 13,241 $ 10,509 $ - $ 23,450 (a) $ 300
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 18,879 $ 4,458 $ - $ 8,375 (b) $ 14,962
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 10,567 $ 15,704 $ - $ 13,030 (a) $ 13,241
========= ========= ========= ========== ==========
Asset valuation reserves $ 10,266 $ - $ - $ 10,266 $ 0
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 19,874 $ 5,709 $ - $ 6,704 (b) $ 18,879
========= ========= ========= ========== ==========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1995
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 12,778 $ 12,722 $ - $ 14,933 (a)$ 10,567
========= ========= ========= ========= =========
Asset valuation reserves $ 8,684 $ 1,582 $ - $ - $ 10,266
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 19,529 $ 5,633 $ - $ 5,288 (b)$ 19,874
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,700 $ 3,259 $ - $ 3,257 (a) $ 1,702
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,265 $ 1,647 $ - $ 1,124 (b) $ 7,788
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,582 $ 2,906 $ - $ 2,788 (a) $ 1,700
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 8,142 1,040 $ - $ 1,917 (b) $ 7,265
========= ========= ========= ========== ==========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1995
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,015 $ 2,454 $ - $ 2,887 (a)$ 1,582
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,113 $ 3,668 $ - $ 639 (b)$ 8,142
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,121 $ 1,086 $ - $ 3,157 (a) $ 50
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,575 $ 1,093 $ - $ 1,165 (b) $ 5,503
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated)
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,230 $ 3,097 $ - $ 3,206 (a) $ 2,121
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,144 $ 1,222 $ - $ 791 (b) $ 5,575
========= ========= ========= ========== ==========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1995
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged
Balance at Charged to to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,032 $ 2,836 $ - $ 2,638 (a)$ 2,230
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 4,674 $ 1,340 $ - $ 870 (b)$ 5,144
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
</TABLE>
EXHIBIT INDEX
Each document described below is incorporated by reference to the files of
the Securities and Exchange Commission, unless the reference to the document is
marked as follows:
& - Filed with the 1997 Annual Report on Form 10-K/A for NU and herein
incorporated by reference from the 1997 NU Form 10-K/A, File No. 1-5324
into the 1997 Annual Report on Form 10-K/A for CL&P, PSNH and WMECO.
* - Filed with the 1997 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into
the 1997 Annual Report on Form 10-K for CL&P, PSNH, WMECO and NAEC.
# - Filed with the 1997 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into
the 1997 Annual Report on Form 10-K for CL&P.
@ - Filed with the 1997 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into
the 1997 Annual Report on Form 10-K for PSNH.
** - Filed with the 1997 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into
the 1997 Annual Report on Form 10-K for WMECO.
## - Filed with the 1997 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1997 Form 10-K, File No. 1-5324 into the
1997 Annual Report on Form 10-K for NAEC.
Exhibit
Number Description
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through May 24,
1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No.
1-5324)
3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P, restated to March
22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No.
1-5324)
3.2.2 Certificate of Amendment to Certificate of Incorporation
of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996
NU Form 10-K, File No. 1-5324)
3.2.3 By-laws of CL&P, as amended to January 1, 1997. (Exhibit
3.2.3, 1996 NU Form 10-K, File No. 1-5324)
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991.
(Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993.
(Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
3.4 Western Massachusetts Electric Company
3.4.1 Articles of Organization of WMECO, restated to February
23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No.
1-5324)
** 3.4.2 By-laws of WMECO, as amended to February 11, 1998.
3.5 North Atlantic Energy Corporation
3.5.1 Articles of Incorporation of NAEC dated September 20,
1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No.
1-5324)
3.5.2 Articles of Amendment dated October 16, 1991 and June 2,
1992 to Articles of Incorporation of NAEC. (Exhibit
3.5.2, 1993 NU Form 10-K, File No. 1-5324)
3.5.3 By-laws of NAEC, as amended to November 8, 1993.
(Exhibit 3.5.3, 1993 NU Form 10-K, File No. 1-5324)
4 Instruments defining the rights of security holders, including
indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991 between Northeast
Utilities and IBJ Schroder Bank & Trust Company, with
respect to the issuance of Debt Securities. (Exhibit
4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.2 First Supplemental Indenture dated as of December 1,
1991 between Northeast Utilities and IBJ Schroder Bank
& Trust Company, with respect to the issuance of Series
A Notes. (Exhibit 4.1.2, 1991 NU Form 10-K, File No.
1-5324)
4.1.3 Second Supplemental Indenture dated as of March 1, 1992
between Northeast Utilities and IBJ Schroder Bank &
Trust Company with respect to the issuance of 8.38%
Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K,
File No. 1-5324)
4.1.4 Credit Agreements among CL&P, NU, WMECO, NUSCO (as
Agent) and 3 Commercial Banks dated December 3, 1992
(Three-Year Facility). (Exhibit C.2.38, 1992 NU Form
U5S, File No. 30-246)
4.1.5 Credit Agreements among CL&P, WMECO, NU, Holyoke Water
Power Company, RRR, NNECO and NUSCO (as Agent) and 1
commercial bank dated December 3, 1992 (Three-Year
Facility). (Exhibit C.2.39, 1992 NU Form U5S, File No.
30-246)
4.1.6 Credit Agreement among NU, CL&P and WMECO and several
commercial banks, dated as of November 21, 1996.
(Exhibit No. B.1, File No. 70-8875)
4.1.7 First Amendment and Waiver dated as of May 30, 1997 to
Credit Agreement dated as of November 21, 1996 among NU,
CL&P, WMECO, and the Co-Agents and Banks named therein.
(Exhibit B.4(a) (Execution Copy), File No. 70-8875)
4.1.8 Credit Agreement dated as of February 10, 1998 among NU,
the Lenders named therein, and Toronto Dominion (Texas),
Inc., as Administrative Agent, TD Securities (USA) Inc.,
as Arranger. (Exhibit B.9 (Execution Copy), File No.
70-8875)
4.2 The Connecticut Light and Power Company
4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, Trustee, dated as of May 1, 1921.
(Composite including all twenty-four amendments to May
1, 1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No.
1-5324)
Supplemental Indentures to the Composite May 1, 1921
Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, dated as of:
4.2.2 December 1, 1969. (Exhibit 4.20, File No. 2-60806)
4.2.3 June 30, 1982. (Exhibit 4.33, File No. 2-79235)
4.2.4 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K,
File No. 1-5324)
4.2.5 July 1, 1992. (Exhibit 4.31, File No. 33-59430)
4.2.6 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.7 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.8 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K,
File No. 1-5324)
4.2.9 February 1, 1994. (Exhibit 4.2.15, 1993 NU Form 10-K,
File No. 1-5324)
4.2.10 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K,
File No. 1-5324)
4.2.11 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File
No. 1-5324)
4.2.12 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K,
File No. 1-5324)
4.2.13 June 1, 1996. (Exhibit 4.2.16, 1996 NU Form 10-K, File
No. 1-5324)
4.2.14 January 1, 1997. (Exhibit 4.2.17, 1996 NU Form 10-K,
File No. 1-5324
4.2.15 May 1, 1997. (Exhibit 4.19, File No. 333-30911)
4.2.16 June 1, 1997. (Exhibit 4.20, File No. 333-30911)
# 4.2.17 June 1, 1997.
4.2.18 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1986 Series) dated as of
December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S,
File No. 30-246)
4.2.18.1 Letter of Credit and Reimbursement Agreement
(Pollution Control Bonds, 1986 Series) dated
as of August 1, 1994. (Exhibit 1 (Execution
Copy), File No. 70-7320)
4.2.19 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1988 Series) dated as of
October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S,
File No. 30-246)
4.2.19.1 Letter of Credit (Pollution Control Bonds,
1988 Series) dated October 27, 1988. (Exhibit
4.2.17.1, 1995 NU Form 10-K, File No. 1-5324)
4.2.19.2 Reimbursement and Security Agreement
(Pollution Control Bonds, 1988 Series) dated
as of October 1, 1988. (Exhibit 4.2.17.2, 1995
NU Form 10-K, File No. 1-5324)
4.2.20 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds) dated as of December 1, 1989.
(Exhibit C.1.39, 1989 NU Form U5S, File No. 30-246)
4.2.21 Loan and Trust Agreement among Business Finance
Authority of the State of New Hampshire, CL&P and the
Trustee (Pollution Control Bonds, 1992 Series A) dated
as of December 1, 1992.(Exhibit C.2.33, 1992 NU Form
U5S, File No. 30-246)
4.2.21.1 Letter of Credit and Reimbursement Agreement
(Pollution Control Bonds, 1992 Series A) dated
as of December 1, 1992. (Exhibit 4.2.19.1, 1995
NU Form 10-K, File No. 1-5324)
4.2.22 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.22.1 Letter of Credit and Reimbursement Agreement
(Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993.
(Exhibit 4.2.23, 1993 NU Form 10-K, File No.
1-5324)
4.2.23 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series B, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.23.1 Letter of Credit and Reimbursement Agreement
(Pollution Control Bonds - Series B, Tax Exempt
Refunding) dated as of September 1, 1993.
(Exhibit 4.2.24, 1993 NU Form 10-K, File No.
1-5324)
4.2.24 Amended and Restated Loan Agreement between Connecticut
Development Authority and CL&P (Pollution Control
Revenue Bond - 1996A Series) dated as of May 1, 1996
and Amended and Restated as of January 1, 1997.
(Exhibit 4.2.24, 1996 NU Form 10-K, File No. 1-5324)
4.2.24.1 Amended and Restated Indenture of Trust
between Connecticut Development Authority and
the Trustee (CL&P Pollution Control Revenue
Bond-1996A Series), dated as of May 1, 1996 and
Amended and Restated as of January 1, 1997.
(Exhibit 4.2.24.1, 1996 NU Form 10-K, File No.
1-5324)
4.2.24.2 Standby Bond Purchase Agreement among CL&P,
Societe Generale, New York Branch and the
Trustee, dated January 23, 1997. (Exhibit
4.2.24.2, 1996 NU Form 10-K, File No. 1-5324)
# 4.2.24.3 Amendment No. 1, dated January 21, 1998, to
the Standby Bond Purchase Agreement, dated
January 23, 1997.
4.2.24.4 AMBAC Municipal Bond Insurance Policy issued
by the Connecticut Development Authority (CL&P
Pollution Control Revenue Bond-1996A Series),
effective January 23, 1997. (Exhibit 4.2.24.3,
1996 NU Form 10-K, File No. 1-5324)
4.2.25 Amended and Restated Limited Partnership Agreement (CL&P
Capital, L.P.) among CL&P, NUSCO, and the persons who
became limited partners of CL&P Capital, L.P. in
accordance with the provisions thereof dated as of
January 23, 1995 (MIPS). (Exhibit A.1 (Execution Copy),
File No. 70-8451)
4.2.26 Indenture between CL&P and Bankers Trust Company,
Trustee (Series A Subordinated Debentures), dated as of
January 1, 1995 (MIPS). (Exhibit B.1 (Execution Copy),
File No. 70-8451)
4.2.27 Payment and Guaranty Agreement of CL&P dated as of
January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy),
File No. 70-8451)
4.3 Public Service Company of New Hampshire
4.3.1 First Mortgage Indenture dated as of August 15, 1978
between PSNH and First Fidelity Bank, National
Association, New Jersey, Trustee, (Composite including
all amendments to May 16, 1991). (Exhibit 4.4.1, 1992
NU Form 10-K, File No. 1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1,
1991 between PSNH and First Fidelity Bank,
National Association. (Exhibit 4.1, PSNH
Current Report on Form 8-K dated February 10,
1992, File No. 1-6392).
4.3.2 Revolving Credit Agreement, dated as of May 1, 1991
(includes a collateral mortgage). (Exhibit 4.12, PSNH
Current Report on Form 8-K, File No. 1-6392)
4.3.2.1 Amended and Restated Revolving Credit
Agreement, dated as of April 1, 1996
(includes amendment to collateral
mortgage). (Exhibit 4.3.2, 1996 NU Form 10-K,
File No. 1-5324)
4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.6 Series D (Taxable New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.5, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.6.1 First Supplement to Series D (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1992. (Exhibit
4.4.5.1, 1992 NU Form 10-K, File No. 1-5324)
4.3.6.2 Second Series D (May 1, 1991 Taxable New Issue
and December 1, 1992 Tax Exempt Refunding
Issue) PCRB Letter of Credit and Reimbursement
Agreement dated as of May 1, 1995 (Exhibit B.4,
Execution Copy, File No. 70-8036)
4.3.7 Series E (Taxable New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.6, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.7.1 First Supplement to Series E (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1993. (Exhibit 4.3.8.1,
1993 NU Form 10-K, File No. 1-5324)
4.3.7.2 Second Series E (May 1, 1991 Taxable New Issue
and December 1, 1993 Tax Exempt Refunding
Issue) PCRB Letter of Credit and Reimbursement
Agreement dated as of May 1, 1995. (Exhibit
B.5, (Execution Copy), File No. 70-8036)
4.4 Western Massachusetts Electric Company
4.4.1 First Mortgage Indenture and Deed of Trust between WMECO
and Old Colony Trust Company, Trustee, dated as of
August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File
No. 1-5324)
Supplemental Indentures thereto dated as of:
4.4.2 October 1, 1954.(Exhibit 4.2, File No. 33-51185)
** 4.4.3 March 1, 1967.
4.4.4 July 1, 1973. (Exhibit 2.10. File No. 2-68808)
4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772)
4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K,
File No. 1-5324)
4.4.7 March 1, 1994. (Exhibit 4.4.11, 1993 NU Form 10-K, File
No. 1-5324)
4.4.8 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File
No. 1-5324)
4.4.9 May 1, 1997. (Exhibit 4.11, File No. 33-51185)
** 4.4.10 July 1, 1997.
4.4.11 Loan Agreement between Connecticut Development
Authority and WMECO, (Pollution Control Bonds -
Series A, Tax Exempt Refunding) dated as of
September 1, 1993. (Exhibit 4.4.13, 1993 NU Form
10-K, File No. 1-5324)
4.4.11.1 Letter of Credit and Reimbursement Agreement
(Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993.
(Exhibit 4.4.14, 1993 NU Form 10-K, File No.
1-5324)
4.5 North Atlantic Energy Corporation
4.5.1 First Mortgage Indenture and Deed of Trust between NAEC
and United States Trust Company of New York, Trustee,
dated as of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form
10-K, File No. 1-5324)
4.5.2 Term Credit Agreement dated as of November 9, 1995.
(Exhibit 4.5.2, 1995 NU Form 10-K, File No. 1-5324)
10 Material Contracts
10.1 Stockholder Agreement dated as of July 1, 1964 among the
stockholders of Connecticut Yankee Atomic Power Company (CYAPC).
(Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)
10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC
and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994
NU Form 10-K, File No. 1-5324)
10.2.1 Form of Additional Power Contract dated as of April 30,
1984, between CYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of
April 1, 1987, between CYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No.
1-5324)
10.3 Capital Funds Agreement dated as of September 1, 1964 between
CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU
Form 10-K, File No. 1-5324)
10.4 Stockholder Agreement dated December 10, 1958 between Yankee
Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO.
(Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power
Contract between YAEC and each of CL&P, PSNH and WMECO,
including a composite restatement of original Power Contract
dated June 30, 1959 and Amendment No. 1 dated April 1, 1975 and
Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU
Form 10-K, File No. 1-5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6,
1988, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June
26, 1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July
1,1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated
February 1, 1992, between YAEC and each of CL&P, PSNH
and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No.
1-5324)
10.6 Stockholder Agreement dated as of May 20, 1968 among
stockholders of MYAPC.
10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC
and each of CL&P, HELCO, PSNH and WMECO.
10.7.1 Form of Amendment No. 1 to Power Contract dated as of
March 1, 1983 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No.
1-5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of
January 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No.
1-5324)
10.7.3 Form of Amendment No. 3 to Power Contract dated as of
October 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No.
1-5324)
10.7.4 Form of Additional Power Contract dated as of February
1, 1984 between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.8 Capital Funds Agreement dated as of May 20, 1968 between MYAPC
and CL&P, PSNH, HELCO and WMECO.
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of
August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
(Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
10.9 Sponsor Agreement dated as of August 1, 1968 among the
sponsors of Vermont Yankee Nuclear Power Corporation
(VYNPC).
10.10 Form of Power Contract dated as of February 1, 1968 between
VYNPC and each of CL&P, HELCO, PSNH and WMECO.
10.10.1 Form of Amendment to Power Contract dated as of June 1,
1972 between VYNPC and each of CL&P, HELCO, PSNH and
WMECO. (Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as of
April 15, 1983 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File
No. 1-5324)
10.10.3 Form of Third Amendment to Power Contract dated as of
April 24, 1985 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K,
File No. 1-5324)
10.10.4 Form of Fourth Amendment to Power Contract dated as of
June 1, 1985 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.10.4, 1996 NU Form 10-K, File
No. 1-5324)
10.10.5 Form of Fifth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File No.
1-5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No.
1-5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as
of June 15, 1989 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File
No. 1-5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as of
December 1, 1989 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File
No. 1-5324)
10.10.9 Form of Additional Power Contract dated as of February
1, 1984 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324)
#@**10.11 Capital Funds Agreement dated as of February 1, 1968 between
VYNPC and CL&P, HELCO, PSNH and WMECO.
#@**10.11.1 Form of First Amendment to Capital Funds Agreement
dated as of March 12, 1968 between VYNPC and CL&P,
HELCO, PSNH and WMECO.
10.11.2 Form of Second Amendment to Capital Funds Agreement
dated as of September 1, 1993 between VYNPC and CL&P,
HELCO, PSNH and WMECO. (Exhibit 10.11.2, 1993 NU Form
10-K, File No. 1-5324)
10.12 Amended and Restated Millstone Plant Agreement dated as of
December 1, 1984 by and among CL&P, WMECO and Northeast Nuclear
Energy Company (NNECO). (Exhibit 10.12, 1994 NU Form 10-K,
File No. 1-5324)
10.13 Sharing Agreement dated as of September 1, 1973 with respect to
1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit
6.43, File No. 2-50142)
10.13.1 Amendment dated August 1, 1974 to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No.
2-52392)
10.13.2 Amendment dated December 15, 1975 to Sharing Agreement
- 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File
No. 2-60806)
10.13.3 Amendment dated April 1, 1986 to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990
NU Form 10-K, File No. 1-5324)
10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint
owners with respect to operation of Seabrook. (Exhibit 10.53,
1990 NU Form 10-K, File No. 1-5324)
10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated
as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File
No. 1-5324)
10.16 Rate Agreement by and between NUSCO, on behalf of NU, and the
Governor of the State of New Hampshire and the New Hampshire
Attorney General dated as of November 22, 1989. (Exhibit 10.44,
1989 NU Form 10-K, File No. 1-5324)
10.16.1 First Amendment to Rate Agreement dated as of December
5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K, File No.
1-5324)
10.16.2 Second Amendment to Rate Agreement dated as of December
12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K, File No.
1-5324)
10.16.3 Third Amendment to Rate Agreement dated as of December
3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K, File No.
1-5324)
10.16.4 Fourth Amendment to Rate Agreement dated as of
September 21, 1994. (Exhibit 10.16.4, 1995 NU Form
10-K, File No. 1-5324)
10.16.5 Fifth Amendment to Rate Agreement dated as of September
9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K, File No.
1-5324)
10.17 Form of Seabrook Power Contract between PSNH and NAEC, as
amended and restated. (Exhibit 10.45, NU 1992 Form 10-K, File
No. 1-5324)
10.18 Agreement (composite) for joint ownership, construction and
operation of New Hampshire nuclear unit, as amended through the
November 1, 1990 twenty-third amendment. (Exhibit No. 10.17,
1994 NU Form 10-K, File No. 1-5324)
10.18.1 Memorandum of Understanding dated November 7, 1988
between PSNH and Massachusetts Municipal Wholesale
Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K,
File No. 1-6392)
10.18.2 Agreement of Settlement among Joint Owners dated as of
January 13, 1989. (Exhibit 10.13.21, 1988 NU Form
10-K, File No. 1-5324)
10.18.2.1 Supplement to Settlement Agreement, dated
as of February 7, 1989, between PSNH and
Central Maine Power Company. (Exhibit
10.18.1, PSNH 1989 Form 10-K, File No.
1-6392)
10.19 Amended and Restated Agreement for Seabrook Project Disbursing
Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No.
33-35312)
10.19.1 Form of First Amendment to Exhibit 10.19. (Exhibit
10.4.8, File No. 33-35312)
10.19.2 Form (Composite) of Second Amendment to Exhibit 10.19.
(Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324)
10.20 Agreement dated November 1, 1974 for Joint Ownership,
Construction and Operation of William F. Wyman Unit No. 4 among
PSNH, Central Maine Power Company and other utilities. (Exhibit
5.16 , File No. 2-52900)
10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975.
(Exhibit 5.48, File No. 2-55458)
10.20.2 Amendment to Exhibit 10.20 dated as of August 16, 1976.
(Exhibit 5.19, File No. 2-58251)
10.20.3 Amendment to Exhibit 10.20 dated as of December 31,
1978. (Exhibit 5.10.3, File No. 2-64294)
10.21 Form of Service Contract dated as of July 1, 1966 between each
of NU, CL&P and WMECO and the Service Company. (Exhibit 10.20,
1993 NU Form 10-K, File No. 1-5324)
10.21.1 Service Contract dated as of June 5, 1992 between PSNH
and the Service Company. (Exhibit 10.12.4, 1992 NU
Form 10-K, File No. 1-5324)
10.21.2 Service Contract dated as of June 5, 1992 between NAEC
and the Service Company. (Exhibit 10.12.5, 1992 NU
Form 10-K, File No. 1-5324)
10.21.3 Form of Service Agreement dated as of June 29, 1992
between PSNH and North Atlantic Energy Service
Corporation, and the First Amendment thereto.
(Exhibits B.7 and B.7.1, File No. 70-7787)
10.21.4 Form of Annual Renewal of Service Contract. (Exhibit
10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.22 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and
WMECO dated as of June 1, 1970 with respect to pooling of
generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.22.1 Amendment to Memorandum of Understanding between CL&P,
HELCO, HP&E, HWP and WMECO dated as of February 2,
1982 with respect to pooling of generation and
transmission. (Exhibit 10.21.1, 1993 NU Form 10-K,
File No. 1-5324)
10.22.2 Amendment to Memorandum of Understanding between CL&P,
HELCO, HP&E, HWP and WMECO dated as of January 1, 1984
with generation and transmission. (Exhibit 10.21.2,
1994 NU Form 10-K, File No. 1-5324)
10.23 New England Power Pool Agreement effective as of November 1,
1971, as amended to December 1, 1996. (Exhibit 10.15, 1988 NU
Form 10-K, File No. 1-5324.)
10.23.1 Twenty-sixth Amendment to Exhibit 10.23 dated as of
March 15, 1989. (Exhibit 10.15.1, 1990 NU Form 10-K,
File No. 1-5324)
10.23.2 Twenty-seventh Amendment to Exhibit 10.23 dated as of
October 1, 1990. (Exhibit 10.15.2, 1991 NU Form 10-K,
File No. 1-5324)
10.23.3 Twenty-eighth Amendment to Exhibit 10.23 dated as of
September 15, 1992. (Exhibit 10.18.3, 1992 NU Form
10-K, File No. 1-5324)
10.23.4 Twenty-ninth Amendment to Exhibit 10.23 dated as of
May 1, 1993. (Exhibit 10.22.4, 1993 NU Form 10-K,
File No. 1-5324)
10.23.5 Thirty-second Amendment (Amendments 30 and 31 were
withdrawn) to Exhibit 10.23 dated as of September 1,
1995. (Exhibit 10.23.5, 1995 NU Form 10-K, File No.
1-5324)
10.23.6 Thirty-third Amendment to Exhibit 10.23 dated as of
December 31, 1996 and Form of Interim Independent
System Operator (ISO) Agreement. (Exhibit 10.23.6,
1996 NU Form 10-K, File No. 1-5324)
10.24 Agreements among New England Utilities with respect to the
Hydro-Quebec interconnection projects. (See Exhibits 10(u)
and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively,
Form 10-K of New England Electric System, File No. 1-3446.)
10.25 Trust Agreement dated February 11, 1992, between State Street
Bank and Trust Company of Connecticut, as Trustor, and Bankers
Trust Company, as Trustee, and CL&P and WMECO, with respect to
NBFT. (Exhibit 10.23, 1991 NU Form 10-K, File No. 1-5324)
10.25.1 Nuclear Fuel Lease Agreement dated as of February 11,
1992, between Bankers Trust Company, Trustee, as
Lessor, and CL&P and WMECO, as Lessees. (Exhibit
10.23.1, 1991 NU Form 10-K, File No. 1-5324)
10.26 Simulator Financing Lease Agreement, dated as of February 1,
1985, by and between ComPlan and NNECO. (Exhibit 10.25, 1994
NU Form 10-K, File No. 1-5324)
10.27 Simulator Financing Lease Agreement, dated as of May 2, 1985,
by and between The Prudential Insurance Company of America and
NNECO. (Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324)
10.28 Lease dated as of April 14, 1992 between The Rocky River Realty
Company (RRR) and Northeast Utilities Service Company (NUSCO)
with respect to the Berlin, Connecticut headquarters (office
lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.28.1 Lease dated as of April 14, 1992 between RRR and NUSCO
with respect to the Berlin, Connecticut headquarters
(project lease). (Exhibit 10.29.1, 1992 NU Form 10-K,
File No. 1-5324)
10.29 Millstone Technical Building Note Agreement dated as of
December 21, 1993 between, by and between The Prudential
Insurance Company of America and NNECO. (Exhibit 10.28,
1993 NU Form 10-K, File No. 1-5324)
10.30 Lease and Agreement, dated as of December 15, 1988, by and
between WMECO and Bank of New England, N.A., with BNE Realty
Leasing Corporation of North Carolina. (Exhibit 10.63, 1988
NU Form 10-K, File No. 1-5324.)
10.31 Note Agreement dated April 14, 1992, by and between The Rocky
River Realty Company (RRR) and Purchasers named therein
(Connecticut General Life Insurance Company, Life Insurance
Company of North America, INA Life Insurance Company of New
York, Life Insurance Company of Georgia), with respect to RRR's
sale of $15 million of guaranteed senior secured notes due 2007
and $28 million of guaranteed senior secured notes due 2017.
(Exhibit 10.52, 1992 NU Form 10-K, File No. 1-5324)
* 10.31.1 Amendment to Note Agreement, dated September 26, 1997.
10.31.2 Note Guaranty dated April 14, 1992 by Northeast
Utilities pursuant to Note Agreement dated April 14,
1992 between RRR and Note Purchasers, for the benefit
of The Connecticut National Bank as Trustee, the
Purchasers and the owners of the notes. (Exhibit
10.52.1, 1992 NU Form 10-K, File No. 1-5324)
* 10.31.2.1 Extension of Note Guaranty, dated September
26, 1997.
10.31.3 Assignment of Leases, Rents and Profits, Security
Agreement and Negative Pledge, dated as of April 14,
1992 among RRR, NUSCO and The Connecticut National
Bank as Trustee, securing notes sold by RRR pursuant
to April 14, 1992 Note Agreement. (Exhibit 10.52.2,
1992 NU Form 10-K, File No. 1-5324)
* 10.31.3.1 Modification of and Confirmation of
Assignment of Leases, Rents and Profits,
Security Agreement and Negative Pledge,
dated as of September 26, 1997.
* 10.31.4 Purchase and Sale Agreement, dated July 28, 1997 by
and between RRR and the Sellers and Purchasers named
therein.
* 10.31.5 Purchase and Sale Agreement, dated September 26, 1997
by and between RRR and the Purchaser named therein.
10.32 Master Trust Agreement dated as of September 2, 1986 between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 1 decommissioning costs. (Exhibit
No. 10.32, 1996 NU Form 10-K, File No. 1-5324)
10.32.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K,
File No. 1-5324)
10.33 Master Trust Agreement dated as of September 2, 1986 between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 2 decommissioning costs. (Exhibit
No. 10.33, 1996 NU Form 10-K, File No. 1-5324)
10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File
No. 1-5324)
10.34 Master Trust Agreement dated as of April 23, 1986 between CL&P
and WMECO and Colonial Bank as Trustee, with respect to reserve
funds for Millstone 3 decommissioning costs. (Exhibit No. 10.34,
1996 NU Form 10-K, File No. 1-5324)
10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K, File
No. 1-5324)
10.35 NU Executive Incentive Plan, effective as of January 1, 1991.
(Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
10.36 Supplemental Executive Retirement Plan for Officers of NU System
Companies, Amended and Restated effective as of January 1, 1992.
(Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30,
1992, File No. 1-5324)
10.36.1 Amendment 1 to Exhibit 10.36, effective as of August 1,
1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No.
1-5324)
10.36.2 Amendment 2 to Exhibit 10.36, effective as of
January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K,
File No. 1-5324)
10.36.3 Amendment 3 to Exhibit 10.36, effective as of January
1, 1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No.
1-5324)
10.37 Special Severance Program for Officers of NU System Companies,
as adopted on June 9, 1997. (Exhibit No. 10.33, File No.
333-30911)
10.38 Loan Agreement dated as of December 2, 1991, by and between NU
and Mellon Bank, N.A., as Trustee, with respect to NU's loan of
$175 million to an ESOP Trust. (Exhibit 10.46, NU 1991 Form
10-K, File No. 1-5324)
10.38.1 First Amendment to Exhibit 10.37 dated February 7,
1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No.
1-5324)
10.38.2 Loan Agreement dated as of March 19, 1992 by and
between NU and Mellon Bank, N.A., as Trustee, with
respect to NU's loan of $75 million to the ESOP Trust.
(Exhibit 10.49.1, 1992 NU Form 10-K, File No. 1-5324)
10.38.3 Second Amendment to Exhibit 10.37 dated April 9, 1992.
(Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
* 10.39 Employment Agreement with Michael G. Morris.
10.40 Transition and Retirement Agreement with Bernard M. Fox.
(Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324)
10.41 Employment Agreement with Bruce M. Kenyon. (Exhibit 10.40,
1996 NU Form 10-K, File No. 1-5324)
10.42 Employment Agreement with John H. Forsgren. (Exhibit 10.41,
1996 NU Form 10-K, File No. 1-5324)
10.43 Employment Agreement with Hugh C. MacKenzie. (Exhibit 10.42,
1996 NU Form 10-K, File No. 1-5324)
* 10.44 Employment Agreement with Robert P. Wax.
10.45 Northeast Utilities Deferred Compensation Plan for Trustees,
Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU
Form 10-K, File No. 1-5324)
10.46 Deferred Compensation Plan for Officers of Northeast Utilities
System Companies adopted September 23, 1986. (Exhibit 10.40,
1995 NU Form 10-K, File No. 1-5324)
10.47 Northeast Utilities Deferred Compensation Plan for Executives,
adopted January 13, 1998. (Exhibit A.5, File No. 70-09185)
10.48 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC
and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form
10K, File No. 1-5324)
# 10.49 Receivables Purchase and Sale Agreement (CL&P and CL&P
Receivables Corporation), dated as of September 30, 1997.
# 10.49.1 Purchase and Contribution Agreement (CL&P and CL&P
Receivables Corporation), dated as of September 30,
1997.
** 10.50 Receivables Purchase Agreement (WMECO and WMECO Receivables
Corporation), dated as of May 22, 1997.
** 10.50.1 Purchase and Sale Agreement (WMECO and WMECO
Receivables Corporation), dated as of May 22, 1997.
10.51 Master Lease Agreement between General Electric Capital
Corporation and CL&P, dated as of June 21, 1996. (Exhibit
10.50, 1996 NU Form 10-K, File No. 1-5324)
# 10.51.1 Amendment No. 1 to Master Lease Agreement, dated as of
August 29, 1997.
13 Annual Report to Security Holders (Each of the Annual Reports is
filed only with the Form 10-K/A of that respective registrant.)
& 13.1 Amended Annual Report to Shareholders of NU.
& 13.2 Amended Annual Report of CL&P.
& 13.3 Amended Annual Report of WMECO.
& 13.4 Amended Annual Report of PSNH.
*21 Subsidiaries of the Registrant.
27 Amended Financial Data Schedules (Each Financial Data Schedule is
filed only with the Form 10-K/A of that respective registrant.)
& 27.1 Amended Financial Data Schedule of NU.
& 27.2 Amended Financial Data Schedule of CL&P.
& 27.3 Amended Financial Data Schedule of WMECO.
& 27.4 Amended Financial Data Schedule of PSNH.
EXHIBIT 13.1
EXHIBIT 13.1
NORTHEAST UTILITIES AND SUBSIDIARIES
AMENDED 1997 ANNUAL REPORT TO SHAREHOLDERS
Northeast Utilities and Subsidiaries
Amended 1997 Annual Report
Index
Contents Page
Company Report....................................................... 2
Report of Independent Public Accountants............................. 3
Consolidated Balance Sheets (Restated)............................... 4-5
Consolidated Statements of Income (Restated)......................... 6
Consolidated Statements of Cash Flows (Restated)..................... 7
Consolidated Statements of Shareholders' Equity (Restated)........... 8
Consolidated Statements of Capitalization (Restated)................. 9
Notes to Consolidated Statements of Capitalization................... 10
Consolidated Statements of Income Taxes (Restated)................... 12
Notes to Consolidated Financial Statements (Restated)................ 13
Management's Discussion and Analysis of Financial
Condition and Results of Operations (Restated)....................... 48
Statement of Quarterly Financial Data (Restated)..................... 64
Consolidated Generation Statistics................................... 64
Selected Consolidated Financial Data (Restated)...................... 65
Consolidated Sales Statistics........................................ 66
Company Report
The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages
the maintenance of high standards of conduct in all of its business activities.
The company maintains a system of internal controls over financial reporting
which is designed to provide reasonable assurance to the company's management
and Board of Trustees regarding the preparation of reliable, published financial
statements. The system is supported by an organization of trained management
personnel, policies and procedures, and a comprehensive program of internal
audits. Through established programs, the company regularly communicates to its
management employees their internal control responsibilities and policies
prohibiting conflict of interest.
The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. This committee meets periodically with management, the internal
auditors and the independent auditors to review the activities of each and to
discuss audit matters, financial reporting and the adequacy of internal
controls.
Because of inherent limitations in any system of internal controls, errors or
irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation of
all financial statements, are reliable.
Report of Independent Public Accountants
To the Board of Trustees and Shareholders
of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization, as restated - see Note 1, of Northeast Utilities
(a Massachusetts trust) and subsidiaries as of December 31, 1997 and 1996, and
the related consolidated statements of income, common shareholders' equity,
cash flows and income taxes, as restated - see Note 1, for each of the three
years in the period ended December 31, 1997. These financial statements are the
responsibility of the company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
As explained in Note 1 to the consolidated financial statements, the company has
given retroactive effect to the change in accounting for nuclear compliance
costs.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in Note 1,
as to which the date is June 10, 1998)
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996
(Restated) (Restated)
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Assets
- ------
Utility Plant, at cost:
Electric................................................... $ 9,869,561 $ 9,685,155
Other...................................................... 186,130 192,303
------------ ------------
10,055,691 9,877,458
Less: Accumulated provision for depreciation............ 4,330,599 3,979,864
------------ ------------
5,725,092 5,897,594
Unamortized PSNH acquisition costs......................... 402,285 491,709
Construction work in progress.............................. 141,077 146,438
Nuclear fuel, net.......................................... 194,704 196,424
------------ ------------
Total net utility plant................................ 6,463,158 6,732,165
------------ ------------
Other Property and Investments:
Nuclear decommissioning trusts, at market.................. 502,749 403,544
Investments in regional nuclear generating companies,
at equity................................................ 86,955 85,340
Investments in transmission companies, at equity........... 19,635 21,186
Investments in Charter Oak Energy, Inc..................... - 57,188
Other, at cost............................................. 95,362 43,372
------------ ------------
704,701 610,630
------------ ------------
Current Assets:
Cash and cash equivalents.................................. 143,403 194,197
Investments in securitizable assets........................ 230,905 -
Receivables,less accumulated provision for uncollectible
accounts of $2,052,000 in 1997 and $17,062,000 in 1996... 214,914 477,021
Accrued utility revenues................................... 36,885 127,162
Fuel, materials, and supplies, at average cost............. 212,721 211,414
Recoverable energy costs, net--current portion............. 59,959 1,804
Investments in Charter Oak Energy, Inc. held for sale...... 33,391 -
Prepayments and other...................................... 38,495 55,318
------------ ------------
970,673 1,066,916
------------ ------------
Deferred Charges:
Regulatory assets.......................................... 2,173,278 2,221,839
Unamortized debt expense................................... 38,758 38,146
Other ..................................................... 63,844 72,052
------------ ------------
2,275,880 2,332,037
------------ ------------
Total Assets................................................. $10,414,412 $10,741,748
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
<TABLE>
<Caption
- ------------------------------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------------------------------
1997 1996
(Thousands of Dollars) (Restated) (Restated)
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization and Liabilities:
- -------------------------------
Capitalization: (See Consolidated Statements of Capitalization)
Common shareholders' equity (See Note (a) - Consolidated
Statements of Common Shareholders' Equity):
Common shares, $5 par value--authorized 225,000,000
shares;136,842,170 shares issued and 130,182,736
shares outstanding in 1997 and 136,051,938 shares
issued and 128,444,373 shares outstanding in 1996........ $ 684,211 $ 680,260
Capital surplus, paid in................................... 932,493 940,446
Deferred contribution plan--employee stock ownership
plan (ESOP).............................................. (154,141) (176,091)
Retained earnings (Note 1)................................. 707,522 869,618
------------ ------------
Total common shareholders' equity........................ 2,170,085 2,314,233
Preferred stock not subject to mandatory redemption.......... 136,200 136,200
Preferred stock subject to mandatory redemption.............. 245,750 276,000
Long-term debt............................................... 3,645,659 3,613,681
------------ ------------
Total capitalization..................................... 6,197,694 6,340,114
------------ ------------
Minority Interest in Consolidated Subsidiaries................. 100,000 99,972
------------ ------------
Obligations Under Capital Leases............................... 30,427 186,860
------------ ------------
Current Liabilities:
Notes payable to banks....................................... 50,000 38,750
Long-term debt and preferred stock--current portion.......... 274,810 319,503
Obligations under capital leases--current portion............ 177,304 19,305
Accounts payable............................................. 402,870 507,139
Accrued taxes................................................ 46,016 7,050
Accrued interest............................................. 30,786 51,386
Accrued pension benefits..................................... 77,186 99,699
Other........................................................ 88,396 98,570
------------ ------------
1,147,368 1,141,402
------------ ------------
Deferred Credits:
Accumulated deferred income taxes............................ 1,984,513 2,070,225
Accumulated deferred investment tax credits.................. 158,837 168,444
Deferred contractual obligations............................. 525,076 440,495
Other........................................................ 270,497 294,236
------------ ------------
2,938,923 2,973,400
------------ ------------
Commitments and Contingencies (Note 8)
Total Capitalization and Liabilities........................... $10,414,412 $10,741,748
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------
(Thousands of Dollars, except share 1997 1996
information) (Restated) (Restated) 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues................................ $ 3,834,806 $ 3,792,148 $ 3,750,560
------------- ------------- -------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power..... 1,293,518 1,139,848 909,244
Other......................................... 1,097,297 1,094,078 966,845
Maintenance..................................... 501,693 415,532 288,927
Depreciation.................................... 354,329 359,507 354,293
Amortization of regulatory assets, net.......... 130,900 122,573 128,413
Federal and state income taxes (See
Consolidated Statements of Income Taxes)....... 12,650 94,363 261,287
Taxes other than income taxes................... 253,637 257,577 249,463
------------- ------------- -------------
Total operating expenses (Note 1)........... 3,644,024 3,483,478 3,158,472
------------- ------------- -------------
Operating Income.................................. 190,782 308,670 592,088
------------- ------------- -------------
Other Income:
Deferred nuclear plants return--other funds..... 7,288 8,988 14,196
Equity in earnings of regional nuclear
generating and transmission companies......... 11,306 13,155 13,208
Other, net...................................... (38,473) 30,932 10,954
Minority interest in income of subsidiary....... (9,300) (9,300) (8,732)
Income taxes.................................... 10,702 (1,747) (683)
------------- ------------- -------------
Other (loss)/ income, net................... (18,477) 42,028 28,943
------------- ------------- -------------
Income before interest charges.............. 172,305 350,698 621,031
------------- ------------- -------------
Interest Charges:
Interest on long-term debt...................... 282,095 285,463 315,862
Other interest.................................. 3,561 7,649 6,666
Deferred nuclear plants return--borrowed funds.. (13,675) (15,119) (23,310)
------------- ------------- -------------
Interest charges, net....................... 271,981 277,993 299,218
------------- ------------- -------------
(Loss)/Income after interest charges......... (99,676) 72,705 321,813
Preferred Dividends of Subsidiaries............... 30,286 33,776 39,379
------------- ------------- -------------
Net (Loss)/Income (Note 1)........................ $ (129,962) $ 38,929 $ 282,434
============= ============= =============
(Loss)/Earnings Per Common Share (Note 1)......... $ (1.01) $ 0.30 $ 2.24
============= ============= =============
Common Shares Outstanding (average)............... 129,567,708 127,960,382 126,083,645
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- ------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
(Loss)/Income before preferred dividends of subsidiaries..... $ (99,676) $ 72,705 $ 321,813
Adjustments to reconcile to net cash
from operating activities:
Depreciation............................................... 354,329 359,507 354,293
Deferred income taxes and investment tax credits, net...... 26,435 71,832 164,208
Deferred nuclear plants return, net of amortization........ (13,781) (14,948) 71,788
Amortization of demand-side-management costs, net.......... 38,029 26,941 (937)
Recoverable energy costs, net of amortization.............. (54,102) (14,289) (27,874)
Amortization of PSNH acquisition costs..................... 56,557 56,884 55,547
Amortization of deferred cogeneration costs, net........... 32,700 25,957 (55,341)
Deferred nuclear refueling outage, net of amortization..... (36,514) 51,831 (29,569)
Other sources of cash...................................... 141,041 164,915 147,348
Other uses of cash......................................... (86,202) (41,589) (67,838)
Changes in working capital:
Receivables and accrued utility revenues .................. 262,384 (31,992) (72,081)
Fuel, materials, and supplies.............................. (1,307) (10,834) (10,518)
Accounts payable........................................... (104,269) 188,101 38,096
Accrued taxes.............................................. 38,966 (68,168) 17,686
Sale of receivables and accrued utility revenues........... 90,000 - -
Investments in securitizable assets........................ (230,905) - -
Other working capital (excludes cash)...................... (36,464) (21,383) (2,458)
---------- ---------- ----------
Net cash flows from operating activities (Note 1).............. 377,221 815,470 904,163
---------- ---------- ----------
Financing Activities:
Issuance of common shares.................................... 6,502 10,622 31,976
Issuance of long-term debt................................... 260,000 222,150 225,100
Issuance of Monthly Income
Preferred Securities........................................ - - 100,000
Net increase/(decrease) in short-term debt................... 11,250 (60,250) (91,000)
Reacquisitions and retirements of long-term debt............. (288,793) (248,142) (425,500)
Reacquisitions and retirements of preferred stock............ (25,000) (36,500) (140,675)
Cash dividends on preferred stock............................ (30,286) (33,776) (39,379)
Cash dividends on common shares.............................. (32,134) (176,277) (221,701)
---------- ---------- ----------
Net cash flows used for financing activities................... (98,461) (322,173) (561,179)
---------- ---------- ----------
Investment Activities:
Investment in plant:
Electric and other utility plant........................... (233,399) (222,829) (231,408)
Nuclear fuel............................................... (6,852) (14,529) (18,261)
---------- ---------- ----------
Net cash flows used for investments in plant................. (240,251) (237,358) (249,669)
Investment in nuclear decommissioning trusts................. (61,046) (65,716) (60,642)
Other investment activities, net............................. (28,257) (25,064) (30,761)
---------- ---------- ----------
Net cash flows used for investments............................ (329,554) (328,138) (341,072)
---------- ---------- ----------
Net (Decrease)/Increase In Cash For The Period................. (50,794) 165,159 1,912
Cash and cash equivalents - beginning of period................ 194,197 29,038 27,126
---------- ---------- ----------
Cash and cash equivalents - end of period...................... $ 143,403 $ 194,197 $ 29,038
========== ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized......................... $ 291,335 $ 268,129 $ 321,148
========== ========== ==========
Income taxes................................................. $ (26,387) $ 64,189 $ 108,928
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases.............. $ 3,475 $ 3,524 $ 41,388
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Shareholders' Equity
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
Capital Deferred Retained
Common Surplus, Contribution Earnings (b)
Shares(a) Paid In Plan--ESOP (Note 1) Total
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance as of January 1, 1995............... $ 671,051 $904,371 $ (213,324) $ 946,988 $2,309,086
---------- --------- ------------- ------------- -----------
Net income for 1995...................... 282,434 282,434
Cash dividends on common shares--
$1.76 per share....................... (221,701) (221,701)
Loss on retirement of preferred stock.... (381) (381)
Issuance of 1,400,940 common shares,
$5 par value........................... 7,005 24,971 31,976
Allocation of benefits-- ESOP............ 70 15,172 15,242
Capital stock expenses, net.............. 6,896 6,896
---------- --------- ------------- ------------- -----------
Balance as of December 31, 1995............. 678,056 936,308 (198,152) 1,007,340 2,423,552
---------- --------- ------------- ------------- -----------
Net income for 1996 (Note 1)............. 38,929 38,929
Cash dividends on common shares--
$1.38 per share....................... (176,277) (176,277)
Loss on retirement of preferred stock.... (374) (374)
Issuance of 440,772 common shares,
$5 par value........................... 2,204 8,418 10,622
Allocation of benefits-- ESOP............ (8,103) 22,061 13,958
Capital stock expenses, net.............. 3,077 3,077
Currency translation adjustments......... 746 746
---------- --------- ------------- ------------- -----------
Balance as of December 31, 1996 (Restated).. 680,260 940,446 (176,091) 869,618 2,314,233
---------- --------- ------------- ------------- -----------
Net loss for 1997 (Note 1)............... (129,962) (129,962)
Cash dividends on common shares--
$0.25 per share....................... (32,134) (32,134)
Issuance of 790,232 common shares,
$5 par value........................... 3,951 2,551 6,502
Allocation of benefits-- ESOP............ (12,238) 21,950 9,712
Capital stock expenses, net.............. 2,592 2,592
Currency translation adjustments......... (858) (858)
---------- --------- ------------- ------------- -----------
Balance as of December 31, 1997 (Restated).. $ 684,211 $932,493 $ (154,141) $ 707,522 $2,170,085
========== ========= ============= ============= ===========
(a) NU issued 8,430,910 warrants as part of its acquisition of PSNH. These warrants, which
expired on June 5, 1997, entitled the holder to purchase one share of NU common stock at an
exercise price of $24 per share. As of June 5, 1997, 464,678 shares had been purchased through
the exercise of warrants.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt
agreements. These restrictions also limit the amount of retained earnings available for NU
common dividends. At December 31, 1997, these restrictions totaled approximately $559.6 million.
The accompanying notes are an integral part of these financial statements.
</TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------------------------------
1997 1996
(Thousands of Dollars) (Restated) (Restated)
<S> <C> <C>
- -------------------------------------------------------------------------------------------------------
Common Shareholders' Equity (See Consolidated Balance Sheets).................. $2,170,085 $2,314,233
- -------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subisidiaries:
$25 par value--authorized 36,600,000 shares at December 31, 1997 and 1996;
4,840,000 shares outstanding in 1997 and 5,840,000 shares outstanding in 1996
$50 par value--authorized 9,000,000 shares at December 31, 1997 and 1996;
5,424,000 shares outstanding in 1997 and 5,424,000 shares outstanding in 1996
$100 par value--authorized 1,000,000 shares at December 31, 1997 and 1996;
200,000 shares outstanding in 1997 and 1996
- -------------------------------------------------------------------------------------------------------
Current Current
Dividend Rates Redemption Prices(a) Shares Outstanding
- -------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
$50 par value--$1.90 to $3.28 $50.50 to $54.00 2,324,000...... 116,200 116,200
$100 par value--$7.72 $103.51 200,000...... 20,000 20,000
- -------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory Redemption...................... 136,200 136,200
- -------------------------------------------------------------------------------------------------------
Subject to Mandatory Redemption: (b)
$25 par value--$1.90 to $2.65 $25.00 to $25.64 4,840,000...... 121,000 146,000
$50 par value--$2.65 to $3.615 $51.00 to $52.41 3,100,000...... 155,000 155,000
- -------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption.......................... 276,000 301,000
Less:Preferred Stock to be redeemed within one year............................ 30,250 25,000
- -------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption,net............................ 245,750 276,000
- -------------------------------------------------------------------------------------------------------
Long-term Debt: (c)
First Mortgage Bonds--
Maturity Interest Rates
- -------------------------------------------------------------------------------------------------------
1997 5.75% to 7.625%.......................................... - 207,988
1998 6.50% to 9.17%........................................... 199,800 199,800
1999 5.50% to 7.25%........................................... 279,000 279,000
2000 5.75% to 6.875%.......................................... 260,000 260,000
2001 7.375% to 7.875%......................................... 220,000 160,000
2002 7.75% to 9.05%........................................... 580,000 400,000
2004 6.125%................................................... 140,000 140,000
2019-2023 7.375% to 7.50%.......................................... 120,000 120,000
2024-2025 7.375% to 8.50%.......................................... 430,000 430,000
- -------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 2,228,800 2,196,788
- -------------------------------------------------------------------------------------------------------
Other Long-Term Debt --(d)
Pollution Control Notes and Other Notes--
2000 Adjustable Rate (e) and 7.67%............................ 218,033 224,182
2005-2006 8.38% to 8.58%........................................... 194,000 210,000
2013-2018 Adjustable Rate.......................................... 33,400 33,400
2020 Adjustable Rate.......................................... 15,300 15,300
2021-2022 7.50% to 7.65% and Adjustable Rate....................... 552,485 552,485
2028 Adjustable Rate.......................................... 369,300 369,300
2031 Adjustable Rate.......................................... 62,000 62,000
- -------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other Notes................................. 1,444,518 1,466,667
Fees and interest due for spent nuclear fuel disposal costs (Note 2P).......... 205,502 195,023
Other.......................................................................... 18,513 57,169
- -------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt..................................................... 1,668,533 1,718,859
- -------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net.......................................... (7,113) (7,463)
- -------------------------------------------------------------------------------------------------------
Total Long-Term Debt........................................................... 3,890,220 3,908,184
Less: Amounts due within one year.............................................. 244,561 294,503
- -------------------------------------------------------------------------------------------------------
Long-Term Debt, net............................................................ 3,645,659 3,613,681
- -------------------------------------------------------------------------------------------------------
Total Capitalization........................................................... $6,197,694 $6,340,114
=======================================================================================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
Notes to Consolidated Statements of Capitalization
(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
- ----------------------------------------------------------------------------
(Thousands of Dollars)
- ----------------------------------------------------------------------------
Balance at January 1, 1995 .............................. $ 379,675
Reacquisitions and Retirements .......................... (75,675)
- ----------------------------------------------------------------------------
Balance at December 31, 1995 ............................ 304,000
Reacquisitions and Retirements .......................... (3,000)
- ----------------------------------------------------------------------------
Balance at December 31, 1996 ............................ 301,000
Reacquisitions and Retirements .......................... (25,000)
- ----------------------------------------------------------------------------
Balance at December 31, 1997 ............................ $ 276,000
============================================================================
The minimum sinking-fund requirements of the series subject each year to
mandatory redemption aggregate approximately $30.3 million in 1998, $46.3
million each year in 1999, 2000 and 2001 and $21.3 million in 2002. In case of
default on sinking-fund payments, no payments may be made on any junior stock by
way of dividends or otherwise (other than in shares of junior stock) so long as
the default continues. If a subsidiary is in arrears in the payment of dividends
on any outstanding shares of preferred stock, the subsidiary is prohibited from
redeeming or purchasing less than all of the outstanding preferred stock.
(c) Long-term debt maturities and cash sinking-fund requirements, excluding
fees and interest due for spent nuclear fuel disposal costs, on debt outstanding
at December 31, 1997, for the years 1998 through 2002 are approximately $244.6
million, $375.9 million, $557.8 million, $313.2 million and $375.4 million,
respectively.
In addition, there are annual one percent sinking- and improvement-fund
requirements of approximately $1.5 million each year for 1998 and 1999 and $900
thousand each year for 2000 through 2002 for certain series of Western
Massachusetts Electric Company (WMECO) first mortgage bonds. The WMECO sinking-
and improvement-fund requirements may be satisfied by the deposit of cash or
bonds or by certification of property additions. The one percent sinking- and
improvement-fund requirements for The Connecticut Light and Power Company (CL&P)
first mortgage bonds are no longer required, as of 1997, as determined by a
majority of bond holders. Essentially all utility plant of CL&P, WMECO, Public
Service Company of New Hampshire (PSNH) and North Atlantic Energy Corporation
(NAEC), wholly owned subsidiaries of NU, is subject to the liens of each
company's respective first mortgage bond indenture.
NAEC's first mortgage bonds also are secured by payments made to NAEC by PSNH
under the terms of the Seabrook Power Contracts.
CL&P and WMECO have secured $369.3 million of pollution-control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.
CL&P and WMECO have issued $225 million and $90 million, respectively, of first
mortgage bonds as collateral to enable them to borrow under a three-year
revolving credit agreement. At December 31, 1997, CL&P and WMECO had $35 million
and $15 million, respectively, in borrowings under this agreement. PSNH's
Revolving Credit Facility has a second lien, junior to the lien of its first
mortgage bond indenture, on all PSNH property located in New Hampshire, which
will expire in April 1999. At December 31, 1997, PSNH had no borrowings under
the Revolving Credit Facility. For further information on these borrowing
facilities, see Note 4, "Short-Term Debt."
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with
a bond insurance and liquidity facility secured by first mortgage bonds.
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH
entered into financing arrangements with the Business Finance Authority (BFA) of
the state of New Hampshire. Pursuant to these arrangements, the BFA issued seven
series of PCRBs and loaned the proceeds to PSNH. At December 31, 1997, $516.5
million of the PCRBs were outstanding. PSNH's obligation to repay each series of
PCRBs is secured by a series of first mortgage bonds that were issued under its
indenture. Each such series of first mortgage bonds contains terms and
provisions with respect to maturity, principal payment, interest rate and
redemption that correspond to those of the applicable series of PCRBs. For
financial reporting purposes, these bonds would not be considered outstanding
unless PSNH fails to meet its obligations under the PCRBs.
(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.4 percent to 5.6 percent for 1997 and 3.2 percent to 5.5
percent for 1996.
(e) Interest-rate management instruments with financial institutions effectively
fix the interest rate of NAEC's $200 million variable-rate bank note at 7.823
percent. For further information, see Note 9, "Market Risk Management."
Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------
1997 1996
(Thousands of Dollars) (Restated) (Restated) 1995
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
The components of the federal and state income tax
provisions (credited)/charged to operations are:
Current income taxes
Federal......................................... $ (22,760) $ 13,500 $ 53,862
State........................................... (1,727) 10,778 43,900
- --------------------------------------------------------------------------------------
Total current..................................... (24,487) 24,278 97,762
- --------------------------------------------------------------------------------------
Deferred income taxes, net
Federal......................................... 46,871 90,093 167,091
State........................................... (10,841) (8,667) 7,224
- --------------------------------------------------------------------------------------
Total deferred.................................... 36,030 81,426 174,315
- --------------------------------------------------------------------------------------
Investment tax credits, net....................... (9,595) (9,594) (10,107)
- --------------------------------------------------------------------------------------
Total income tax expense (Note 1)................. $ 1,948 $ 96,110 $ 261,970
======================================================================================
The components of total income tax expense are
classified as follows:
Income taxes charged to operating expenses...... $ 12,650 $ 94,363 $ 261,287
Other income taxes.............................. (10,702) 1,747 683
- --------------------------------------------------------------------------------------
Total income tax expense.......................... $ 1,948 $ 96,110 $ 261,970
======================================================================================
Deferred income taxes comprise the tax effects of
temporary differences as follows:
Depreciation, leased nuclear fuel, settlement
credits and disposal costs..................... $ 32,932 $ 18,401 $ 82,318
Energy adjustment clauses....................... 5,916 (8,268) 26,851
Nuclear plant deferrals......................... 13,989 (15,549) 2,666
Contractual settlements......................... 1,754 2,513 (9,496)
Bond redemptions................................ (4,260) (4,685) 9,224
Amortization of New Hampshire regulatory
settlement..................................... 11,501 11,501 11,501
Deferred tax asset associated with net
operating losses............................... - 96,756 57,543
Demand-side management.......................... (12,169) (14,954) 765
State net operating loss carryforward........... (7,670) - -
Other........................................... (5,963) (4,289) (7,057)
- --------------------------------------------------------------------------------------
Deferred income taxes, net........................ $ 36,030 $ 81,426 $ 174,315
======================================================================================
A reconciliation between income tax expense and
the expected tax expense at 35 percent of pretax
income:
Expected federal income tax....................... $ (34,205) $ 59,085 $ 204,324
Tax effect of differences:
Depreciation.................................... 22,049 24,337 25,639
Deferred nuclear plants return.................. (2,551) (3,146) (4,969)
Amortization of regulatory assets............... 5,498 7,910 20,389
Amortization of PSNH acquisitions costs......... 31,298 31,410 31,522
Seabrook intercompany loss...................... (4,616) (7,503) (13,048)
Investment tax credit amortization.............. (9,595) (9,594) (10,107)
State income taxes, net of federal benefit...... (7,839) 1,372 33,231
Sale of Seabrook 2 steam generator.............. - (2,516) -
Adjustment for prior years' taxes............... (1,712) (962) (20,312)
Employee stock ownership plan................... (4,648) (4,007) (2,192)
Dividends received deduction.................... (1,563) (3,027) (3,936)
Loss reserve on sale of investment.............. 8,750 - -
Other, net...................................... 1,082 2,751 1,429
- --------------------------------------------------------------------------------------
Total income tax expense.......................... $ 1,948 $ 96,110 $ 261,970
======================================================================================
The accompanying notes are an integral part of these financial statements.
</TABLE>
Notes to Consolidated Financial Statements
1. Securities and Exchange Commission Inquiry
In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC)
inquired into Northeast Utilities' (NU or the company) accounting for nuclear
compliance costs. These costs are the unavoidable incremental costs associated
with the current nuclear outages required to be incurred prior to restart of
the units in accordance with correspondence received from the Nuclear Regulatory
Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs
associated with nuclear outages and procedures to be implemented at nuclear
power plants in response to regulatory requirements required prior to restart of
the units should be expensed as incurred. During 1996 and 1997, NU and its
wholly owned subsidiaries, CL&P, PSNH and WMECO reserved for these unavoidable
incremental costs that they expected to incur to meet NRC standards. The SEC
advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred.
While NU and its independent auditors, Arthur Andersen LLP, believed the
accounting was required by, and was in accordance with, generally accepted
accounting principles, the company has agreed to adjust its accounting for
nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The
financial statements in this report have been restated to reflect the change in
accounting.
2. Summary of Significant Accounting Policies
A. About Northeast Utilities
NU is the parent company of the Northeast Utilities system (the NU system). The
NU system furnishes franchised retail electric service in Connecticut, New
Hampshire and western Massachusetts through four wholly owned subsidiaries:
CL&P, PSNH, WMECO and Holyoke Water Power Company (HWP). A fifth wholly
owned subsidiary, NAEC, sells all of its entitlement to the capacity and output
of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its
franchised retail service, the NU system furnishes firm and other wholesale
electric services to various municipalities and other utilities, and
participates in limited retail access programs, providing off-system retail
electric service. The NU system serves about 30 percent of New England's
electric needs and is one of the 25 largest electric utility systems in the
country as measured by revenues.
Several wholly owned subsidiaries of NU provide support services for the NU
system companies and, in some cases, for other New England utilities. Northeast
Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing and other services to the NU system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
generating facilities. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibility for Seabrook. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by the NU system
companies. In addition, CL&P and WMECO each have established a special purpose
subsidiary whose business consists of the purchase and resale of receivables.
Charter Oak Energy, Inc. (COE), HEC, Inc. (HEC), Mode 1 Communications, Inc.
(Mode 1), and Select Energy, Inc., (formerly NUSCO Energy Partners, Inc.) are
other NU system companies which engage in a variety of activities.
Directly and through subsidiaries, COE has investments in cogeneration,
small-power production and other forms of nonutility generation as permitted
under the Public Utility Regulatory Policy Act, and in exempt wholesale
generators and foreign utility companies as permitted under the Energy Policy
Act of 1992 (Energy Act). These investments are accounted for on either a cost
or equity basis based upon COE's level of participation. NU has put COE up
for sale. For further information regarding the sale of COE, see Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A),
and Note 8G, "Commitments and Contingencies -- Sale of COE."
HEC provides energy management services for the NU system's and other utilities'
commercial, industrial and institutional electric customers. Mode 1 and Select
Energy, Inc. develop and invest in telecommunications and in energy-related
activities, respectively.
B. Presentation
The consolidated financial statements of the company include the accounts of all
wholly owned subsidiaries. Significant intercompany transactions have been
eliminated in consolidation.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with
the current year's presentation.
C. Public Utility Regulation
NU is registered with the SEC as a holding company under the Public Utility
Holding Company Act of 1935 (1935 Act). NU and its subsidiaries are subject to
the provisions of the 1935 Act. Arrangements among the NU system companies,
outside agencies and other utilities covering interconnections, interchange of
electric power and sales of utility property are subject to regulation by
the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating
subsidiaries are subject to further regulation for rates, accounting and other
matters by the FERC and/or applicable state regulatory commissions.
For information regarding proposed changes in the nature of industry regulation,
see Note 8A, "Commitments and Contingencies -- Restructuring and Rate Matters."
D. New Accounting Standards
The Financial Accounting Standards Board (FASB) issued two new accounting
standards in February 1997: Statement of Financial Accounting Standards (SFAS)
128, "Earnings per Share" and SFAS 129, "Disclosure of Information about Capital
Structure." SFAS 128 establishes standards for computing and presenting earnings
per share (EPS) and is effective for 1997. The adoption of SFAS 128 did not have
a material impact on the company's EPS calculation and presentation. SFAS 129
establishes standards for disclosing information about an entity's capital
structure. NU's current disclosures are consistent with the requirements of SFAS
129.
During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and
SFAS 131, "Disclosures about Segments of an Enterprise and Related Information."
SFAS 130 establishes standards for the reporting and disclosure of comprehensive
income. To date, the NU system companies have not had material transactions that
would be required to be reported as comprehensive income. SFAS 131 determines
the standards for reporting and disclosing qualitative and quantitative
information about a company's operating segments. This information includes
segment profit or loss, certain segment revenue and expense items and segment
assets and a reconciliation of these segment disclosures to corresponding
amounts in the company's general purpose financial statements. The NU system
currently evaluates management performance using a cost-based budget, and the
information required by SFAS 131 is not available. Therefore, these disclosure
requirements are not applicable. Management believes that the implementation of
SFAS 130 and SFAS 131 will not have a material impact on NU's current
disclosures.
See Note 7, "Sale of Customer Receivables and Accrued Utility Revenues," and
Note 8C, "Commitments and Contingencies -- Environmental Matters," for
information on other newly issued accounting and reporting standards related to
those specific areas.
E. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock of
four regional nuclear generating companies (Yankee companies). The NU system's
investments in the Yankee companies are accounted for on the equity basis due to
NU's ability to exercise significant influence over their operating and
financial policies. The Yankee companies, with the NU system's equity
investments and ownership interests are:
- ----------------------------------------------------------------------------
(Thousands of Dollars Except for Percentages)
- ----------------------------------------------------------------------------
Connecticut Yankee Atomic
Power Company (CYAPC) $54,671 49.0%
Yankee Atomic Electric
Company (YAEC) 8,020 38.5
Maine Yankee Atomic
Power Company (MYAPC) 15,699 20.0
Vermont Yankee Nuclear
Power Corporation (VYNPC) 8,565 16.0
- ----------------------------------------------------------------------------
Total Equity Investment $86,955
============================================================================
Each Yankee company owns a single nuclear generating unit. Under the terms of
the contracts with the Yankee companies, the shareholders-sponsors are
responsible for their proportionate share of the costs of each unit, including
decommissioning. The energy and capacity costs from VYNPC and nuclear
decommissioning costs of the Yankee companies that have been shut down are
billed as purchased power to CL&P, PSNH and WMECO.
The electricity produced by the Vermont Yankee nuclear generating facility (VY)
is committed substantially on the basis of ownership interests and is billed
pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's nuclear power
plants were shut down permanently on February 26, 1992, December 4, 1996, and
August 6, 1997, respectively. Under ownership agreements with the Yankee
companies, CL&P, PSNH and WMECO may be asked to provide direct or indirect
financial support for one or more of the companies. For more information on the
Yankee companies, see Note 3, "Nuclear Decommissioning," and Note 8F,
"Commitments and Contingencies -- Long-Term Contractual Arrangements."
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a 660-
megawatt (MW) nuclear generating unit and Millstone 2, a 870-MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154-MW nuclear generating unit.
The three Millstone units are out of service. NU hopes to return Millstone 3 to
service in early spring of 1998 and Millstone 2 three to four months after
Millstone 3. Millstone 1 has been placed in extended maintenance status.
Management is reviewing its options with respect to Millstone 1, including
restart, early retirement and other options. In a draft ruling issued in
February 1998, the Connecticut Department of Public Utility Control (DPUC)
determined that Millstone 1 was no longer "used and useful" and ordered it
removed from rate base.
In 1996, one of the joint owners of Millstone 3, Vermont Electric Generation and
Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy. The subsequent
liquidation resulted in the offering of VEG&T's 0.035 percent share of Millstone
3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners
accepted the offer. During 1998, CL&P expects to make the necessary regulatory
filings to acquire ownership of VEG&T's share of Millstone 3.
For more information regarding the DPUC's action, see the MD&A. For more
information regarding the Millstone units see Note 3, "Nuclear Decommissioning,"
and Note 8B, "Commitments and Contingencies -- Nuclear Performance."
Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook 1 to PSNH under two long-term
contracts (the Seabrook Power Contracts).
Plant-in-service and the accumulated provision for depreciation for the NU
system's share of the three Millstone units and Seabrook 1 are as follows:
- -----------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------
(Millions of Dollars) 1997 1996
- -----------------------------------------------------------------------------
Plant-in-service
Millstone 1 $ 478.7 $ 474.7
Millstone 2 857.1 851.8
Millstone 3 2,404.3 2,402.4
Seabrook 1 897.5 892.4
Accumulated provision for depreciation
Millstone 1 $ 212.1 $ 196.6
Millstone 2 306.7 275.8
Millstone 3 695.1 633.3
Seabrook 1 150.0 131.7
=============================================================================
The NU system's share of Millstone and Seabrook 1 expenses are included in the
corresponding operating expenses on the accompanying Consolidated Statements of
Income.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
approximately $19.6 million, in two companies that transmit electricity imported
from the Hydro-Quebec system in Canada. The two companies own and operate
transmission and terminal facilities which have the capability of importing up
to 2,000 MW from the Hydro-Quebec system. See Note 8F, "Commitments and
Contingencies -- Long-Term Contractual Arrangements," for additional
information.
F. Depreciation
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency.
Except for major facilities, depreciation rates are applied to the average
plant-in-service during the period. Major facilities are depreciated from the
time they are placed in service. When plant is retired from service, the
original cost of plant, including costs of removal, less salvage, is charged to
the accumulated provision for depreciation. The depreciation rates for the
several classes of electric plant-in-service are equivalent to a composite rate
of 3.8 percent in 1997, 1996 and 1995. See Note 3, "Nuclear Decommissioning,"
for information on nuclear plant decommissioning.
The NU system's nonnuclear generating facilities have limited service lives.
Plant may be retired in place or dismantled based upon expected future needs,
the economics of the closure and environmental concerns. The costs of closure
and removal are incremental costs and, for financial reporting purposes, are
accrued over the life of the asset as part of depreciation. At December 31, 1997
and 1996, the accumulated provision for depreciation included approximately
$83.2 million and $77.3 million, respectively, accrued for the cost of removal,
net of salvage for nonnuclear generation property.
G. Revenues
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, commercial and industrial customers and limited retail access
programs, utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through a
formal proceeding before the appropriate regulatory commission. Regulatory
commissions also have authority over the terms and conditions of nontraditional
rate-making arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue an estimate for the amount of energy delivered but unbilled.
For information on rate proceedings and their potential impact on CL&P and
PSNH, see the MD&A.
H. Regulatory Accounting and Assets
The accounting policies of the operating companies and the accompanying
consolidated financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." Assuming a cost-of-service based
regulatory structure, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered through future revenues. Through their
actions, regulators also may reduce or eliminate the value of an asset, or
create a liability. If any portion of the operating companies' operations were
no longer subject to the provisions of SFAS 71, as a result of a change in the
cost-of-service based regulatory structure or the effects of competition, the
company would be required to write off all of its related regulatory assets and
liabilities unless there is a formal transition plan which provides for the
recovery, through established rates, for the collection of approved stranded
costs and to maintain the cost-of-service basis for the remaining regulated
operations. At the time of transition, the operating companies would be required
to determine any impairment to the carrying costs of deregulated plant and
inventory assets.
Management anticipates that restructuring programs will be implemented within
each of the NU system operating companies' respective jurisdictions during the
next few years. In a restructured environment, the companies' generation
businesses no longer will be rate regulated on a cost-of-service basis. The
majority of NU's regulatory assets are related to its generation business.
The staff of the SEC has had concerns regarding the appropriateness of the
utilities' ability to continue application of SFAS 71 for the generation portion
of their business in a restructured environment. The SEC referred the issue to
the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and
issued "Deregulation of the Pricing of Electricity-Issues Related to the
Application of FASB Statements No. 71 and 101" (EITF 97-4). The EITF concluded:
(1) the future recognition of regulatory assets for the portion of the business
that no longer qualifies for application of SFAS 71 depends on the regulators'
treatment of the recovery of those costs and other stranded assets from cash
flows of other portions of the business still considered to be regulated, and
(2) a utility should discontinue the application of SFAS 71 when a legislative
and regulatory plan has been enacted, which would include transition plans
into a competitive environment, and when the stranded costs which are subject to
future rate recovery are determined. EITF 97-4 became effective in August 1997.
Electric utility industry restructuring within the state of Massachusetts will
be effective March 1, 1998. WMECO has submitted its proposed restructuring plan
to the Massachusetts Department of Telecommunications and Energy (DTE), formerly
the Massachusetts Department of Public Utilities. If the DTE approves the plan
in its current form, WMECO would discontinue the application of SFAS 71.
However, the restructuring legislation enacted by the state of Massachusetts
specifically provides for future deferrals and the cost recovery of generation-
related assets as contemplated under the plan. As such, WMECO is not expected to
have to write off either its generation-related assets or related regulatory
assets. WMECO's generation-related regulatory assets were valued at
approximately $188 million at December 31, 1997.
The issue of restructuring the electric utility industry in New Hampshire is
currently the focus of negotiations and proceedings within the federal and state
court systems. Management believes that PSNH's use of regulatory accounting
remains appropriate while this issue remains in litigation.
The Connecticut General Assembly is addressing a proposal for electric industry
restructuring in the state of Connecticut during 1998. As the terms and
conditions to be contained within the restructuring plan cannot be determined at
this time, management believes that its use of regulatory accounting within this
jurisdiction remains appropriate.
The company expects that its transmission and distribution business within each
of its jurisdictions will continue to be rate regulated on a cost-of-service
basis and, accordingly, CL&P, WMECO and PSNH will continue to apply SFAS 71 to
this portion of their business.
For further information on the NU system companies' respective regulatory
environments and the potential impacts of restructuring, see Note 8A,
"Commitments and Contingencies -- Restructuring and Rate Matters" and the MD&A.
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," requires the evaluation of long-lived assets,
including regulatory assets, for impairment when certain events occur or when
conditions exist that indicate the carrying amounts of assets may not be
recoverable. SFAS 121 requires that any long-lived assets which are no longer
probable of recovery through future revenues be revalued based on estimated
future cash flows. If this revaluation is less than the book value of the asset,
an impairment loss would be charged to earnings.
Management continues to believe it is probable that the operating companies will
recover their investments in long-lived assets through future revenues. This
conclusion may change in the future as the implementation of restructuring plans
within the NU system companies' respective jurisdictions will generally require
the formation of separate generation entities that will be subject to
competitive market conditions. As a result, the NU system companies will be
required to assess the carrying amounts of their long-lived assets in accordance
with SFAS 121. The components of the NU system companies' regulatory assets are
as follows:
- ----------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996
Income taxes, net (Note 2I) $ 938,564 $1,012,343
Recoverable energy costs,
net (Note 2K) 324,809 328,863
Deferred costs -- nuclear
plants (Note 2L) 199,753 185,078
Unrecovered contractual
obligations (Note 3) 515,076 435,495
Deferred demand-side
management costs (Note 2M) 52,100 90,129
Cogeneration costs (Note 2N) 33,505 66,205
Seabrook deferral (Note 2L) 8,376 --
Other 101,095 103,726
- ---------------------------------------------------------------------------
$2,173,278 $2,221,839
===========================================================================
I. Income Taxes
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods in
which they affect the determination of taxable income) is accounted for in
accordance with the ratemaking treatment of the applicable regulatory
commissions. See the Consolidated Statements of Income Taxes for the components
of income tax expense.
The tax effect of temporary differences, including timing differences accrued
under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:
- -----------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996
- -----------------------------------------------------------------------------
Accelerated depreciation and
other plant-related
differences $ 1,567,597 $ 1,640,068
Net operating loss
carryforwards (102,492) (94,149)
Regulatory assets --
income tax gross up 395,619 423,363
Other 123,789 100,943
- -----------------------------------------------------------------------------
$ 1,984,513 $ 2,070,225
=============================================================================
At December 31, 1997, PSNH had a net operating loss (NOL) carryforward of
approximately $293 million that can be used against PSNH's federal taxable
income and which, if unused, expires between the years 2000 and 2006. CL&P had a
state of Connecticut NOL carryforward of approximately $131 million that can be
used against CL&P and its affiliates' combined Connecticut taxable income and
which, if unused, expires in the year 2002. PSNH also had Investment Tax Credit
(ITC) carryforwards of $40 million which, if unused, expire between the years
1998 and 2004. For a portion of the carryforward amounts indicated above, the
reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code
limits the annual amount of PSNH NOL and ITC carryforwards that may be used.
Approximately $31 million of the NOL and $9 million of the ITC carryforwards are
subject to this limitation.
J. Unamortized PSNH Acquisition Costs
The unamortized PSNH acquisition costs represent the aggregate value placed by
the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on
PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets,
plus the $700 million value assigned to Seabrook by the Rate Agreement, as part
of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate
Agreement provides for the recovery through rates, with a return, of the
unamortized PSNH acquisition costs. The Rate Agreement provides that $425
million of the unamortized PSNH acquisition costs be amortized over the first
seven years after PSNH's May 16, 1991 reorganization from bankruptcy
(Reorganization Date) with the remaining amount to be amortized over the 20-year
period after the Reorganization Date. The unrecovered balance of PSNH
acquisition costs at December 31, 1997, was approximately $402.3 million. In
accordance with the Rate Agreement, approximately $32.9 million of this amount
will be recovered through rates by June 1, 1998, and the remaining amount of
approximately $369.4 million will be recovered through rates by 2011. As of
December 31, 1997, PSNH has collected approximately $591 million of acquisition
costs through rates.
K. Recoverable Energy Costs
Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed for
their proportionate shares of the costs of decontaminating and decommissioning
uranium enrichment plants owned by the United States Department of Energy (D&D
assessment). The Energy Act requires that regulators treat D&D assessments as a
reasonable and necessary current cost of fuel, to be fully recovered in rates
like any other fuel cost. CL&P, PSNH, WMECO and NAEC are currently recovering
these costs through rates. As of December 31, 1997, the company's total D&D
deferrals were approximately $63.7 million.
CL&P: During 1997, CL&P implemented an energy adjustment clause (EAC) under
which fuel prices above or below base-rate levels are charged or credited to
customers. The EAC replaced CL&P's fuel adjustment and generation utilization
adjustment clauses and is designed to reconcile and adjust the difference
between actual fuel costs and the fuel revenue collected through base rates on a
six-month basis.
For the period January 1, 1997 through June 30, 1997, CL&P agreed to a zero EAC
rate. For the period July 1, 1997 through December 31, 1997, the DPUC approved
an EAC rate through which CL&P recovered approximately $11.5 million
of deferred fuel costs. While this proceeding did not include provisions for the
recovery of approximately $18 million of costs related to the early closing of
CYAPC's nuclear generating unit, it did allow for the recovery of costs, subject
to refund, related to the closure of MYAPC's nuclear generating unit. CL&P has
appealed the DPUC's ruling related to CYAPC replacement power costs.
During December 1997, the DPUC approved an EAC rate for the period January 1,
1998 through June 30, 1998. During this period, CL&P will recover approximately
$27.9 million of deferred fuel costs.
At December 31, 1997, CL&P's net recoverable energy costs, excluding current net
recoverable energy costs, were approximately $104.8 million, which includes
approximately $50.1 million of costs related to CL&P's share of the D&D
assessment.
PSNH: The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period that began in May 1991, the retail portion of differences
between the fuel and purchased power costs assumed in the Rate Agreement and
PSNH's actual costs, which include the costs related to the Seabrook Power
Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are
subject to a prudence review by the New Hampshire Public Utilities Commission
(NHPUC).
Under the Rate Agreement, the deferred Seabrook return is being deferred by PSNH
and subsequently will be billed and collected by PSNH through the FPPAC. PSNH
began to defer the amount of these costs on December 1, 1997, and will continue
to do so for the period from December 1, 1997 through May 31, 1998. Beginning on
June 1, 1998, these costs will be recovered from PSNH customers over a 36-month
period. At December 31, 1997, PSNH has deferred approximately $8.4 million of
these costs.
On February 10, 1998, the NHPUC established a FPPAC rate for the period
December 1, 1997 through May 31, 1998. The new FPPAC rate increased customer
billings by approximately six percent. This rate continues to defer a
substantial portion of these costs.
At December 31, 1997, PSNH's net recoverable energy costs, excluding current net
recoverable energy costs, were approximately $191.7 million. This amount
includes approximately $172.9 million of deferred small power producer costs.
WMECO: WMECO has a fuel adjustment clause (FAC) which includes energy costs
along with capacity and transmission charges and credits that result from short-
term transactions with other utilities and from certain FERC-approved contracts
among the NU system's operating companies. The Massachusetts restructuring
legislation will effectively eliminate the FAC, effective March 1, 1998.
On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a
settlement agreement with the Massachusetts Attorney General which allowed WMECO
to recover approximately $15.3 million of fuel costs for the period September
1997 through February 1998.
At December 31, 1997, WMECO's net recoverable energy costs were approximately
$26.3 million, which includes approximately $11.3 million of costs related to
WMECO's share of the D&D assessment.
For further information on recoverable energy costs, see the MD&A.
L. Deferred Costs -- Nuclear Plants
As of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion
of its investment in Seabrook 1. This plan is in compliance with SFAS 92,
"Regulated Enterprises -- Accounting for Phase-in Plans." From the Acquisition
Date through November 1997, NAEC recorded $203.9 million of deferred return on
its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant
included $84.1 million of deferred return that was transferred as part of the
Seabrook plant assets to NAEC on the Acquisition Date. Beginning on December 1,
1997, the deferred return, including the portion transferred to NAEC, is
currently being billed through the Seabrook Power Contracts to PSNH and will be
fully recovered from customers by May 2001.
M. Demand-Side Management (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation Adjustment
Mechanism. CL&P is allowed to recover DSM costs in excess of costs reflected in
base rates over periods ranging from approximately four to ten years.
During April 1997, the DPUC approved CL&P's DSM budget of $36 million for 1997.
In October 1997, CL&P and other interested parties filed a stipulation with the
DPUC requesting that the DPUC approve certain programs and establish a budget
level of $32.7 million for 1998 and $28.8 million for 1999. The $52.1 million of
DSM costs on CL&P's books as of December 31, 1997, currently being collected,
will be fully recovered by 2000.
N. CL&P Cogeneration Costs
Beginning on July 1, 1996, the deferred cogeneration balance of approximately
$86 million is being amortized over a five year period. An additional $9 million
of amortization was applied to the deferred balance in 1997, as required under a
settlement agreement which CL&P reached with the DPUC. CL&P continues to apply
any savings associated with the renegotiation of a certain contract with a
cogeneration facility to the deferred balance. Under current expectations, CL&P
expects complete amortization of the deferred balance by December 31, 1998. At
December 31, 1997, CL&P's deferred cogeneration costs balance was approximately
$33.5 million.
O. Market Risk-Management Policies
The company utilizes market risk-management instruments, including swaps,
collars, puts and calls, to hedge well-defined risks associated with variable
interest rates and changes in fuel prices. To qualify for hedge treatment, the
underlying hedged item must expose the company to risks associated with market
fluctuations and the market risk-management instrument used must be designated
as a hedge and must reduce the company's exposure to market fluctuations
throughout the period. Amounts receivable or payable under fuel-price
management instruments are recognized in operating revenues when realized.
Amounts receivable or payable under interest-rate management instruments are
accrued and offset against interest expense. The company does not use market
risk-management instruments for speculative purposes. For further information,
see Note 9, "Market Risk Management."
P. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO and NAEC must pay
the United States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the selection
and development of repositories for, and the disposal of, spent nuclear fuel and
high-level radioactive waste. Fees for nuclear fuel burned on or after April 7,
1983, are billed currently to customers and paid to the DOE on a quarterly
basis. For nuclear fuel used to generate electricity prior to April 7, 1983
(prior-period fuel), payment must be made prior to the first delivery of spent
fuel to the DOE. Until such payment is made, the outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield Rate. At
December 31, 1997, fees due to the DOE for the disposal of prior-period fuel
were approximately $205.5 million, including interest costs of $123.4 million.
The DOE was originally scheduled to begin accepting delivery of spent fuel in
1998. However, delays in identifying a permanent storage site have continually
postponed plans for the DOE's long-term storage and disposal site. Extended
delays or a default by the DOE could lead to consideration of costly
alternatives. The company has primary responsibility for the interim storage of
its spent nuclear fuel. Current capability to store spent fuel at Millstone 1, 2
and Seabrook are estimated to be adequate until the years 2004 for Millstone 1
and 2 and 2010 for Seabrook. Storage facilities for Millstone 3 are expected to
be adequate for the projected life of the unit. Meeting spent fuel storage
requirements beyond these periods could require new and separate storage
facilities, the costs for which have not been determined.
In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled
that the lack of an interim storage facility does not excuse the DOE from
meeting its contractual obligation to begin accepting spent nuclear fuel no
later than January 31, 1998. Currently, the DOE has not taken the spent nuclear
fuel as scheduled and, as a result, may have to pay contract damages. The
ultimate outcome of this legal proceeding is uncertain at this time.
Q. Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
3. Nuclear Decommissioning
Millstone and Seabrook: The NU system's nuclear power plants have service lives
that are expected to end during the years 2010 through 2026. Upon retirement,
these units must be decommissioned. Current decommissioning studies concluded
that complete and immediate dismantlement at retirement continues to be the most
viable and economic method of decommissioning the three Millstone units and
Seabrook 1. Decommissioning studies are reviewed and updated periodically to
reflect changes in decommissioning requirements, costs, technology and
inflation.
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1997
dollars, is $482.6 million and $432.2 million, respectively. The NU system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 in year-end 1997 dollars, is $377.4 million and $189.4 million,
respectively. The Millstone units and Seabrook 1 decommissioning costs will be
increased annually by their respective escalation rates. Nuclear decommissioning
costs are accrued over the expected service life of the units and are included
in depreciation expense on the Consolidated Statements of Income. Nuclear
decommissioning costs amounted to $48.8 million in 1997, $47.8 million in 1996
and $38.9 million in 1995. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on the Consolidated
Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated
reserve for depreciation amounted to $540.8 million and $435.7 million,
respectively.
CL&P and WMECO have established external decommissioning trusts through a
trustee for their portions of the costs of decommissioning Millstone 1, 2 and 3.
PSNH makes payments to an independent decommissioning trust for its portion of
the costs of decommissioning Millstone 3. CL&P's and NAEC's portions of the cost
of decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the estimated
decommissioning costs assumes levelized collections for the Millstone units and
escalated collections for Seabrook 1 and after-tax earnings on the Millstone and
Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent,
respectively.
As of December 31, 1997, CL&P, PSNH and WMECO collected through rates $277.9
million, $2.6 million and $59.7 million, respectively, toward the future
decommissioning costs of their share of the Millstone units, of which $302.6
million has been transferred to external decommissioning trusts. As of December
31, 1997, CL&P and NAEC (including payments made prior to the Acquisition Date
by PSNH) paid approximately $2.9 million and $21.1 million, respectively, into
Seabrook 1's decommissioning financing fund. Earnings on the decommissioning
trusts and financing fund increase the decommissioning trust balance and the
accumulated reserve for depreciation. Unrealized gains and losses associated
with the decommissioning trusts and financing fund also impact the balance of
the trusts and the accumulated reserve for depreciation.
Changes in requirements or technology, the timing of funding or dismantling or
adoption of a decommissioning method other than immediate dismantlement would
change decommissioning cost estimates and the amounts required to be recovered.
CL&P, PSNH and WMECO attempt to recover sufficient amounts through their allowed
rates to cover their expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
regulatory agencies is reflected in rates of the NU system companies. Based on
present estimates and assuming its nuclear units operate to the end of their
respective license periods, the NU system expects that the decommissioning
trusts and financing fund will be substantially funded when the units are
retired from service.
Millstone 1 has been placed in extended maintenance status while management is
reviewing its options with respect to the unit. These include restart, early
retirement and other options. Relating to management's consideration of the
option to immediately retire Millstone 1 are certain Connecticut state law
issues. In its four-year rate review proceeding, the DPUC noted that CL&P may
not be able to obtain its remaining investment in Millstone 1 if it were to
determine that the unit had been prematurely shut down due to management
imprudence. Additionally, there is a Connecticut statute which may limit CL&P's
ability to collect future decommissioning charges related to Millstone 1 if
Millstone 1 were to be terminated before the end of its expected life.
At December 31, 1997, CL&P's net unrecovered Millstone 1 plant costs were $215.7
million and the remaining unrecovered decommissioning costs were approximately
$198 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share of
estimated costs, in year-end 1997 dollars, of decommissioning this unit is $80.8
million.
On August 6, 1997, the board of directors of MYAPC voted unanimously to cease
permanently the production of power at its nuclear generating facility (MY). The
NU system companies had relied on MY for approximately one percent of their
capacity. During November 1997, MYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. During January 1998, the FERC accepted the amendments
and proposed rates, subject to refund. At December 31, 1997, the remaining
estimated obligation, including decommissioning, amounted to approximately
$867.2 million, of which the NU system's share was approximately $173.4 million.
On December 4, 1996, the board of directors of CYAPC voted unanimously to cease
permanently the production of power at its nuclear generating plant (CY).
During 1996, the NU system companies had relied on CY for approximately three
percent of their capacity. During late December 1996, CYAPC filed an amendment
to its power contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. On February 27, 1997, the FERC
approved an order for hearing which, among other things, accepted CYAPC's
contract amendment. The new rates became effective March 1, 1997, subject to
refund. At December 31, 1997, the remaining estimated obligation, including
decommissioning, amounted to $619.9 million, of which the NU system's share was
approximately $303.7 million.
YAEC is in the process of decommissioning its nuclear facility. At
December 31, 1997, the estimated remaining costs, including decommissioning,
amounted to $124.4 million, of which the NU system's share was approximately
$47.9 million.
Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-
sponsor companies, including CL&P, WMECO and PSNH, are responsible for their
proportionate share of the costs of the units, including decommissioning.
Management expects that CL&P, PSNH and WMECO each will continue to be allowed to
recover these costs from their customers. Accordingly, CL&P, PSNH and WMECO have
recognized these costs as regulatory assets, with corresponding obligations.
Proposed Accounting: The staff of the SEC has questioned certain current
accounting practices of the electric utility industry, including NU, regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating units in the financial statements. In response to these
questions, the FASB has agreed to review the accounting for closure and removal
costs, including decommissioning. If current electric utility industry
accounting practices for nuclear power plant decommissioning are changed, the
annual provision for decommissioning could increase relative to 1997, and the
estimated cost for decommissioning could be recorded as a liability (rather than
as accumulated depreciation), with recognition of an increase in the cost of the
related nuclear power plant. Management believes that the operating companies
each will continue to be allowed to recover decommissioning costs through rates.
4. Short-Term Debt
Limits: The amount of short-term borrowings that may be incurred by the NU
system's utility companies is subject to periodic approval by either the SEC
under the 1935 Act or by their respective state regulators. SEC authorization
allowed CL&P, WMECO and NAEC, as of January 1, 1998, to incur total short-term
borrowings up to a maximum of $375 million, $150 million and $60 million,
respectively. In addition, the charter of WMECO contains a provision which
restricts the total amount of unsecured debt that it may borrow at any one time.
As of January 1, 1998, this charter provision allowed WMECO to incur unsecured
borrowings, whether short-term or long-term, up to a maximum of approximately
$114 million. PSNH was authorized under a waiver from the NHPUC to incur short-
term borrowings up to a maximum of $125 million effective May 1997.
Credit Agreements: In May 1997, because of the potential for NU and CL&P to
violate their various financial ratio tests, NU amended the three-year revolving
credit agreement (Credit Agreement) with a group of 12 banks. Under the amended
Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability
of first mortgage bond collateral, up to $313.75 million and $150 million,
respectively. At December 31, 1997, CL&P and WMECO have issued first mortgage
bonds to enable borrowings under this facility up to a maximum of $225 million
and $90 million, respectively. NU, which cannot issue first mortgage bonds, will
be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet
certain interest coverage tests for two consecutive quarters. In addition, CL&P
and WMECO each must meet certain minimum quarterly financial ratios to access
the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter
ending December 31, 1997. The overall limit for all of the borrowing system
companies under the entire Credit Agreement is $313.75 million. The companies
are obligated to pay a facility fee of .50 percent per annum of each bank's
total commitment under this Credit Agreement, which will expire in November
1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million,
respectively, in borrowings under this Credit Agreement.
In February 1998, because of borrowing restrictions on NU in the amended Credit
Agreement, NU entered into a separate $25 million 364-day revolving credit
facility (Credit Facility) with one bank. NU is obligated to pay a facility fee
of .625 percent per annum on the unused commitment.
In addition to the Credit Agreement and Credit Facility, NU, CL&P, WMECO, HWP
and The Rocky River Realty Company (RRR) have various revolving credit
lines through separate bilateral credit agreements. Under this facility, four
banks maintain commitments to the respective companies totaling $56.25 million.
NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP
and RRR may borrow up to their SEC or board authorized short-term debt limit of
$5 million and $22 million, respectively. Under the terms of this facility, the
companies are obligated to pay a facility fee of .15 percent per annum of each
bank's total commitment. These commitments will expire in December 1998. At
December 31, 1997 and 1996, there were no borrowings and $11.3 million in
borrowings, respectively, under this facility.
PSNH has a $125 million revolving credit agreement that will expire in April
1999. The revolving credit agreement is with a group of 16 banks. PSNH is
obligated to pay a facility fee of .50 percent per annum on the commitment of
$125 million. At December 31, 1997 and 1996, there were no borrowings under the
facility.
Under the credit facilities discussed above, with the exception of the $25
million NU Credit Facility, the NU system companies may borrow funds on a short-
term revolving basis under their respective agreements, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding. Standby
loans are based upon several alternative variable rates. Loans advanced under
the $25 million NU Credit Facility are on a standby basis only. The weighted
average annual interest rate on the NU system companies' notes payable to banks
outstanding on December 31, 1997 and 1996 was 6.95 percent and 8.3 percent,
respectively. Maturities of short-term debt obligations were for periods of
three months or less.
For further information on short-term debt, including the ability to access
these agreements, see the MD&A.
5. Leases
CL&P and WMECO may finance up to $400 million of nuclear fuel for Millstone 1
and 2 and their respective shares of the nuclear fuel for Millstone 3 under the
Niantic Bay Fuel Trust (NBFT) capital lease agreement which is scheduled to
expire July 31, 1998. The NBFT capital lease agreement, which was amended in
February 1998, requires CL&P and WMECO to secure their obligation to repay the
NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue
these bonds by May 1998.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates which
reflect estimated kilowatt hours of energy provided plus financing costs
associated with the fuel in the reactors. Upon permanent discharge from the
reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The NU
system companies also have entered into lease agreements, some of which are
capital leases, for the use of data processing and office equipment, vehicles,
gas turbines, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $19.0 million in
1997, $28.2 million in 1996 and $75.9 million in 1995. Interest included in
capital lease rental payments was $13.6 million in 1997, $14.1 million in 1996
and $15.0 million in 1995. Operating lease rental payments charged to expense
were $17.3 million in 1997, $18.3 million in 1996 and $20.9 million in 1995.
Future minimum rental payments, excluding executory costs such as property
taxes, state use taxes, insurance and maintenance, under long-term noncancelable
leases, as of December 31, 1997, are:
- ---------------------------------------------------------------------------
(Thousands of Dollars)
- ---------------------------------------------------------------------------
Capital Operating
Year Leases Leases
- ---------------------------------------------------------------------------
1998 $181,000 $ 25,800
1999 8,500 23,200
2000 7,900 21,000
2001 5,800 16,500
2002 3,200 8,000
After 2002 54,900 26,600
- ---------------------------------------------------------------------------
Future minimum
lease payments 261,300 $121,100
========
Less amount
representing interest 53,300
--------
Present value of future
minimum lease payments $208,000
========
6. Employee Benefits
A. Pension Benefits
The NU system's subsidiaries participate in a uniform noncontributory defined
benefit retirement plan covering all regular NU system employees. Benefits are
based on years of service and the employees' highest eligible compensation
during 60 consecutive months of employment. Total pension (credit)/cost, part of
which was (credited)/charged to utility plant, approximated $(22.5) million in
1997, $9.1 million in 1996 and $0.4 million in 1995. Pension (credit)/costs for
1997, 1996 and 1995 included approximately $(2.6) million, $7.8 million and
$6.8 million, respectively, related to workforce reduction programs.
Currently, the subsidiaries annually fund an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income Security Act and
the Internal Revenue Code. Pension costs are determined using market-related
values of pension assets. Pension assets are invested primarily in domestic and
international equity securities and bonds.
The components of net pension (credit)/cost are:
- ----------------------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996 1995
- ----------------------------------------------------------------------------
Service cost $ 32,298 $ 43,206 $ 35,771
Interest cost 98,621 94,722 89,351
Return on plan assets (337,198) (232,604) (310,997)
Net amortization 183,752 103,745 186,310
- -----------------------------------------------------------------------------
Net pension (credit)/cost $ (22,527) $ 9,069 $ 435
=============================================================================
For calculating pension costs, the following assumptions were used:
- -----------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------------------
Discount rate 7.75% 7.50% 8.25%
Expected long-term
rate of return 9.25 8.75 8.50
Compensation/progression rate 4.75 4.75 5.00
=============================================================================
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- ----------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996
- ----------------------------------------------------------------------------
Accumulated benefit obligation
including vested benefits at
December 31, 1997 and 1996
of $(1,003,157,000) and
$(943,696,000), respectively $(1,106,850) $(1,037,908)
- ----------------------------------------------------------------------------
Projected benefit obligation $(1,392,833) $(1,321,146)
Market value of plan assets 1,919,414 1,660,404
- -----------------------------------------------------------------------------
Market value in excess of
projected benefit obligation 526,581 339,258
Unrecognized transition
amount (10,562) (12,105)
Unrecognized prior service cost 29,711 31,802
Unrecognized net gain (622,916) (458,654)
- ----------------------------------------------------------------------------
Accrued pension liability $ (77,186) $ (99,699)
=============================================================================
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- ----------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------
1997 1996
- -----------------------------------------------------------------------------
Discount rate 7.25% 7.75%
Compensation/progression rate 4.25 4.75
=============================================================================
B. Postretirement Benefits Other Than Pensions
The NU system's subsidiaries provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees (referred to as SFAS 106 benefits). These benefits are
available for employees retiring from the NU system who have met specified
service requirements. For current employees and certain retirees, the total SFAS
106 benefit is limited to two times the 1993 per-retiree health care cost. The
SFAS 106 obligation has been calculated based on this assumption. Total SFAS 106
benefit costs, part of which were deferred or charged to utility plant,
approximated $28.3 million in 1997, $39.2 million in 1996 and $44.1 million in
1995. NU's subsidiaries are funding SFAS 106 postretirement costs through
external trusts. The subsidiaries are funding, on an annual basis, amounts that
have been rate-recovered and which also are tax deductible under the Internal
Revenue Code. The trust assets are invested primarily in equity securities and
bonds.
The components of health care and life insurance cost are:
- -----------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996 1995
- -----------------------------------------------------------------------------
Service cost $ 5,746 $ 7,457 $ 7,137
Interest cost 20,556 22,698 24,693
Return on plan assets (21,452) (9,330) (7,812)
Amortization of unrecognized
transition obligation 15,134 15,134 15,134
Other amortization, net 8,327 3,194 4,924
- ----------------------------------------------------------------------------
Net health care and life
insurance cost $ 28,311 $ 39,153 $ 44,076
============================================================================
For calculating SFAS 106 benefit costs, the following assumptions were used:
- -----------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------------------
Discount rate 7.75% 7.50% 8.00%
Long-term rate of return --
Health assets, net of tax 6.00 5.25 5.00
Life assets 9.25 8.75 8.50
=============================================================================
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- -----------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------
(Thousands of Dollars) 1997 1996
- -----------------------------------------------------------------------------
Accumulated postretirement benefit obligation of:
Retirees $(214,624) $(226,774)
Fully eligible active
employees (529) (323)
Active employees
not eligible to retire (70,806) (78,985)
- ----------------------------------------------------------------------------
Total accumulated postretirement
benefit obligation (285,959) (306,082)
Market value of plan assets 129,434 105,086
- ----------------------------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets (156,525) (200,996)
Unrecognized transition
obligation 227,015 242,149
Unrecognized net gain (70,391) (41,457)
- ----------------------------------------------------------------------------
Prepaid/(accrued) postretirement
benefit obligation $ 99 $ (304)
============================================================================
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- -----------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------
1997 1996
- ----------------------------------------------------------------------------
Discount rate 7.25% 7.75%
Health care cost trend rate (a) 5.76 7.23
=============================================================================
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 4.40 percent by 2001.
The effect of increasing the assumed health care cost trend rate by one
percentage point in each year would increase the accumulated postretirement
benefit obligation as of December 31, 1997, by $16.1 million and the aggregate
of the service and interest cost components of net periodic postretirement
benefit cost for the year then ended by $1.3 million. The trust holding the
health plan assets is subject to federal income taxes at a 39.6 percent tax
rate.
CL&P, PSNH and WMECO currently are recovering SFAS 106 costs through rates.
C. 401(k) Savings Plan
NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
The company matches, with company stock, employee contributions up to a maximum
of three percent of eligible compensation. The matching contributions made by
the company were $12.0 million for 1997, $11.8 million for 1996 and $12.1
million for 1995.
D. ESOP
NU maintains an ESOP for purposes of allocating shares to employees
participating in the NU system's 401(k) plan. Under this arrangement, NU issued
unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of
which were lent to the ESOP trust for purchase of approximately 10.8 million
newly issued NU common shares (ESOP shares). NU makes principal and interest
payments on the ESOP notes at the same rate that ESOP shares are allocated to
employees.
In 1997 and 1996, the ESOP trust issued approximately 948,000 and 953,000 of NU
common shares, respectively, to satisfy plan obligations to employees totaling
approximately $21.9 million and $22.1 million, respectively. These costs were
charged to the 401(k) plan. As of December 31, 1997 and 1996, the total
allocated ESOP shares were 4,140,751 and 3,192,620, respectively, and total
unallocated ESOP shares were 6,659,434 and 7,607,565, respectively. The fair
market value of unallocated ESOP shares as of December 31, 1997 and 1996 was
approximately $78.7 million and $99.8 million, respectively.
During 1997, the ESOP trust used approximately $3 million in dividends and $41
million in contributions from NU to meet principal and interest payments on ESOP
notes. During March 1997, NU's Board of Trustees suspended the quarterly
dividend on NU's common shares indefinitely, beginning with the second quarter
of 1997. Future principal and interest payments on ESOP notes will be fully
supported by contributions from NU until the dividend is restored.
E. Stock-Based Compensation
During 1997, certain key officers of the company were awarded nonvested stock
grants, totaling 25,700 shares, under which the officers pay nothing to receive
these shares. These officers must stay in employment of the company for a
specified period to receive the shares. During 1996, the same key officers of
the company were awarded nonvested stock grants, for a total of approximately
43,000 shares, for which again no payment was required. Under the 1996 programs,
certain shares became vested immediately with certain restrictions and others
became vested upon the meeting of specified performance goals within a limited
time period. Dividends accruing on the shares of each award are reinvested in
additional shares subject to the same provisions and restrictions. Under
these programs, approximately 3,400 shares were vested at December 31, 1997, and
December 31, 1996.
During August 1997, the company's Board of Trustees approved the granting of
500,000 stock options to the new Chief Executive Officer to purchase common
shares of NU common stock. The exercise price of these options is $9.625 per
share, which equaled the fair value of the company's common stock at the date of
grant. The exercise period for the options granted is ten years from the date of
grant, with vesting from the date of grant as follows: 50 percent after two
years, 75 percent after three years and 100 percent after four years.
The company accounts for its nonvested stock grants and stock options using the
intrinsic-value based method in accordance with Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," (APB 25) under which
approximately $238 thousand and $136 thousand of compensation costs were
recognized in 1997 and 1996, respectively, for the nonvested stock grants. No
compensation costs have been recognized for the stock options award as the
exercise price was equal to the market value of the stock on the date of grant.
In October 1995 the FASB issued SFAS 123, "Accounting for Stock-Based
Compensation," which defines a fair-value based method of accounting for stock-
based compensation. SFAS 123 allows companies to continue accounting for stock-
based compensation using APB 25 but requires pro forma net income and earnings
per share disclosures as if the fair-value based method of accounting under SFAS
123 had been used.
Had compensation costs of the options award been determined under the fair value
alternative method as stated in SFAS 123, the company's pro forma net loss for
the year ended December 31, 1997, would have been increased by approximately $73
thousand. The resulting pro forma impact on the company's loss per share for the
year was not material. The fair value of the options as of the date of grant was
determined using the Black-Scholes option pricing model with the following
assumptions: risk-free interest rate of 6.41 percent, expected life of 10.0
years, expected volatility of 31.89 percent and a dividend yield of 7.42
percent.
7. Sale of Customer Receivables and Accrued Utility Revenues
During 1996, CL&P and WMECO entered into agreements to sell up to $200 million
and $40 million, respectively, of undivided ownership interests in eligible
customer receivables and accrued utility revenues (receivables).
The FASB issued SFAS 125, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities," in June 1996. SFAS 125 became
effective on January 1, 1997, and establishes, in part, criteria for concluding
whether a transfer of financial assets in exchange for consideration should be
accounted for as a sale or as a secured borrowing. By October 31, 1997, both
CL&P and WMECO had restructured their respective sales agreements to comply with
the conditions of SFAS 125 and account for transactions occurring under these
programs as sales of assets. CL&P and WMECO have each established a special
purpose, wholly owned subsidiary whose business consists of the purchase and
resale of receivables. For receivables sold, both CL&P and WMECO have retained
collection responsibilities as agent for the purchaser under each company's
respective agreements. As collections reduce previously sold receivables, new
receivables may be sold. At December 31, 1997, approximately $70 million and $20
million of receivables had been sold to third-party purchasers by CL&P and
WMECO, respectively, through the use of each company's special purpose, wholly
owned subsidiary, CL&P Receivables Corporation (CRC) and WMECO Receivables
Corporation (WRC). All receivables transferred to both CRC and WRC are assets
owned by CRC and WRC and are not available to pay CL&P's or WMECO's creditors.
For CRC's and WRC's respective sales agreements with the third-party purchasers,
the receivables were sold with limited recourse. Both CRC's and WRC's respective
sales agreements provide for a formula-based loss reserve in which additional
receivables may be assigned to the third-party purchasers for costs such
as bad debt. The third-party purchasers absorb the excess amount in the event
that actual loss experience exceeds the loss reserve. At December 31, 1997,
approximately $7.2 million and $3.0 million of assets had been designated as
collateral by CRC and WRC, respectively. These amounts represent the formula-
based amount of credit exposure at December 31, 1997. Historical losses for bad
debt for both CL&P and WMECO have been substantially less.
During December 1997, Moody's Investors Service downgraded the rating on WMECO's
first mortgage bonds. This downgrade brought WMECO's bond ratings to a level at
which the sponsor of WMECO's accounts receivable program can take various
actions, in its discretion, which would have the practical effect of limiting
WMECO's ability to utilize the facility. To date, the sponsor has not notified
WMECO that it will elect to exercise those rights, and the program is
functioning in its normal mode. The WMECO accounts receivable program could be
terminated if WMECO's first mortgage bond credit ratings experience one more
level of downgrade. CL&P's accounts receivable program could be terminated if
its senior secured debt is downgraded two more steps from its current ratings.
Concentrations of credit risk to the respective purchasers under each company's
agreements with respect to the receivables are limited due to CL&P's and WMECO's
diverse customer base within their respective service territories.
For additional information on accounts receivable programs and CL&P's and
WMECO's ability to utilize these programs, see the MD&A.
8. Commitments and Contingencies
A. Restructuring and Rate Matters
New Hampshire: The 1996 restructuring legislation that the NHPUC is charged with
implementing provides that the NHPUC may not adopt a restructuring plan that
imposes a severe financial hardship on a utility. Management believes that
PSNH is entitled to full recovery of its prudently incurred costs, including
regulatory assets and other strandable costs. It bases this belief both on the
general nature of public utility industry cost-of-service based regulation and
the specific circumstances of the resolution of PSNH's previous bankruptcy
proceedings and its acquisition by NU, including the recoveries provided by the
Rate Agreement and related agreements.
On February 28, 1997, the NHPUC issued its decision related to restructuring the
state's electric utility industry and setting interim stranded cost charges for
PSNH pursuant to legislation enacted in New Hampshire in 1996. In the decision,
the NHPUC announced a departure from cost-based ratemaking and instead adopted a
market-priced approach to ratemaking and stranded cost recovery. Accordingly,
unless the NHPUC modifies its position or the litigation described below results
in necessary modifications to the final plan which leads management to conclude
that the ratemaking approach utilized in the NHPUC's restructuring decision will
not go into effect, PSNH no longer will be subject to the provisions of SFAS 71.
That would result in PSNH writing off from its balance sheet substantially all
of its regulatory assets. The amount of the potential write-off triggered by the
order is currently estimated at over $400 million, after taxes. PSNH does not
believe that under the decision, it would be required to recognize any
additional loss resulting from the impairment of the value of its other long-
lived assets under the provisions of SFAS 121.
On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary restraining
order, preliminary and permanent injunctive relief and for declaratory judgment
in the United States District Court for New Hampshire (District Court). The case
was subsequently transferred to Rhode Island. On March 10, 1997, the Chief
Judge of the Rhode Island federal court issued a temporary restraining order
which stayed the NHPUC's February 28, 1997, decision to the extent it
established a rate-setting methodology that is not designed to recover PSNH's
costs of providing service and would require PSNH to write off any regulatory
assets.
During 1997, a mediation process ended without a resolution. The District Court
had suspended the procedural schedule associated with this court proceeding
pending the resolution of appeals of certain preliminary rulings by the U.S.
Circuit Court of Appeals for the First Circuit (First Circuit). On February 3,
1998, the First Circuit denied the appeals taken by would-be intervenors in
PSNH's federal court proceeding concerning the NHPUC's final plan on
restructuring. The First Circuit affirmed a previous court decision stating that
the opposing interests in this case were adequately represented by the NHPUC or
by PSNH. As a result of this decision, the proceedings in the District Court may
resume. On February 17, 1998, the NHPUC filed a petition for rehearing with the
First Circuit. The temporary restraining order issued by the District Court in
March 1997 will remain in effect until further orders by either court.
During 1997, the NHPUC reopened its proceeding to reconsider certain limited
matters in its restructuring orders. The scope of the PSNH-specific rehearing
proceedings included alternative rate-setting methodologies proposed by the
intervenors; to decide the appropriate methodology to be used to determine
PSNH's interim stranded costs; and to set PSNH's interim stranded cost charges
utilizing the determined methodology. In testimony filed with the NHPUC in
November 1997, PSNH proposed a new methodology to quantify its strandable costs.
Under this proposal, PSNH would divest all owned generation and purchased-power
obligations via auction. To the extent that the auction fails to produce
sufficient revenues to cover the net book value of owned generation and
contractual payment obligations of purchased power, the difference would be
recovered from customers through a non-bypassable distribution charge. The new
proposal also relies upon securitization of certain assets to further reduce
rates.
On December 15, 1997, the NHPUC officially announced that industry restructuring
would not take place on January 1, 1998. Management believes that industry
restructuring will not take place in New Hampshire until the courts resolve
the issues brought before them, or the parties involved reach a settlement.
PSNH and NAEC are parties to a variety of financing agreements providing that
the credit thereunder can be terminated or accelerated if they do not maintain
specified minimum ratios of common equity to capitalization (as defined in each
agreement). In addition, PSNH and NAEC are parties to a variety of financing
agreements providing in effect that the credit thereunder can be terminated or
accelerated if there are actions taken, either by PSNH or NAEC or by the state
of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the Rate
Agreement and/or the Seabrook Power Contracts.
If the NHPUC's February 28, 1997 decision were to become effective, it would,
unless PSNH and NAEC receive waivers from their respective lenders, result in
(i) write-offs that would cause PSNH's common equity to fall below the
contractual minimums, (ii) reductions in income that would cause PSNH's income
to fall below the contractual minimums, (iii) potential violation of the
contractual provisions with respect to actions depriving PSNH and NAEC of the
benefits of the Rate Agreement and (iv) the potential for cross defaults to
other PSNH and NAEC financing documents. Substantially all of PSNH's and NAEC's
debt obligations would be affected.
If these events transpired and if the creditors holding PSNH and NAEC debt
obligations decide to exercise their rights to demand payment, then either
creditors or PSNH and NAEC could initiate proceedings under Chapter 11 of the
bankruptcy laws.
As a result of the NHPUC decision and the potential consequences discussed
above, the reports of our auditors on the individual financial statements of
PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs
indicate that a substantial doubt exists currently about the ability of PSNH and
NAEC to continue as going concerns. The accounts of PSNH and NAEC are included
in the accompanying consolidated financial statements on the basis of a
going concern. While the effect of the implementation of that decision would
have a material adverse impact on NU's financial position, results of operations
and cash flows, it would not in and of itself result in defaults under borrowing
or other financial agreements of NU or its other subsidiaries.
On May 2, 1997, PSNH made a rate filing with the NHPUC. For information
regarding this rate proceeding, see the MD&A.
Massachusetts: During November 1997, the state of Massachusetts enacted a
comprehensive electric utility industry restructuring bill (legislation). On
December 31, 1997, WMECO filed its restructuring plan with the DTE, as required
by the legislation. The WMECO restructuring plan describes the process by which
WMECO will, beginning March 1, 1998, initiate a ten percent rate reduction for
all customer rate classes and allow customers to choose their energy supplier.
As part of the plan, the DTE authorized recovery of certain strandable, above-
market costs (strandable costs). The legislation gives the DTE the authority to
determine the amount of strandable costs that will be eligible for recovery by
utilities. Costs which will qualify as strandable costs and be eligible for
recovery include, but are not limited to, certain above-market costs associated
with generating facilities, costs associated with long-term commitments to
purchase power at above-market prices from small power producers and nonutility
generators, and regulatory assets and associated liabilities related to the
generation portion of WMECO's business.
Under the statute, if a distribution company claims that it is unable to meet a
price reduction of ten percent initially and 15 percent by September 1, 1999,
the distribution company may so state to the DTE and the DTE is provided with
the authority to "explore all possible mechanisms and options within the limits
of the constitution" to achieve the mandated rate reductions. The statute
indicates that allowing a substitute company to provide standard offer service
is one option that can be considered by the DTE.
The costs of transitioning to competition will be mitigated through several
steps, including divesting WMECO's nonnuclear generating assets at an auction to
be held as soon as June 1998, and securitization of approximately $500 million
in strandable costs by September 30, 1998. NU presently expects to participate,
through a competitive affiliate, in the competitive bid process for WMECO's
generation resources. Any net proceeds in excess of book value received from the
divestiture of these units will be used to mitigate strandable costs. As
required by the legislation, WMECO will continue to operate and maintain its
transmission and local distribution network and deliver electricity to all
customers.
As noted above, the legislation has authorized Massachusetts utilities to
finance a portion of the strandable costs through securitization, using rate
reduction bonds. A separate transition charge will be collected over the life of
the bonds to recover principal, interest and issuance costs.
WMECO's ability to recover its strandable costs will depend on several factors,
which include, but are not limited to, continuous recovery of the costs over the
transitional period supported by the legislation, the aggregate amount of
strandable costs which the company will be allowed to recover and the market
price of electricity. Management believes that the company will recover its
strandable costs. However, a change in one or more of these factors could affect
the recovery of strandable costs and may result in a loss to the company.
Connecticut: Although CL&P continues to operate under cost-of-service based
regulation, legislative restructuring initiatives during 1997 and 1998 in its
jurisdiction has created some uncertainty with respect to future rates and the
recovery of strandable investments and certain future costs such as purchase
power obligations. Management is unable to predict the ultimate outcome of
restructuring initiatives, however, it continues to believe that it is probable
that CL&P will fully recover its prudently incurred costs, including regulatory
assets and strandable investments based on the general nature of public utility
cost-of-service regulation.
For further information on restructuring, see Note 2H, "Summary of Significant
Accounting Policies -- Regulatory Accounting and Assets" and the MD&A.
The DPUC is required to review a utility's rates every four years if there has
not been a rate proceeding during such period. The DPUC has conducted such a
review. For information regarding this review and other rate matters, see the
MD&A.
FERC Rate Proceedings: For information regarding the FERC rate proceedings for
CYAPC and MYAPC, see Note 3, "Nuclear Decommissioning."
B. Nuclear Performance
Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2 and 3
have been out of service since November 4, 1995, February 21, 1996, and March
30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC)
watch list. The company has restructured its nuclear organization and is
currently implementing comprehensive plans to restart the units.
Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC stated that the units cannot return to service until
independent, third-party verification teams have reviewed the actions taken to
improve the design, configuration and employee concerns issues that prompted the
NRC to place the units on its watch list. The actual date of the return to
service for each of the units is dependent upon the completion of independent
inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes
to return Millstone 3 to service in early spring of 1998 and Millstone 2 three
to four months after Millstone 3. Millstone 1 is currently in extended
maintenance status.
Management cannot predict when the NRC will allow any of the Millstone units to
return to service and thus cannot precisely estimate the total replacement power
costs the companies ultimately will incur. Replacement power costs incurred by
NU attributable to the Millstone outages averaged approximately $28 million per
month during 1997, and for 1998 are projected to average approximately $9
million per month for Millstone 3, $9 million per month for Millstone 2 and $6
million per month for Millstone 1 while the plants remain out of service. CL&P,
WMECO and PSNH will continue to expense their replacement power costs in 1998.
Based on the current estimates of expenditures and restart dates, management
believes the NU system has sufficient resources to fund the restoration of the
Millstone units and related replacement power costs. If the return to service of
Millstone 3 or 2 is delayed substantially beyond the present restart estimates,
if some financing facilities become unavailable because of difficulties in
meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO
encounter additional significant costs or if any other significant deviations
from management's assumptions occur, CL&P and WMECO could be unable to meet
their cash requirements. In those circumstances, management would take even more
stringent actions to reduce costs and cash outflows and attempt to obtain
additional sources of funds. The availability of these funds would be dependent
upon general market conditions and CL&P's and WMECO's respective credit and
financial conditions at that time.
For information regarding Millstone restart costs, see the MD&A.
For information concerning the ability of CL&P and WMECO to access their
borrowing facilities, see the MD&A.
Litigation: Several class-action lawsuits have been filed against the company
and certain present and former officers and employees of NU in connection with
the company's nuclear operations. Management cannot estimate the
potential outcome of these suits, but believes these suits are without merit and
intends to defend itself vigorously in all these actions.
CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without
profit, under a sharing agreement that obligates them to utilize good utility
operating practice and requires the joint owners to share the risk of employee
negligence and other risks of operation and maintenance pro-rata in accordance
with their ownership shares. This agreement also provides that CL&P and WMECO
would be liable only for damages to the non-NU owners for a deliberate violation
of the agreement pursuant to authorized corporate action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior
Court against NU and its current and former trustees. The non-NU owners raise a
number of contract, tort and statutory claims arising out of the operation of
Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages,
punitive damages, treble damages and attorneys' fees. Owners representing
approximately two-thirds of the non-NU interests in Millstone 3 claimed
compensatory damages in excess of $200 million. In addition, one of the lawsuits
seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP,
pending the outcome of the lawsuit. Management cannot estimate the potential
outcome of these suits but believes there is no legal basis for the claims and
intends to defend against them vigorously. To date, no reserves have been
established for this litigation. At December 31, 1997, the costs related to this
litigation were estimated to be approximately $100 million for incremental O&M
costs and approximately $100 million for replacement power costs. These costs
are likely to increase as long as Millstone 3 remains out of service.
The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P have been
negotiating since May 1996 over issues related to the operation of Millstone 1
and 2. CMEEC has failed to make payments on its accrued obligations since
October 1996, claiming that CL&P materially breached its contractual
obligations. CL&P has denied the allegations and requested payment. The matter
has gone to arbitration which has been scheduled for July 1998.
CL&P has filed an application with the Connecticut Superior Court in Hartford
requesting the court to grant interim relief to CL&P. CL&P has asked the court
to enforce the contract provisions by ordering CMEEC to pay the outstanding
obligations under the contract (approximately $25 million) and to continue
making payments (approximately $1.8 million per month) during the arbitration
process.
On December 9, 1997, the Superior Court judge issued a decision denying CL&P's
request for an interim payment order. Management cannot predict the outcome of
this litigation and has taken steps to assert its legal rights. CL&P has
requested reargument, in order to present evidence, and has requested that the
Connecticut Superior Court vacate its order. CL&P is prepared to appeal to a
higher court, if necessary, after the reargument.
C. Environmental Matters
The NU system is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of toxic
substances and hazardous and solid wastes, and the handling and use of chemical
products. The NU system has an active environmental auditing and training
program and believes that it is in substantial compliance with current
environmental laws and regulations. However, the NU system is subject to certain
pending enforcement actions and governmental investigations in the environmental
area. Management cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new generating
units, transmission and distribution lines, substations and other facilities.
Changing environmental requirements could also require extensive and costly
modifications to the NU system's existing generating units and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the NU system may incur significant additional environmental costs,
greater than amounts included in cost of removal and other reserves, in
connection with the generation and transmission of electricity and the storage,
transportation and disposal of byproducts and wastes. The NU system also may
encounter significantly increased costs to remedy the environmental effects of
prior waste handling activities. The cumulative long-term cost impact of
increasingly stringent environmental requirements cannot be estimated
accurately.
The NU system has recorded a liability based upon currently available
information for what it believes are its estimated environmental remediation
costs that the NU system's subsidiaries expect to incur for waste disposal
sites. In most cases, additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown magnitude
of possible contamination, the appropriate remediation methods, the possible
effects of future legislation or regulation and the possible effects of
technological changes. At December 31, 1997, the net liability recorded by the
NU system for its estimated environmental remediation costs, excluding any
possible insurance recoveries or recoveries from third parties, amounted to
approximately $16.2 million, which management has determined to be the most
probable amount within the range of $16.2 million to $28.0 million.
During 1997, NU adopted Statement of Position 96-1, "Environmental Remediation
Liabilities" (SOP). The principal objective of the SOP is to improve the manner
in which existing authoritative accounting literature is applied by entities to
specific situations of recognizing, measuring and disclosing environmental
remediation liabilities. The adoption of the SOP resulted in an increase of
approximately $1.5 million to NU's environmental reserve in 1997.
The NU system cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against it.
However, considering known facts, existing laws and regulatory practices,
management does not believe the matters disclosed above will have a material
effect on the NU system's financial position or future results of operations.
D. Nuclear Insurance Contingencies
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities in the country covered by the federal government's third-
party liability indemnification program, an owner of a nuclear unit could be
assessed in proportion to its ownership interest in each of its nuclear units up
to $75.5 million. Payments of this assessment would be limited to $10.0 million
in any one year per nuclear incident based upon the owner's pro rata ownership
interest in each of its nuclear units. In addition, the owner would be subject
to an additional five percent or $3.8 million, in proportion to its ownership
interests in each of its nuclear units, if the sum of all claims and costs from
any one nuclear incident exceeds the maximum amount of financial protection.
Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1,
the NU system's maximum liability, including any additional assessments, would
be $244.2 million per incident, of which payments would be limited to $30.8
million per year. In addition, through power purchase contracts with MYAPC,
VYNPC and CYAPC, the NU system would be responsible for up to an additional
$67.4 million per incident, of which payments would be limited to $8.5 million
per year.
Insurance has been purchased to cover the primary cost of repair, replacement or
decontamination of utility property resulting from insured occurrences. The NU
system is subject to retroactive assessments if losses exceed the accumulated
funds available to the insurer. The maximum potential assessment against the
system with respect to losses arising during the current policy year is
approximately $17.1 million under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred in obtaining
replacement power during prolonged accidental outages and the excess cost of
repair, replacement or decontamination or premature decommissioning of utility
property resulting from insured occurrences. The NU system is subject to
retroactive assessments if losses exceed the accumulated funds available to the
insurer. The maximum potential assessments against the NU system with respect to
losses arising during current policy years are approximately $13.8 million under
the replacement power policies and $24.6 million under the excess property
damage, decontamination and decommissioning policies. The cost of a nuclear
incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry basis for
coverage of worker claims. All participating reactor operators insured under
this coverage are subject to retrospective assessments of $3 million per
reactor. The maximum potential assessment against the NU system with respect to
losses arising during the current policy period is approximately $13.0 million.
Effective January 1, 1998, a new worker policy was purchased which is not
subject to retrospective assessments.
E. Construction Program
The construction program is subject to periodic review and revision by
management. The NU system companies currently forecast construction expenditures
of approximately $2.0 billion for the years 1998-2002, including $267 million
for 1998. In addition, the NU system companies estimate that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $360.7 million for the years 1998-2002, including $60.6 million
for 1998. See Note 5, "Leases," for additional information about the financing
of nuclear fuel.
F. Long-Term Contractual Arrangements
Yankee Companies: The NU system companies rely on VY for approximately 1.7
percent of their capacity under long-term contracts. Under the terms of their
agreements, the NU system companies pay their ownership (or entitlement) shares
of costs, which include depreciation, O&M expenses, taxes, the estimated cost of
decommissioning and a return on invested capital. These costs are recorded as
purchased power expense and are recovered through the companies' rates. The
total cost of purchases under contracts with VYNPC amounted to $24.2 million in
1997, $25.5 million in 1996 and $25.3 million in 1995.
The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently
shut down as of August 6, 1997, December 4, 1996, and February 26, 1992,
respectively. See Note 1E, "Summary of Significant Accounting Policies --
Investments and Jointly Owned Electric Utility Plant," for further information
on the Yankee companies, and Note 3, "Nuclear Decommissioning," regarding the
related decommissioning obligations.
Nonutility Generators: CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from nonutiltiy generators
(NUGs). These arrangements have terms from 10 to 30 years, currently expiring in
the years 1998 through 2028, and require the companies to purchase energy at
specified prices or formula rates. For the twelve month period ending December
31, 1997, approximately 14 percent of NU system electricity requirements was met
by NUGs. The total cost of purchases under these arrangements amounted to $447.6
million in 1997, $441.6 million in 1996 and $434.7 million in 1995. These costs
may be deferred for eventual recovery through rates.
New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement to
purchase the capacity and energy of the New Hampshire Electric Cooperative,
Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for
a ten-year period, which began on July 1, 1990. The total cost of purchases
under this agreement was $23.4 million in 1997, $14.6 million in 1996 and $15.8
million in 1995. The total cost of these purchases has been collected
through the FPPAC in accordance with the Rate Agreement. In connection with the
agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for
15 years.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and HWP
have entered into agreements to support transmission and terminal facilities to
import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO and
HWP are obligated to pay, over a 30-year period ending in 2020, their
proportionate shares of the annual O&M and capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements are as follows:
- -----------------------------------------------------------------------------
(Millions of Dollars) 1998 1999 2000 2001 2002
- -----------------------------------------------------------------------------
VYNPC $ 28.7 $ 28.9 $ 27.7 $ 30.3 $ 31.5
NUGs 455.5 471.1 477.5 488.5 498.9
NHEC 30.0 30.0 14.6 -- --
Hydro-Quebec 32.6 31.6 30.9 30.0 29.3
=============================================================================
For additional information regarding the recovery of purchased power costs, see
Note 2K, "Summary of Significant Accounting Policies -- Recoverable Energy
Costs."
G. Sale of COE
During 1997, the NU Board of Trustees approved the offering for sale of COE.
COE's revenues and earnings historically have not been material to NU. During
the fourth quarter of 1997, management established a reserve of $25 million to
reflect the anticipated loss from the sale of a COE investment. NU had a net
investment in COE of approximately $33.4 million and $57.2 million, as of
December 31, 1997 and 1996, respectively.
9. Market Risk Management
Fuel Price Management: CL&P uses swap, collar, put and call instruments with
financial institutions to hedge against some of the fuel price risk created by
long-term negotiated energy contracts and nuclear replacement power generation
and fuel purchases. These agreements minimize exposure associated with rising
fuel prices by managing a portion of CL&P's cost of fuel for these negotiated
energy contracts and nuclear replacement power generation and fuel purchases. As
of December 31, 1997, CL&P had outstanding agreements with a total notional
value of approximately $327 million, and a negative mark-to-market position of
approximately $21 million.
The terms of the agreements require CL&P to post cash collateral with its
counterparties in the event of negative mark-to-market positions and lowered
credit ratings. The amount of the collateral is to be returned to CL&P when the
mark-to-market position becomes positive, when CL&P meets specified credit
ratings or when an agreement ends and all open positions are properly settled.
At December 31, 1997, cash collateral in the amount of $15.4 million was posted
under these terms.
Interest Rate Management: NAEC uses swap instruments with financial institutions
to hedge against interest rate risk associated with its $200 million variable-
rate bank note. The interest-rate management instruments employed eliminate the
exposure associated with rising interest rates, and effectively fix the interest
rate for this borrowing arrangement. Under the agreements, NAEC exchanges
quarterly payments based on a differential between a fixed contractual interest
rate and the three-month LIBOR rate at a given time. As of December 31, 1997,
NAEC had outstanding agreements with a total notional value of $200 million and
a positive mark-to-market position of approximately $104 thousand.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
Each respective company will be exposed to credit risk on their respective
market risk-management instruments if the counterparties fail to perform their
obligations. However, management anticipates that the counterparties will be
able to fully satisfy their obligations under the agreements.
10. Minority Interest in Consolidated Subsidiary
CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million
capital contribution, back to CL&P in the form of an unsecured debenture. CL&P
consolidates CL&P LP for financial reporting purposes. Upon consolidation, the
unsecured debenture is eliminated, and the MIPS securities are accounted for as
minority interests.
11. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate fair
value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities,"
requires investments in debt and equity securities to be presented at fair
value. As a result of this requirement, the investments held in the NU system
companies' nuclear decommissioning trusts were adjusted to market by
approximately $69.6 million as of December 31, 1997, and $31.4 million as of
December 31, 1996, with corresponding offsets to the accumulated provision for
depreciation. The amounts adjusted in 1997 and in 1996 represent cumulative
gross unrealized holding gains. The cumulative gross unrealized holding losses
were immaterial for both 1997 and 1996.
Preferred stock and long-term debt: The fair value of the system's fixed-rate
securities is based upon the quoted market price for those issues or similar
issues. Adjustable rate securities are assumed to have a fair value equal to
their carrying value. The carrying amounts of the system's financial instruments
and the estimated fair values are as follows:
- ---------------------------------------------------------------------------
At December 31, 1997
- ---------------------------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- ---------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 136,200 $ 79,141
Preferred stock subject to
mandatory redemption 276,000 255,180
Long-term debt --
First Mortgage Bonds 2,228,800 2,210,423
Other long-term debt 1,668,533 1,691,362
MIPS 100,000 100,760
===========================================================================
- ---------------------------------------------------------------------------
At December 31, 1996
- ---------------------------------------------------------------------------
Carrying Fair
Thousands of Dollars) Amount Value
- ---------------------------------------------------------------------------
Preferred stock not subject to
mandatory redemption $ 136,200 $ 127,045
Preferred stock subject to
mandatory redemption 301,000 264,304
Long-term debt --
First Mortgage Bonds 2,196,788 2,163,031
Other long-term debt 1,718,859 1,741,818
MIPS 100,000 108,520
==========================================================================
The fair values shown above have been reported to meet disclosure requirements
and do not purport to represent the amounts at which those obligations would be
settled.
Management's Discussion and Analysis
Financial Condition
Overview
The length of the ongoing outages at the three Millstone nuclear plants
(Millstone) and the high costs of the recovery efforts weakened NU's 1997
earnings, balance sheet and cash flows and will continue to have an adverse
impact on NU's financial condition until the units are returned to service.
NU's earnings fell sharply in 1997 for the second consecutive year, primarily as
a result of costs associated with the ongoing Millstone outages. NU lost
$1.01 per common share in 1997, compared with a profit of $0.30 per common share
in 1996 and $2.24 a share in 1995.
The poorer financial results in 1997 were due primarily to the fact that all
three Millstone units were off line for the entire year in 1997 and spending
associated with the recovery efforts was significantly higher in 1997 than it
was in 1996. Millstone 3 operated for nearly three months in 1996 and Millstone
2 for nearly two months. As a result, the cost of replacing power ordinarily
generated by the Millstone units rose by approximately $80 million in 1997. The
total operation and maintenance (O&M) costs at Millstone were approximately $216
million higher in 1997.
The higher Millstone costs have caused the NU system, primarily The Connecticut
Light and Power Company (CL&P) and Western Massachusetts Electric Company
(WMECO), to focus closely on maintaining adequate liquidity and reducing
nonnuclear O&M costs. In 1997 and early 1998, CL&P and WMECO successfully sold
$260 million in first mortgage bonds and renegotiated more than $400 million of
bank credit lines. Additionally, nonnuclear O&M expenses in 1997 were reduced by
about $50 million from 1996.
The SEC has advised NU, CL&P, PSNH and WMECO to adjust for certain costs
associated with the ongoing Millstone outages as they are incurred. For the
past two years, NU, CL&P, PSNH and WMECO have been reserving for the unavoidable
costs they expected to incur to meet NRC requirements. These annual statements
have been adjusted in accordance with the SEC's directive. Management does not
expect implementation of this accounting change to affect the ability of CL&P
and WMECO to meet their financial covenants contained in their $313.75 million
revolving credit arrangement.
In 1998, management expects Millstone-related expenses to fall significantly,
assuming Millstone 3 and Millstone 2 are returned to service at dates close to
current estimates, although the O&M expenses at Millstone 3 and Millstone 2
will be considerably higher than before the station was placed on the Nuclear
Regulatory Commission's (NRC's) watch list. The actual level of 1998 nuclear
spending at Millstone will depend on when the units return to operation and the
cost of restoring them to service. The company hopes to restart Millstone 3,
the newest and largest unit at the site, in the early spring of 1998 and
Millstone 2 three to four months after Millstone 3. The company cannot restart
the Millstone units until it receives formal approval from the NRC. As part of
an effort to reduce spending in 1998, Millstone 1 has been placed in extended
maintenance status. Management will review its options with respect to
Millstone 1 in 1998, including restart, early retirement and other options.
Rate reductions in all three states served by NU's operating companies are
likely to offset a portion of the benefit of lower Millstone-related costs. On
December 1, 1997, Public Service Company of New Hampshire (PSNH) rates were
reduced 6.87 percent as a result of an interim rate order issued by the New
Hampshire Public Utilities Commission (NHPUC). On March 1, 1998, CL&P rates
were reduced by approximately 1.4 percent to reflect the removal of Millstone 1
from rates, and additional noncash reductions were made to revenue requirements
as a result of an interim rate order issued by the Connecticut Department of
Public Utility Control (DPUC). Also on March 1, 1998, WMECO reduced retail
rates by 10 percent in compliance with industry restructuring legislation passed
in November 1997 by the Massachusetts Legislature. Rate cases involving CL&P
and PSNH may result in additional rate adjustments later in 1998. CL&P's
revenues could be further reduced if substantial delays in restarting Millstone
3 and Millstone 2 result in a DPUC decision to remove those units from rates.
In addition to focusing on maintaining liquidity, management also must attend to
industry restructuring efforts throughout the NU system's service territory. A
temporary restraining order issued by a U.S. District Court is currently
blocking the NHPUC from implementing a February 1997 restructuring order that
would have resulted in a write-off by PSNH of more than $400 million.
Management hopes to negotiate an alternative restructuring proposal in
1998 that will produce significant PSNH rate reductions and allow retail
customers to choose their electric suppliers, but still give PSNH and North
Atlantic Energy Corporation (NAEC) an opportunity to maintain an adequate
financial condition and earn fair returns on their investments.
The 1997 Massachusetts legislation allowed full retail choice on March 1, 1998.
WMECO expects to recover fully its stranded costs through a combination of
securitization and divestiture of its nonnuclear generating assets.
In Connecticut, restructuring legislation is being considered in the legislative
session that began in February 1998.
Restructuring also is likely to cause other NU subsidiaries to auction their
nuclear and/or nonnuclear generating units. Despite these potential
requirements, management believes that it could be advantageous for the NU
system to remain in the generation business, which could be accomplished by
acquiring ownership interests in facilities inside and outside New England.
NU's earnings in 1997 also were affected by a $25 million reserve for
anticipated losses on the sale of investments by Charter Oak Energy, Inc., NU's
independent power development subsidiary.
Presently, NU is New England's largest electric utility system with 1.7 million
customers in Connecticut, New Hampshire and Massachusetts. In 1997, NU
experienced modest economic growth in its retail sales that was offset by the
effects of mild winter weather. In 1998, management expects that the regional
economy will continue to experience modest growth.
Millstone
Outages
The NU system has a 100 percent ownership interest in Millstone 1 and 2
and a 68 percent ownership interest in Millstone 3. Millstone 1, 2 and 3 have
been out of service since November 4, 1995, February 21, 1996, and March 30,
1996, respectively.
Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC stated that the units cannot return to service until
independent, third-party verification teams have reviewed the actions taken to
improve the design, configuration and employee concerns issues that prompted the
NRC to place the units on its watch list. The actual date of the return to
service for each of the units is dependent upon the completion of independent
inspections, reviews by the NRC and a vote by the NRC commissioners.
In January 1998, NU declared Millstone 3 physically ready for restart, which
meant that almost all of the restart-required physical work had been completed
in the plant. The NRC currently is conducting a series of inspections to
determine, among other things, whether the plant has effective leadership and
corrective action and employee concerns programs. The Independent Corrective
Action Verification Program, an NRC-ordered independent review of the plant's
design and licensing bases, is expected to be completed in March 1998.
In 1997, the NU system's share of nonfuel O&M costs expensed for Millstone
increased to approximately $556 million, compared to approximately $340 million
in 1996.
Replacement power costs attributable to the Millstone outages totaled
approximately $340 million in 1997 compared to $260 million expensed in 1996.
These costs for 1998 are forecasted to average approximately $9 million per
month for Millstone 3, $9 million per month for Millstone 2 and $6 million per
month for Millstone 1 while the plants are out of service.
CL&P, WMECO and PSNH have been, and will continue to be, expensing all of the
costs to restart the units including replacement power and nonfuel O&M
expenses. See "Connecticut Rate Matters" for issues related to the recovery of
Millstone 1 costs.
NU and its subsidiaries are involved in several class action lawsuits and other
litigation in connection with their nuclear operations. See the "Notes to
Consolidated Financial Statements," Note 8B, for further information on this
litigation.
Millstone 1
Management will review its options with respect to Millstone 1 during 1998. The
issues that management will consider in evaluating its options include the costs
to restart the unit, the economic benefits of the unit's continued operation and
certain Connecticut state law issues. In the CL&P four year rate review
proceeding (discussed in detail under "Rate Matters"), the DPUC noted that CL&P
may not be able to recover its remaining investment in Millstone 1 if the DPUC
were to determine that the unit had been prematurely shut down due to management
imprudence. Additionally, there is a Connecticut statute which may limit CL&P's
ability to collect decommissioning charges in the future if Millstone 1 were to
be prematurely retired.
CL&P's net unrecovered Millstone 1 plant cost and the unrecovered
decommissioning costs at December 31, 1997, were approximately $216 million and
$198 million, respectively.
Capacity
During 1996 and continuing into 1997, the NU system companies took measures to
improve their capacity position, including obtaining additional generating
capacity, improving the availability of NU's generating units and improving the
NU system's transmission capability. During 1997, NU spent approximately $58
million to ensure the availability of adequate generating capacity in
Connecticut and Massachusetts, of which $40 million was expensed. In 1998, NU
does not anticipate the need to take additional measures to ensure adequate
generating capacity.
Liquidity and Capital Resources
Cash provided from operations decreased approximately $438 million in 1997,
compared to 1996, primarily due to higher cash expenditures related to the
Millstone outages, and the pay down in 1997 of the 1996 year end accounts
payable balance. The 1996 year end accounts payable balance was relatively high
due to costs related to a severe December storm and costs associated with the
Millstone outages that had been incurred but not yet paid by the end of 1996.
Net cash used for financing activities decreased approximately $224 million,
primarily due to suspension of the NU common dividend early in 1997 and an
increase in short-term borrowings.
CL&P and WMECO established facilities in 1996 under which they may sell, from
time to time, up to $200 million and $40 million, respectively, of their
accounts receivable and accrued utility revenues. As of December 31, 1997, CL&P
and WMECO sold approximately $70 million and $20 million of receivables,
respectively, to third-party purchasers.
NU's, CL&P's and WMECO's three-year revolving credit agreement was amended in
May 1997 (the Credit Agreement). Under the Credit Agreement, CL&P and WMECO are
able to borrow up to approximately $225 million and $90 million, respectively,
subject to a total borrowing limit of $313.75 million for all three borrowers.
NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each
maintained a consolidated operating income to consolidated interest expense
ratio of at least 2.50 to 1 for two consecutive fiscal quarters. Currently, the
companies cannot meet this requirement. At December 31, 1997, CL&P and WMECO had
$35 million and $15 million outstanding, respectively, under the Credit
Agreement.
In February 1998, because of borrowing restrictions on NU in the Credit
Agreement, NU entered into a separate $25 million, 364-day revolving credit
facility with one bank.
Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has
any financing agreements containing cross defaults based on financial defaults
by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing
agreements containing cross defaults based on financial defaults by NU, CL&P or
WMECO. Nevertheless, it is possible that investors will take negative operating
results or regulatory developments at one company in the NU system into account
when evaluating other companies in the NU system. That could, as a practical
matter and despite the contractual and legal separations among the NU companies,
negatively affect each company's access to financial markets.
In December 1997 and January 1998, Moody's Investors Service (Moody's) and
Standard & Poor's (S&P), respectively, downgraded the senior secured debt of
CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was
the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since
the Millstone units went on the NRC watch list in 1996. All of the NU system's
securities are rated below investment grade and remain under review for further
downgrade. Although CL&P and WMECO do not have any plans to issue debt in the
near term, rating agency downgrades generally increase the future cost of
borrowing funds because lenders will want to be compensated for increased risk.
Additionally, this could affect the terms and ability of the NU system companies
to extend existing agreements.
The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in December 1997
brought those ratings to a level at which the sponsor of WMECO's accounts
receivable program can take various actions, in its discretion, which would have
the practical effect of limiting WMECO's ability to utilize the facility. The
WMECO accounts receivable program could be terminated if WMECO's first mortgage
bond credit ratings experience one more level of downgrade. CL&P's accounts
receivables program could be terminated if its senior secured debt is downgraded
two more steps from its current ratings.
The NU system companies' ability to borrow under their financing arrangements is
dependent on their satisfaction of contractual borrowing conditions. The
financial covenants that must be satisfied to permit CL&P and WMECO to borrow
under the Credit Agreement are particularly restrictive and become more
restrictive throughout 1998. Spending levels in 1998, particularly for the
first half of the year while the Millstone units are expected to be out of
service, will be constrained to levels intended to assure that the financial
covenants in CL&P's and WMECO's Credit Agreement are satisfied. However, there
is no assurance that these financial covenants will be met as the system may
encounter additional unexpected costs from such areas as storms, reduced
revenues from regulatory actions or the effect of weather on sales levels.
If the return to service of Millstone 3 or Millstone 2 is delayed substantially
beyond the present restart estimates, if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions or
renegotiating extensions, if the system encounters additional significant costs,
or any other significant deviations from management's current assumptions, the
currently available borrowing facilities could be insufficient to meet all of
the NU system's cash requirements. In those circumstances, management would take
even more stringent actions to reduce costs and cash outflows and would attempt
to take other actions to obtain additional sources of funds. The availability
of these funds would be dependent upon the general market conditions and the NU
system's credit and financial condition at that time.
Restructuring
The NU system companies continue to operate under cost-of-service based
regulation, however, future rates and the recovery of strandable costs are
issues under various restructuring initiatives in each of the NU system
companies' service territories. Strandable costs are expenditures or commitments
that have been made to meet public service obligations with the expectation that
they would be recovered from customers in the future. The NU system companies
have exposure to strandable costs for their investments in high-cost nuclear
generating plants, state-mandated purchased power obligations and significant
regulatory assets. The NU system companies' exposure to strandable investments
and purchased power obligations exceeds their shareholder's equity. The NU
system's financial strength and resulting ability to compete in a restructured
environment will be negatively affected if the NU system companies are unable to
recover their past investments and commitments. Even if the NU system companies
are given the opportunity to recover a large portion of their strandable costs,
earnings prospects in a restructured environment will be affected in ways which
cannot be estimated at this time.
The NU system companies are seeking to mitigate the impacts of restructuring by
proposing stable, lower rates while pursuing customer choice options and full
recovery of their strandable costs. The NU system companies' strategy to
recover strandable costs includes efforts to promote state legislation that will
authorize the issuance of rate reduction bonds that would refinance these
investments and which would be repaid through non-bypassable charges to
customers. Management is unable to predict the ultimate outcome of these
initiatives which will be subject to regulatory and legislative approvals.
Management believes it is entitled to full recovery of its prudently incurred
costs, including regulatory assets and other strandable costs. See the "Notes to
Consolidated Financial Statements," Note 8A, for the potential accounting
impacts of restructuring.
New Hampshire
In February 1997, the NHPUC issued orders to restructure the state's electric
utility industry and set interim stranded cost charges for PSNH. In the
orders, the NHPUC announced a departure from cost-based ratemaking and adopted a
market-priced approach to stranded cost recovery. PSNH, NU, NAEC, and Northeast
Utilities Service Company (NUSCO) filed for a temporary restraining order,
preliminary and permanent injunctive relief and a declaratory judgment in the
United States District Court of New Hampshire. The case subsequently was
transferred to the United States District Court of Rhode Island (District Court)
where a temporary restraining order was granted, staying, indefinitely, the
enforcement of the NHPUC's restructuring orders as they affected PSNH. Certain
appeals to the preliminary ruling have been denied and proceedings in the
District Court are expected to resume.
The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate
methodology to be used to determine PSNH's interim stranded costs and to set
PSNH's interim stranded cost charges utilizing the determined methodology. The
NHPUC has not indicated when it will issue a decision in these proceedings. On
December 15, 1997, the NHPUC officially announced that industry restructuring
would not take place on January 1, 1998.
As part of the rehearing proceedings, PSNH proposed a new methodology to
quantify its stranded costs. Under this proposal, PSNH would divest its owned
generation and purchased power obligations via auction. To the extent that the
auction fails to produce sufficient revenues to cover the net book value of
owned generation and contractual payment obligations of purchased power, the
difference would be recovered from customers through a non-bypassable
distribution charge. The new proposal also relies upon securitization of
certain assets to further reduce rates.
On February 20, 1998, PSNH forwarded a settlement offer to representatives from
the state of New Hampshire that was consistent with PSNH's proposal in the
rehearing proceedings including, among other things, a 20 percent rate reduction
at the beginning of 1999, an auction of PSNH's nonnuclear generating units and
Securitization of approximately $1.15 billion of PSNH's stranded costs.
Massachusetts
On November 25, 1997, Massachusetts enacted a comprehensive electric utility
industry restructuring bill. The bill provides that each Massachusetts electric
company, including WMECO, will decrease its rates by 10 percent and allow all
its customers to choose their electric supplier on March 1, 1998. The statute
requires a further 5 percent rate reduction, adjusted for inflation, by
September 1, 1999.
In addition, the legislation provides, among other things, for: (i) recovery of
strandable costs through a "transition charge" to customers, subject to review
by the Department of Telecommunications and Energy (DTE), formerly the
Department of Public Utilities (DPU, collectively the DTE), (ii) a possible
limitation on WMECO's return on equity should its transition cost charge go
above a certain level, (iii) securitization of allowed strandable costs, and
(iv) divestiture of nonnuclear generation. WMECO hopes it will be able to
complete securitization in 1998.
The statute also provides that an electric company must transfer or separate
ownership of generation, transmission and distribution facilities into
independent affiliates or functionally separate such facilities within 30
business days after federal approval. Additionally, marketing companies formed
by an electric company are to be separate from the electric company and separate
from generation, transmission or distribution affiliates.
On December 31, 1997, WMECO filed its restructuring plan with the DTE consistent
with the Massachusetts restructuring legislation. The plan sets out the process
by which WMECO, as of March 1, 1998, initiated a 10 percent rate reduction for
all customer rate classes and allowed customers to choose their energy supplier.
WMECO intends to mitigate its strandable costs through several steps, including
divesting WMECO's nonnuclear generating plants at an auction to be held as soon
as June 30, 1998, and securitization of approximately $500 million of stranded
costs. NU intends to participate through a nonregulated affiliate in the
competitive bid process for WMECO's generation resources. Any proceeds in
excess of book value received from the divestiture of these units will be used
to mitigate stranded costs. As required by the legislation, WMECO will continue
to operate and maintain the transmission and local distribution network and
deliver electricity to all customers. On February 20, 1998, the DTE issued an
order approving, in all material respects, WMECO's restructuring plan on an
interim basis. A final decision is expected in 1998.
Because WMECO is obligated to reduce rates on March 1, 1998, before the means of
financing for restructuring are completed, WMECO's cash flows and financial
condition will be negatively affected. These impacts would become significant if
there are material delays in, or significantly reduced proceeds from, the
divestiture of nonnuclear generation and securitization.
Connecticut
Massachusetts and New Hampshire have been at the forefront of the restructuring
movement in New England with very different approaches as previously discussed.
In Connecticut, legislators have proposed broad restructuring legislation which
will be considered in the spring of 1998.
Rate Matters
Connecticut
In July 1996, the DPUC approved a rate settlement agreement with CL&P (the
Settlement). Under the Settlement, CL&P froze base rates until at least December
31, 1997, and agreed to accelerate the amortization of regulatory assets during
the period that the rate freeze remains in effect. The Settlement provided that
CL&P's target return on equity (ROE) would be 10.7 percent but did not alter
CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a calendar year
exceeds 10.7 percent after the target regulatory asset amortization ($68 million
in 1997) and after adjustment for any incremental NRC billings and any rate
disallowances for nuclear operations, then CL&P shall retain two-thirds of any
surplus and use the remaining one-third to provide a reduction in bills. CL&P's
actual ROE, as adjusted, fell below the target ROE for 1996 and 1997 and,
therefore, the accelerated amortization of regulatory assets was reduced to the
minimum amounts allowed under the Settlement ($73 million in 1996 and $54
million in 1997). For each full year that the rate freeze remains in effect,
CL&P agreed to amortize an additional $44 million of regulatory assets. On July
30, 1997, the DPUC issued a decision in its prudence review of nuclear cost
recovery issues disallowing CL&P's recovery of all of the replacement power
costs associated with the ongoing outages at Millstone. CL&P has expensed, and
will continue to expense, replacement power costs for the Millstone outages as
they are incurred.
The DPUC is required to review a utility's rates every four years if there has
not been a rate proceeding during such period. In 1997, the DPUC conducted such
a review of CL&P's rates, including an analysis of the possibility of removing
one or more of the Millstone nuclear units from CL&P's rate base. On December
31, 1997, the DPUC issued its ruling in this matter. The decision did not
effect a change in CL&P's rates, but set forth findings and conclusions that
could be used to do so in additional proceedings. The most significant
conclusion was that Millstone 1 should be removed from CL&P's rate base, which
would cause an annual revenue reduction of approximately $30.5 million. The
decision stated that the DPUC would open an interim rate case immediately to
remove Millstone 1 from CL&P's rates and simultaneously to remove an additional
$110.5 million of other expenses from rates related to perceived overearnings.
In February 1998, the DPUC issued a decision reducing CL&P's rates by
approximately 1.4 percent to reflect the removal of Millstone 1 from rates.
This reduction reflects the removal from rates of O&M, depreciation and
investment return related to Millstone 1, net of replacement power costs. In
addition, the decision requires CL&P to accelerate the amortization of
regulatory assets by $110.5 million, which includes the $44 million from the
1996 Settlement. The interim rate reduction became effective on March 1, 1998.
CL&P also was directed to file a full rate case on June 1, 1998, to address
potential overearnings amounting to an additional $150 million in 1998. The
effective date of any rate order will be September 28, 1998. In addition, the
DPUC has scheduled a hearing for April 1, 1998, to determine the status of
Millstone 3 and Millstone 2. A similar restart status hearing is anticipated
for June 1, 1998. If the units are not operating by those dates, the DPUC will
consider their removal from rates.
The DPUC also will consider CL&P's analyses of the economic benefits of the
continued operation of Millstone 1 and Millstone 2 in the context of CL&P's next
integrated resource planning proceeding, which begins in April 1998.
New Hampshire
PSNH's Rate Agreement provides for seven base rate increases and a comprehensive
fuel and purchased power adjustment clause (FPPAC). In June 1996, the final base
rate increase of 5.5 percent went into effect. Although the FPPAC continues for
an additional four years beyond the end of the fixed rate period, there is
uncertainty regarding how it will function after that time.
On May 2, 1997, PSNH made a rate filing with the NHPUC requesting base rates to
remain at their current level after May 31, 1997. By order dated November 6,
1997, the NHPUC ordered a temporary rate reduction for PSNH at a revenue level
6.87 percent lower than current rates. The NHPUC also set an interim return on
equity of 11 percent. The temporary rates became effective December 1, 1997. A
final decision, which will be reconciled to July 1, 1997, is not expected to be
issued until September 1998. A portion of this reduction was offset by an
increase to rates through the FPPAC.
On February 10, 1998, the NHPUC ordered an FPPAC rate for the period December 1,
1997, through May 31, 1998, which increased customer bills by approximately 6
percent. This rate continues to defer recovery of a substantial portion of
costs for the future. In addition, recovery of the Seabrook deferred return
(approximately $127 million annually) is scheduled to begin in June 1998. See
the "Notes to Consolidated Financial Statements," Note 2K, for further
information on the FPPAC.
Massachusetts
In April 1996, the DTE approved a settlement (the Agreement) that included the
continuation through February 1998 of a 2.4 percent rate reduction instituted in
June 1994. Additionally, the Agreement terminated certain pending and potential
reviews of WMECO's generating plant performance and accelerated its amortization
of strandable generation assets by approximately $6 million in 1996 and $10
million in 1997.
On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a
settlement agreement with the Massachusetts Attorney General for a fuel
adjustment clause (FAC) which would allow for a lower rate to WMECO customers
for the billing months of September 1997 through February 1998. WMECO is not
recovering replacement power costs during this period and has indicated that it
would not seek recovery of any replacement power costs associated with the
Millstone outages. WMECO has been expensing and will continue to expense these
costs. The Massachusetts restructuring legislation effectively eliminates the
FAC, effective March 1, 1998.
Nuclear Decommissioning
Connecticut Yankee
The NU system has a 49 percent ownership interest in the Connecticut Yankee
nuclear generating facility (CY or the plant). On December 4, 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease
permanently the production of power at the plant. The decision to retire CY
from commercial operation was based on an economic analysis of the costs of
operating it compared to the costs of closing it and incurring replacement power
costs over the remaining period of the plant's operating license, which would
have expired in 2007. The economic analysis showed that closing the plant and
incurring replacement power costs produced substantial savings.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December 1996, CY filed an amendment to its power
contracts with the FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1997, NU's
share of these obligations was approximately $304 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that
CL&P, PSNH and WMECO each will continue to be allowed to recover such FERC
approved costs from their customers. Accordingly, NU has recognized its share of
the estimated costs as a regulatory asset, with a corresponding obligation, on
its balance sheet.
Maine Yankee
The NU system has a 20 percent ownership interest in the Maine Yankee (MY)
nuclear generating facility. On August 6, 1997, the Board of Directors of Maine
Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY. On January
14, 1998, FERC released a draft order on the MYAPC application to amend its
power contracts with the owner/purchasers and revise its decommissioning and
other charges. FERC has accepted the proposed application for filing and made
the amendments and the proposed charges under the contracts effective on January
15, 1998, subject to refund after hearings. At December 31, 1997, the NU
system's share of the estimated remaining obligation, including decommissioning,
amounted to approximately $173 million. Under the terms of the contracts with
MYAPC, the shareholders' sponsor companies, including CL&P, PSNH and WMECO, are
responsible for their proportionate share of the costs of the unit, including
decommissioning. Management expects that CL&P, PSNH and WMECO will be allowed to
recover these costs from their customers. Accordingly, NU has recognized these
costs as a regulatory asset, with a corresponding obligation on its balance
sheet.
Millstone and Seabrook
NU's estimated cost to decommission its shares of the Millstone plants and
Seabrook is approximately $1.48 billion in year end 1997 dollars. These costs
are being recognized over the lives of the respective units with a portion
currently being recovered through rates. As of December 31, 1997, the market
value of the contributions already made to the decommissioning trusts, including
their investment returns, was approximately $503 million. See the "Notes to
Consolidated Financial Statements," Note 3, for further information on nuclear
decommissioning, including the NU system's share of costs to decommission the
other regional nuclear generating units.
Environmental Matters
NU's subsidiaries are potentially liable for environmental cleanup costs at a
number of sites inside and outside their service territories. To date, the
future estimated environmental remediation liability has not been material with
respect to the earnings or financial position of the NU system. At December 31,
1997, NU's subsidiaries had recorded an environmental reserve of approximately
$16 million. See the "Notes to Consolidated Financial Statements," Note 8C, for
further information on environmental matters.
Year 2000 Issue
The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU's systems to process critical financial and operational
information incorrectly. The company has assessed and continues to assess the
impact of the Year 2000 issue on its operating and reporting systems. The
assessment of the nuclear operating systems is continuing and is expected to be
completed in the summer of 1998.
The NU system will utilize both internal and external resources to reprogram or
replace and test the software for Year 2000 modifications. The total estimated
remaining cost of the Year 2000 project is $37 million and is being funded
through operating cash flows. This estimate does not include any costs for the
replacement or repair of equipment or devices that may be identified during the
assessment process. The majority of these costs will be expensed as incurred
over the next two years. To date, the company has incurred and expensed
approximately $4 million related to the assessment of, and preliminary efforts
in connection with, its Year 2000 project.
The costs of the project and the date on which the company plans to complete the
Year 2000 modifications are based on management's best estimates, which were
derived utilizing numerous assumptions of future events, including the continued
availability of certain resources, third-party modification plans and other
factors. However, there can be no guarantee that these estimates will be
achieved, and actual results could differ materially from those plans. If the NU
system's remediation plan is not successful, there could be a significant
disruption of the NU system's operations.
Risk-Management Instruments
The following discussion about the NU system's risk-management activities
includes forward looking statements that involve risk and uncertainties. Actual
results could differ materially from those projected in the forward looking
statements.
This analysis presents the hypothetical loss in earnings related to the fuel
price and interest rate market risks not covered by the risk-management
instruments at December 31, 1997. The NU system uses swaps, collars, puts and
calls to manage the market risk exposures associated with changes in fuel prices
and variable interest rates. The NU system does not use these risk-management
instruments for speculative purposes. For more information on NU's use of risk-
management instruments, see the "Notes to Consolidated Financial Statements,"
Notes 2.0 and 9.
Fuel Price Risk-Management Instruments
In the generation of electricity, the most significant variable cost component
is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by a
regulatory fuel price adjustment clause. However, for a specific, well-defined
volume of fuel that is excluded from the fuel price adjustment clause
(unprotected volume), CL&P employs fuel price risk-management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks are created by the sale of
long-term, fixed-price electricity contracts to wholesale customers and the
purchase or generation of replacement power related to the ongoing Millstone
nuclear outages.
At December 31, 1997, CL&P had outstanding agreements with a total notional
value of approximately $327 million. The settlement amounts associated with the
instruments reduced fuel expense by approximately $8 million. CL&P has had
experience using various fuel price risk-management instruments since 1994, most
of which have been in the form of fuel price swaps. At December 31, 1997,
approximately 30 percent of the unprotected volume was covered by fuel price
risk-management instruments (hedge ratio) for 1997. This effectively fixed or
bounded the fuel cost and thus eliminated the market price risk for this covered
volume of fuel. At December 31, 1997, CL&P had a hedge ratio of 44 percent for
1998.
At December 31, 1997, the 56 percent uncovered volume of fuel for 1998, as a
result of not being hedged, is subject to changes in actual market prices.
Therefore, assuming a hypothetical 10 percent increase in the average 1997 price
of fuel in 1998, the result would be a negative pretax impact on earnings of
approximately $12.4 million.
This analysis is based on the broad assumption that the entire uncovered volume
of fuel remains constant and will be purchased on the spot market. This
assumption is subject to change as the uncovered volume of fuel likely will
change during the next year. Other assumptions used in this analysis,
projections of the fuel mix, the amount of long-term sales contracts or the
projected Millstone restart dates, also are subject to change.
Interest Rate Risk-Management Instruments
Several NU subsidiaries hold variable rate long-term notes, exposing the NU
system to interest rate risk. In order to hedge some of this risk, interest rate
risk-management instruments have been entered into on NAEC's $200 million
variable rate note, effectively fixing the interest on this note at 7.823
percent. The remaining variable notes remain unhedged.
At December 31, 1997, NU had a hedge ratio on its long-term variable rate notes
of 21 percent, which is expected to be the same for 1998. The remaining 79
percent of NU's variable notes are unhedged and, as a result, are subject to
actual market rates for 1998. Thus, a 10 percent increase in market interest
rates above the 1997 weighted average variable rate during 1998 would result
in a $3.6 million pretax annual decrease in earnings.
For purposes of this analysis, the hedge ratio for long-term variable rate notes
is calculated by dividing the amount of the hedged long-term note by the total
of all long-term variable notes held at December 31, 1997.
Results of Operations
The components of significant income statement variances for the past two years
are provided in the table below. The relative magnitude of how revenues earned
in 1997 and retained earnings were used by NU's continuing operations in 1997 is
illustrated in the chart on page 21.
Income Statement Variances
(Millions of Dollars)
1997 over/(under) 1996 1996 over/(under) 1995
Amount Percent Amount Percent
Operating revenues $ 43 1% $ 42 1%
Fuel, purchased and net
interchange power 154 13 230 25
Other operation 3 - 127 13
Maintenance 86 21 127 44
Amortization of regulatory
assets, net 8 7 (6) (5)
Federal and state income
taxes (94) (98) (166) (63)
Deferred nuclear plants
return (other and
borrowed funds) (3) (13) (13) (36)
Other income, net (69) (a) 20 (a)
Interest on long-term debt (3) (1) (30) (10)
Other interest (4) (53) 1 15
Preferred dividends of
subsidiaries (3) (10) (6) (14)
Net income (169) (a) (244) (86)
(a) Percentage greater than 100
Operating Revenues
Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $32
million, primarily due to higher fuel revenues for CL&P as a result of a lower
fuel rate in 1996. Conservation recoveries increased by $17 million, primarily
due to a 1996 reserve for overrecoveries of CL&P demand-side management costs.
Retail kilowatt hour sales were 0.3 percent lower in 1997 as a result of mild
winter weather.
Total operating revenues increased in 1996, primarily due to higher retail
sales, regulatory decisions and higher other revenues, partially offset by lower
fuel recoveries and lower wholesale revenues. Retail sales increased 1.6 percent
($40 million), primarily due to modest economic growth in 1996. Regulatory
decisions increased revenues by $22 million, primarily due to retail rate
increases for CL&P in mid-1995 and PSNH in mid-1995 and 1996, partially offset
by 1996 reserves for CL&P overrecoveries of demand-side management costs. Other
revenues increased $31 million and included higher recognition in 1996 of
reimbursable conservation services and higher transmission revenues. Fuel
recoveries decreased $40 million, primarily due to lower FPPAC revenues for PSNH
as a result of a customer refund ordered by the NHPUC, partially offset by
higher base fuel revenues for PSNH as a result of the PSNH rate increases.
Wholesale revenues decreased $13 million, primarily due to higher
recognition in 1995 of lump-sum payments for the termination of a CL&P long-term
contract and capacity sales contracts that expired in 1995.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 1997, primarily
due to replacement power costs associated with the Millstone outages and the
expensing in 1997 of replacement power costs incurred in 1996.
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to replacement power costs associated with the Millstone outages and the
write-off of the generation utilization adjustment clause (GUAC) balance under
the CL&P Settlement.
Other Operation and Maintenance
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($216 million), higher
costs as a result of Seabrook outages ($23 million) and higher capacity charges
from Maine Yankee ($16 million), partially offset by lower recognition of
nuclear refueling outage costs primarily as a result of the 1996 CL&P Rate
Settlement ($72 million), lower capacity charges from Connecticut Yankee as a
result of a property tax refund ($35 million), lower administrative and general
expenses ($41 million) primarily due to lower pensions and benefit costs, and
lower storm expenses. Other operation and maintenance expenses increased in
1996, primarily due to higher costs associated with the Millstone restart effort
($116 million) and 1996 costs to ensure adequate generating capacity in
Connecticut ($39 million). In addition, 1996 costs reflect higher storm and
reliability expenditures, higher recognition of conservation expenses and higher
marketing costs.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in 1997, primarily due to the
completion of the CL&P cogeneration deferrals in 1996, increased amortization in
1997, and the beginning of the amortization of NAEC's Seabrook deferred return
in December 1997, partially offset by the completion of CL&P's Seabrook
amortization and WMECO's Millstone 3 amortization in 1996.
Amortization of regulatory assets, net decreased in 1996, primarily due to the
completion of the Millstone 3 phase-in plans in 1995, partially offset by lower
CL&P cogeneration deferrals and the accelerated amortization of regulatory
assets as a result of the 1996 CL&P Settlement.
Federal and State Income Taxes
Federal and state income taxes decreased in 1997, primarily due to lower book
taxable income. Federal and state income taxes decreased in 1996, primarily due
to lower book taxable income, partially offset by 1995 tax benefits from a
favorable tax ruling and the expiration of the 1991 federal statute of
limitations. Income tax expense totaled approximately $95 million in 1996,
despite relatively low pretax earnings, due to the tax effect of differences for
certain items, particularly depreciation and the amortization of PSNH
acquisition costs.
Deferred Nuclear Plants Return
The change in deferred nuclear plants return in 1997 was not significant.
Deferred nuclear plants return decreased in 1996, primarily due to additional
Seabrook investment being phased into rates, partially offset by a one-time
adjustment to NAEC's Seabrook deferred return balance of approximately $5
million in 1995.
Other Income, Net
Other income, net decreased in 1997, primarily due to a $25 million reserve for
anticipated losses on the sale of investments by Charter Oak Energy (COE),
equity losses on COE investments, costs associated with the accounts receivable
facility, nonutility marketing and advertising costs and lower miscellaneous
income.
Other income, net increased in 1996, primarily due to higher interest income on
temporary cash investments in 1996, the 1995 write-down of CL&P's wholesale
investment in Millstone 3 and a 1995 increase to the environmental reserve.
Interest on Long-Term Debt
The change in interest on long-term debt in 1997 was not significant. Interest
on long-term debt decreased in 1996, primarily due to reacquisitions and
retirements of long-term debt in 1995.
Other Interest
Other interest expense decreased in 1997 due to 1996 interest expense associated
with an FPPAC refund for PSNH.
Preferred Dividends of Subsidiaries
The change in preferred dividends of subsidiaries was not significant in 1997.
Preferred dividends of subsidiaries decreased in 1996, primarily due to a 1995
charge to earnings for premiums on redeemed preferred stock and a reduction in
preferred stock levels.
1997 Use of Revenue and Retained Earnings
[The following table was originally a pie chart in the printed materials.]
Energy Costs 32%
Nonfuel Operation and Maintenance Expenses 28%
Depreciation, Amortization and Other Expenses 13%
Wages and Benefits 12%
Interest Charges 7%
Taxes 6%
Common and Preferred Dividends 2%
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Quarterly Financial Data (Restated)
(Unaudited)
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
1997 Quarter Ended (a)
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share data) March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues.....................................$ 975,368 $ 903,323 $ 977,127 $ 978,988
- ---------------------------------------------------------------------------------------------------------
Operating Income.......................................$ 69,377 $ 23,542 $ 46,361 $ 51,502
- ---------------------------------------------------------------------------------------------------------
Net Income/(Loss)......................................$ 876 $ (47,017) $ (30,832) $ (52,989)
- ---------------------------------------------------------------------------------------------------------
Earnings/(Loss) Per Common Share.......................$ 0.01 $ (0.37) $ (0.24) $ (0.41)
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
1996
- ---------------------------------------------------------------------------------------------------------
Operating Revenues.....................................$1,028,202 $ 871,904 $ 955,518 $ 936,524
- ---------------------------------------------------------------------------------------------------------
Operating Income.......................................$ 155,433 $ 87,725 $ 63,432 $ 2,080
- ---------------------------------------------------------------------------------------------------------
Net Income/(Loss)......................................$ 87,674 $ 17,572 $ (3,567) $ (62,750)
- ---------------------------------------------------------------------------------------------------------
Earnings/(Loss) Per Common Share.......................$ 0.68 $ 0.14 $ (0.03) $ (0.49)
- ---------------------------------------------------------------------------------------------------------
</TABLE>
Consolidated Generation Statistics
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Source of Electric Energy:(kWh-millions)
Nuclear--Steam (b)......................... 3,778 9,405 18,235 19,443 22,965
Fossil--Steam.............................. 13,155 9,188 9,162 8,292 7,676
Hydro--Conventional........................ 1,260 1,544 1,099 1,239 1,140
Hydro--Pumped Storage...................... 959 1,217 1,209 1,195 1,269
Internal Combustion........................ 184 206 37 13 8
Energy Used for pumping.................... (1,327) (1,668) (1,674) (1,629) (1,749)
- ---------------------------------------------------------------------------------------------------------
Net Generation............................. 18,009 19,892 28,068 28,553 31,309
- ---------------------------------------------------------------------------------------------------------
Purchased and Net Interchange.............. 24,377 22,111 14,256 14,028 10,499
Company Use and Unaccounted for............ (2,802) (2,473) (2,706) (2,535) (2,591)
- ---------------------------------------------------------------------------------------------------------
Net Energy Sold............................ 39,584 39,530 39,618 40,046 39,217
=========================================================================================================
System Capability--MW (b)(c)............... 8,312.0 8,894.0 8,394.8 8,494.8 7,795.3
System PeaK Demand--MW..................... 6,455.5 5,946.9 6,358.2 69,338.5 6,191.0
Nuclear Capacity--MW (b)(c)................ 2,785.0 3,117.8 3,239.6 3,272.6 3,110.0
Nuclear Contribution to Total
Energy Requirements(%) (b)................ 13.0 28.0 52.0 54.0 62.1
Nuclear Capacity Factor(%) (d)............. 19.6 38.0 69.9 67.5 80.8
=========================================================================================================
(a) Reclassifications of prior data have been made to conform with the current presentation.
(b) Includes the NU system's entitlements in regional nuclear generating companies, net of capacity
sales and purchases.
(c) Millstone 1, 2 and 3 have been out of service since November 4, 1995, Febuary 21, 1996 and
March 30, 1996, respectively. The company has restructured its nuclear organization and is
currently implementing comprehensive plans to restart the units. The actual date of the return to
service for each of the units is dependent upon the completion of independent inspections and
reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service
in early spring of 1998 and Millstone 2 three to fours months after Millstone 3. Millstone 1 is
currently in extended maintenance status.
(d) Represents the average capacity factor for the nuclear units operated by the NU system.
</TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
Selected Consolidated Financial Data
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except 1997 1996
percentages and per share data) (Restated) (Restated) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Net Utility Plant (a)................$ 6,463,158 $ 6,732,165 $ 7,000,837 $ 7,282,421 $ 7,439,159
Total Assets......................... 10,414,412 10,741,748 10,559,574 10,584,880 10,668,164
Total Capitalization (b)............. 6,472,504 6,659,617 6,820,624 7,035,989 7,309,898
Obligations Under Capital Leases (b). 207,731 206,165 230,482 239,121 243,760
- ------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues...................$ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742 $ 3,629,093
Net(Loss)/Income..................... (129,962) 38,929 282,434 286,874 249,953 (c)
- ------------------------------------------------------------------------------------------------------
Common Shate Data:
(Loss)/Earnings per Share............ ($1.01) $0.30 $2.24 $2.30 $2.02 (c)
Dividends per Share (d).............. $0.25 $1.38 $1.76 $1.76 $1.76
Number of Shares
Outstanding--Average................ 129,567,708 127,960,382 126,083,645 124,678,192 123,947,631
Market Price--High................... $14 1/4 $25 1/4 $25 3/8 $25 3/4 $28 7/8
Market Price--Low.................... $7 5/8 $9 1/2 $21 $20 3/8 $22
Market Price--Closing (end of year).. $11 13/16 $13 1/8 $24 1/4 $21 5/8 $23 3/4
Book Value per Share (end of year)... $16.67 $18.02 $19.08 $18.47 $17.89
Rate of Return Earned on Average
Common Equity (%)................... (5.8) 1.6 12.0 12.7 11.4
Market-to-Book Ratio (end of year)... 0.7 0.7 1.3 1.2 1.3
- ------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity.......... 34% 35% 36% 33% 30%
Preferred Stock (b)(e)............... 6 6 7 9 9
Long-Term Debt (b)................... 60 59 57 58 61
- ------------------------------------------------------------------------------------------------------
Total Capitalization................. 100% 100% 100% 100% 100%
======================================================================================================
(a) Includes the reclassification of the unamortized PSNH
acquisition costs to net utility plant.
(b) Includes portions due within one year.
(c) Includes the cumulative effect of change in accounting for municipal property
tax expense, which increased earnings for common shares and earnings per share by
$51.7 million and $0.42, respectively.
(d) Quarterly dividends were suspended effective March 25, 1997.
(e) Excludes $100 million of Monthly Income Preferred Securities.
</TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Sales Statistics
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 (a) 1993
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues: (thousands)
Residential.......................... $ 1,499,394 $ 1,501,465 $ 1,469,988 $ 1,430,239 $ 1,385,818
Commercial........................... 1,266,449 1,246,822 1,230,608 1,173,808 (b) 1,043,125
Industrial........................... 560,782 565,900 583,204 559,801 (b) 649,876
Other Utilities...................... 329,764 315,577 303,004 330,801 383,129
Streetlighting and Railroads......... 48,867 48,053 47,510 45,943 45,480
Non-Franchised Sales................. 21,476 8,360 - - -
Miscellaneous........................ 47,446 23,513 50,353 44,140 60,008
- ---------------------------------------------------------------------------------------------------------
Total Electric.................... 3,774,178 3,709,690 3,684,667 3,584,732 3,567,436
Other................................ 60,628 82,458 65,893 58,010 61,657
- ---------------------------------------------------------------------------------------------------------
Total............................. $ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742 $ 3,629,093
=========================================================================================================
Sales: (kWh - millions)
Residential.......................... 12,099 12,241 12,005 12,231 11,988
Commercial........................... 12,091 12,012 11,737 11,649 (b) 10,304
Industrial........................... 6,801 6,820 6,842 6,729 (b) 7,572
Other Utilities...................... 8,034 8,032 8,718 9,123 9,046
Streetlighting and Railroads......... 318 319 316 314 307
Non-Franchised Sales................. 241 50 - - -
- ---------------------------------------------------------------------------------------------------------
Total............................. 39,584 39,474 39,618 40,046 39,217
=========================================================================================================
Customers: (average)
Residential.......................... 1,535,134 1,532,015 1,526,127 1,513,987 1,503,182
Commercial........................... 159,350 157,347 156,652 154,703 (b) 155,487
Industrial........................... 7,804 7,792 7,861 7,813 (b) 6,272
Other................................ 3,929 3,916 3,878 3,818 3,793
- ---------------------------------------------------------------------------------------------------------
Total............................. 1,706,217 1,701,070 1,694,518 1,680,321 1,668,734
=========================================================================================================
Average Annual Use
per Residential Customer (kWh).... 7,898 8,005 7,880 (c) 8,152 7,987
=========================================================================================================
Average Annual Bill
per Residential Customer.......... $ 978.72 $ 980.19 $ 964.88 (c)$ 953.23 $ 923.32
=========================================================================================================
Average Revenue (in cents) per kWh:
Residential.......................... 12.39 12.27 12.24 11.69 11.56
Commercial........................... 10.47 10.38 10.49 10.08 10.12
Industrial........................... 8.25 8.30 8.52 8.32 8.58
=========================================================================================================
(a) Effective January 1, 1994, the accounting for unbilled revenues was
revised to report unbilled revenues by customer class.
(b) Effective January 1, 1994, approximately 1,300 customers previously
classified as commercial customers were reclassified to industrial
customers.
(c) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.
</TABLE>
EXHIBIT 13.2
THE CONNECTICUT LIGHT AND POWER COMPANY
AND SUBSIDIARIES
AMENDED 1997 ANNUAL REPORT
The Connecticut Light and Power Company and Subsidiaries
Amended 1997 Annual Report
Index
Contents Page
Consolidated Balance Sheets (Restated)............................... 2-3
Consolidated Statements of Income (Restated)......................... 4
Consolidated Statements of Cash Flows (Restated)..................... 5
Consolidated Statements of Common Stockholder's
Equity (Restated).................................................... 6
Notes to Consolidated Financial Statements (Restated)................ 7
Report of Independent Public Accountants............................. 41
Management's Discussion and Analysis of Financial
Condition and Results of Operations (Restated)..................... 42
Selected Financial Data (Restated)................................... 54
Statements of Quarterly Financial Data (Restated).................... 54
Statistics........................................................... 55
Preferred Stockholder and Bondholder Information..................... Back Cover
PART I. FINANCIAL INFORMATION
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................. $ 6,411,018 $ 6,283,736
Less: Accumulated provision for depreciation.......... 2,902,673 2,665,519
------------- -------------
3,508,345 3,618,217
Construction work in progress............................ 93,692 95,873
Nuclear fuel, net........................................ 135,076 133,050
------------- -------------
Total net utility plant.............................. 3,737,113 3,847,140
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market................ 369,162 296,960
Investments in regional nuclear generating
companies, at equity.................................... 58,061 56,925
Other, at cost........................................... 66,625 16,565
------------- -------------
493,848 370,450
------------- -------------
Current Assets:
Cash..................................................... 459 404
Notes receivable from affiliated companies............... - 109,050
Investments in securitizable assets...................... 205,625 -
Receivables, less accumulated provision for
uncollectible accounts of $300,000 in 1997
and of $13,240,000 in 1996............................. 50,671 226,112
Accounts receivable from affiliated companies............ 3,150 3,481
Taxes receivable......................................... 70,311 40,134
Accrued utility revenues................................. - 78,451
Fuel, materials and supplies, at average cost............ 81,878 79,937
Recoverable energy costs, net--current portion........... 28,073 25,436
Prepayments and other.................................... 79,632 63,344
------------- -------------
519,799 626,349
------------- -------------
Deferred Charges:
Regulatory assets........................................ 1,292,818 1,370,781
Unamortized debt expense................................. 19,286 17,033
Other.................................................... 18,359 12,283
------------- -------------
1,330,463 1,400,097
------------- -------------
Total Assets......................................... $ 6,081,223 $ 6,244,036
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$10 par value. Authorized
24,500,000 shares; outstanding 12,222,930
shares in 1997 and 1996................................ $ 122,229 $ 122,229
Capital surplus, paid in................................ 641,333 639,657
Retained earnings (Note 1).............................. 419,972 580,779
------------- -------------
Total common stockholder's equity.............. 1,183,534 1,342,665
Cumulative preferred stock--
$50 par value - authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1997 and 1996;
$25 par value - authorized 8,000,000 shares;
outstanding no shares in 1997 and 1996
Not subject to mandatory redemption.................... 116,200 116,200
Subject to mandatory redemption........................ 151,250 155,000
Long-term debt.......................................... 2,023,316 1,834,405
------------- -------------
Total capitalization........................... 3,474,300 3,448,270
------------- -------------
Minority Interest in Consolidated Subsidiary.............. 100,000 100,000
------------- -------------
Obligations Under Capital Leases.......................... 18,042 143,347
------------- -------------
Current Liabilities:
Notes payable to banks.................................. 35,000 -
Notes payable to affiliated company..................... 61,300 -
Long-term debt and preferred stock--current
portion................................................ 23,761 204,116
Obligations under capital leases--current
portion................................................ 140,076 12,361
Accounts payable........................................ 124,427 160,945
Accounts payable to affiliated companies................ 92,963 78,481
Accrued taxes........................................... 33,017 28,707
Accrued interest........................................ 14,650 31,513
Other................................................... 23,495 34,433
------------- -------------
548,689 550,556
------------- -------------
Deferred Credits:
Accumulated deferred income taxes....................... 1,348,617 1,386,772
Accumulated deferred investment tax credits............. 127,713 135,080
Deferred contractual obligations........................ 348,406 305,627
Other................................................... 115,456 174,384
------------- -------------
1,940,192 2,001,863
------------- -------------
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities........... $ 6,081,223 $ 6,244,036
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................... $2,465,587 $2,397,460 $2,387,069
----------- ----------- -----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power....... 977,543 831,079 608,600
Other........................................... 726,420 727,674 614,382
Maintenance........................................ 355,772 300,005 192,607
Depreciation....................................... 238,667 247,109 242,496
Amortization of regulatory assets, net............. 61,648 57,432 54,217
Federal and state income taxes..................... (59,436) 957 178,346
Taxes other than income taxes...................... 172,592 174,062 172,395
----------- ----------- -----------
Total operating expenses (Note 1)............ 2,473,206 2,338,318 2,063,043
----------- ----------- -----------
Operating (Loss)/Income.............................. (7,619) 59,142 324,026
----------- ----------- -----------
Other Income:
Equity in earnings of regional nuclear
generating companies............................. 5,672 6,619 6,545
Other, net......................................... (1,856) 20,710 14,585
Minority interest in income of subsidiary.......... (9,300) (9,300) (8,732)
Income taxes....................................... 7,573 160 (2,978)
----------- ----------- -----------
Other income, net............................ 2,089 18,189 9,420
----------- ----------- -----------
(Loss)/Income before interest charges........ (5,530) 77,331 333,446
----------- ----------- -----------
Interest Charges:
Interest on long-term debt......................... 132,127 127,198 124,350
Other interest..................................... 1,940 1,001 3,880
----------- ----------- -----------
Interest charges, net........................ 134,067 128,199 128,230
----------- ----------- -----------
Net (Loss)/Income (Note 1)........................... $ (139,597) $ (50,868) $ 205,216
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net(Loss)/Income............................................ $(139,597) $ (50,868) $ 205,216
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 238,667 247,109 242,496
Deferred income taxes and investment tax credits, net..... (10,400) (39,642) 49,520
Deferred nuclear plants return, net of amortization....... (281) 7,746 95,559
Amortization of deferred demand-side-management costs, net 38,029 26,941 (937)
Recoverable energy costs, net of amortization............. (9,533) (35,567) (16,169)
Amortization of deferred cogeneration costs, net.......... 32,700 25,957 (55,341)
Deferred nuclear refueling outage, net of amortization ... (45,333) 45,643 (20,712)
Other sources of cash..................................... 64,013 75,552 86,956
Other uses of cash........................................ (50,137) (23,862) (53,745)
Changes in working capital:
Receivables and accrued utility revenues.................. 184,223 (22,378) (33,032)
Fuel, materials and supplies.............................. (1,941) (11,455) (4,479)
Accounts payable.......................................... (22,036) 83,951 9,605
Accrued taxes............................................. 4,310 (23,561) 25,855
Sale of receivables and accrued utility revenues.......... 70,000 - -
Investment in securitizable assets........................ (205,625) - -
Other working capital (excludes cash)..................... (74,266) (5,385) (1,869)
---------- ---------- ----------
Net cash flows from operating activities (Note 1)............. 72,793 300,181 528,923
---------- ---------- ----------
Financing Activities:
Issuance of long-term debt.................................. 200,000 222,000 -
Issuance of Monthly Income
Preferred Securities....................................... - - 100,000
Net increase/(decrease) in short-term debt.................. 96,300 (51,750) (127,000)
Reacquisitions and retirements of long-term debt............ (204,116) (14,329) (10,866)
Reacquisitions and retirements of preferred stock........... - - (125,000)
Cash dividends on preferred stock........................... (15,221) (15,221) (21,185)
Cash dividends on common stock.............................. (5,989) (138,608) (164,154)
---------- ---------- ----------
Net cash flows from/(used for) financing activities........... 70,974 2,092 (348,205)
---------- ---------- ----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (155,550) (140,086) (131,858)
Nuclear fuel.............................................. (702) 553 (1,543)
---------- ---------- ----------
Net cash flows used for investments in plant................ (156,252) (139,533) (133,401)
Investment in NU system money pool.......................... 109,050 (109,050) -
Investment in nuclear decommissioning trusts................ (45,314) (50,998) (47,826)
Other investment activities, net............................ (51,196) (2,625) 581
---------- ---------- ----------
Net cash flows used for investments........................... (143,712) (302,206) (180,646)
---------- ---------- ----------
Net Increase In Cash For The Period........................... 55 67 72
Cash - beginning of period.................................... 404 337 265
---------- ---------- ----------
Cash - end of period.......................................... $ 459 $ 404 $ 337
========== ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 145,962 $ 114,458 $ 117,074
========== ========== ==========
Income taxes................................................ $ (22,338) $ 77,790 $ 137,706
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases............. $ 2,815 $ 2,855 $ 33,537
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings(a) Total
Stock Paid In (Note 1)
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1995............... $122,229 $632,117 $ 765,724 $1,520,070
Net income for 1995.................. 205,216 205,216
Cash dividends on preferred
stock.............................. (21,185) (21,185)
Cash dividends on common stock....... (164,154) (164,154)
Loss on the retirement of
preferred stock............... (125) (125)
Capital stock expenses, net.......... 5,864 5,864
--------- --------- ---------- -----------
Balance at December 31, 1995............. 122,229 637,981 785,476 1,545,686
Net loss for 1996 (Note 1)........... (50,868) (50,868)
Cash dividends on preferred
stock.............................. (15,221) (15,221)
Cash dividends on common stock....... (138,608) (138,608)
Capital stock expenses, net.......... 1,676 1,676
--------- --------- ---------- -----------
Balance at December 31, 1996 (Restated).. 122,229 639,657 580,779 1,342,665
Net loss for 1997 (Note 1)........... (139,597) (139,597)
Cash dividends on preferred
stock.............................. (15,221) (15,221)
Cash dividends on common stock....... (5,989) (5,989)
Capital stock expenses, net.......... 1,676 1,676
--------- --------- ---------- -----------
Balance at December 31, 1997 (Restated).. $122,229 $641,333 $ 419,972 $1,183,534
========= ========= ========== ===========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1997, these restrictions totaled
approximately $540 million.
The accompanying notes are an integral part of these financial statements.
The Connecticut Light and Power Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SECURITIES AND EXCHANGE COMMISSION INQUIRY
In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC)
inquired into Northeast Utilities' (NU) accounting for nuclear compliance costs.
These costs are the unavoidable incremental costs associated with the current
nuclear outages required to be incurred prior to restart of the units in
accordance with correspondence received from the Nuclear Regulatory Commission
(NRC) early in 1996. The SEC's view is that these unavoidable costs associated
with nuclear outages and procedures to be implemented at nuclear power plants in
response to regulatory requirements required prior to restart of the units
should be expensed as incurred. During 1996 and 1997, NU and its wholly owned
subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service
Company of New Hampshire (PSNH) and Western Massachusetts Electric Company
(WMECO), reserved for these unavoidable incremental costs that they expected to
incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to
reflect these costs as they are incurred. While NU and its independent auditors,
Arthur Andersen LLP, believed the accounting was required by, and was in
accordance with, generally accepted accounting principles, the company has
agreed to adjust its accounting for nuclear compliance costs and amend its 1996
and 1997 Form 10-K filings. The financial statements in this report have been
restated to reflect the change in accounting.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT THE CONNECTICUT LIGHT AND POWER COMPANY
The Connecticut Light and Power Company and subsidiaries (the company
or CL&P), WMECO, Holyoke Water Power Company (HWP), PSNH and North
Atlantic Energy Corporation (NAEC) are the operating subsidiaries
comprising the Northeast Utilities system (the NU system) and are
wholly owned by NU.
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire and western Massachusetts through CL&P,
PSNH, WMECO and HWP. A fifth wholly owned subsidiary, NAEC, sells all
of its entitlement to the capacity and output of the Seabrook nuclear
power plant (Seabrook) to PSNH. In addition to its franchised retail
service, the NU system furnishes firm and other wholesale electric
services to various municipalities and other utilities, and
participates in limited retail access programs, providing off-system
retail electric service. The NU system serves about 30 percent of New
England's electric needs and is one of the 25 largest electric utility
systems in the country as measured by revenues.
Other wholly owned subsidiaries of NU provide support services for
the NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for the NU system companies and other
New England utilities in operating the Millstone nuclear generating
facilities. North Atlantic Energy Service Corporation (NAESCO) acts
as agent for CL&P and NAEC and has operational responsibilities for
Seabrook. In addition, CL&P and WMECO each have established a special
purpose subsidiary whose business consists of the purchase and resale
of receivables.
B. PRESENTATION
The consolidated financial statements of CL&P include the accounts of
all wholly owned subsidiaries. Significant intercompany transactions
have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent liabilities at the date of
the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ
from those estimates.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and are
subject to approval by various federal and state regulatory agencies.
For more information on significant subsidiaries of CL&P, see Note 11,
"Sale of Customer Receivables and Accrued Utility Revenues," and Note
14, "Minority Interest in Consolidated Subsidiary."
C. PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as
a holding company under the Public Utility Holding Company Act of 1935
(1935 Act). NU and its subsidiaries, including CL&P, are subject
to the provisions of the 1935 Act. Arrangements among the NU
system companies, outside agencies and other utilities covering
interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. CL&P is subject to further
regulation for rates, accounting and other matters by the FERC and/or
applicable state regulatory commissions.
For information regarding proposed changes in the nature of industry
regulation, see Note 2H, "Summary of Significant Accounting Policies -
Regulatory Accounting and Assets," and Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A).
D. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS), SFAS 129, "Disclosure of
Information about Capital Structure," in February 1997. SFAS 129
establishes standards for disclosing information about an entity's
capital structure. CL&P's current disclosures are consistent with
the requirements of SFAS 129.
During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive
Income" and SFAS 131, "Disclosures about Segments of an Enterprise
and Related Information." SFAS 130 establishes standards for the
reporting and disclosure of comprehensive income. To date, CL&P has
not had material transactions that would be required to be reported as
comprehensive income. SFAS 131 determines the standards for reporting
and disclosing qualitative and quantitative information about a
company's operating segments. This information includes segment profit
or loss, certain segment revenue and expense items and segment assets
and a reconciliation of these segment disclosures to corresponding
amounts in the company's general purpose financial statements. CL&P
currently evaluates management performance using a cost-based budget
and the information required by SFAS 131 is not available. Therefore,
these disclosure requirements are not applicable. Management believes
that the implementation of SFAS 130 and SFAS 131 will not have a
material impact on CL&P's current disclosures.
See Note 11, "Sale of Customer Receivables and Accrued Utility
Revenues," and Note 12C, "Commitments and Contingencies - Environmental
Matters," for information on other newly adopted accounting and
reporting standards related to those specific areas.
E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with CL&P's ownership interests are:
Connecticut Yankee Atomic Power Company(CYAPC) ............... 34.5%
Yankee Atomic Electric Company (YAEC) ........................ 24.5
Maine Yankee Atomic Power Company (MYAPC) .................... 12.0
Vermont Yankee Nuclear Power Corporation (VYNPC) ............. 9.5
CL&P's investments in the Yankee companies are accounted for on the
equity basis due to the company's ability to exercise significant
influence over their operating and financial policies.
CL&P's investments in the Yankee companies at December 31, 1997 are:
(Thousands of Dollars)
CYAPC .................................................. $38,358
YAEC ................................................... 5,128
MYAPC .................................................. 9,449
VYNPC .................................................. 5,126
$58,061
Each Yankee company owns a single nuclear generating unit. Under the
terms of the contracts with the Yankee companies, the shareholders-
sponsors are responsible for their proportionate share of the costs of
each unit, including decommissioning. The energy and capacity costs
from VYNPC and nuclear decommissioning costs of the Yankee companies
that have been shut down are billed as purchased power to CL&P.
The electricity produced by the Vermont Yankee nuclear generating
facility (VY) is committed substantially on the basis of ownership
interests and is billed pursuant to contractual agreements. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently on
February 26, 1992, December 4, 1996, and August 6, 1997, respectively.
Under ownership agreements with the Yankee companies, CL&P may be asked
to provide direct or indirect financial support for one or more of the
companies. For more information on the Yankee companies, see Note 4,
"Nuclear Decommissioning," and Note 12F, "Commitments and Contingencies
- Long-Term Contractual Arrangements."
Millstone 1: CL&P has an 81.0 percent joint ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of
December 31, 1997 and 1996, plant-in-service included approximately
$387.7 million and $384.5 million, respectively, and the accumulated
provision for depreciation included approximately $172.0 million and
$159.4 million, respectively, for CL&P's share of Millstone 1. CL&P's
share of Millstone 1 expenses is included in the corresponding
operating expenses on the accompanying Consolidated Statements of
Income.
Millstone 2: CL&P has an 81.0 percent joint ownership interest in
Millstone 2, an 870-MW nuclear generating unit. As of December 31,
1997 and 1996, plant-in-service included approximately $694.7 million
and $690.4 million, respectively, and the accumulated provision for
depreciation included approximately $249.1 million and $224.1 million,
respectively, for CL&P's share of Millstone 2. CL&P's share of
Millstone 2 expenses is included in the corresponding operating
expenses on the accompanying Consolidated Statements of Income.
Millstone 3: CL&P has a 52.93 percent joint ownership interest in
Millstone 3, a 1,154-MW nuclear generating unit. As of December 31,
1997 and 1996, plant-in-service included approximately $1.9 billion
each year and the accumulated provision for depreciation included
approximately $552.7 million and $504.1 million, respectively, for
CL&P's share of Millstone 3. CL&P's share of Millstone 3 expenses is
included in the corresponding operating expenses on the accompanying
Consolidated Statements of Income.
The three Millstone units are out of service. NU hopes to return
Millstone 3 to service in the early spring of 1998 and Millstone 2
three to four months after Millstone 3. Millstone 1 has been placed in
extended maintenance status. Management is reviewing its options with
respect to Millstone 1, including restart, early retirement and other
options. In a draft ruling issued in February 1998, the Connecticut
Department of Public Utility Control (DPUC) determined that Millstone 1
was no longer "used and useful" and ordered it removed from rate base.
In 1996, one of the joint owners of Millstone 3, Vermont Electric
Generation and Transmission Cooperative, Inc. (VEG&T), filed for
bankruptcy. The subsequent liquidation resulted in the offering of
VEG&T's 0.035 percent share of Millstone 3 for sale to the joint
owners of Millstone 3. None of the non-NU joint owners accepted the
offer. During 1998, CL&P expects to make the necessary regulatory
filings to acquire ownership of VEG&T's share of Millstone 3.
For more information regarding the DPUC's action, see the MD&A. For
more information regarding the Millstone units see Note 4, "Nuclear
Decommissioning," and Note 12B, "Commitments and Contingencies -
Nuclear Performance."
Seabrook 1: CL&P has a 4.06 percent joint ownership interest in
Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31,
1997 and 1996, plant-in-service included approximately $174.3 million
and $173.7 million, respectively, and the accumulated provision for
depreciation included approximately $33.9 million and $29.7 million,
respectively, for CL&P's share of Seabrook 1. CL&P's share of Seabrook
1 expenses is included in the corresponding operating expenses on the
accompanying Consolidated Statements of Income.
F. DEPRECIATION
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility plant-
in-service, adjusted for salvage value and removal costs, as approved
by the appropriate regulatory agency.
Except for major facilities, depreciation rates are applied to the
average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is
retired from service, the original cost of plant, including costs of
removal, less salvage, is charged to the accumulated provision for
depreciation. The depreciation rates for the several classes of
electric plant-in-service are equivalent to a composite rate of 3.8
percent in 1997 and 4.0 percent in 1996 and 1995. See Note 4, "Nuclear
Decommissioning," for information on nuclear decommissioning.
CL&P's nonnuclear generating facilities have limited service lives.
Plant may be retired in place or dismantled based upon expected future
needs, the economics of the closure and environmental concerns. The
costs of closure and removal are incremental costs and, for financial
reporting purposes, are accrued over the life of the asset as part of
depreciation. At December 31, 1997 and 1996, the accumulated provision
for depreciation included approximately $45.8 million and $43.0
million, respectively, accrued for the cost of removal, net of salvage
for nonnuclear generation property.
G. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, commercial and industrial customers and limited retail
access programs, utility revenues are based on authorized rates applied
to each customer's use of electricity. In general, rates can be changed
only through a formal proceeding before the appropriate regulatory
commission. Regulatory commissions also have authority over the terms
and conditions of nontraditional rate making arrangements. At the end
of each accounting period, CL&P accrues an estimate for the amount of
energy delivered but unbilled.
For information on rate proceedings and their potential impact on CL&P,
see the MD&A.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of CL&P and the accompanying consolidated
financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the
effects of the ratemaking process in accordance with SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." Assuming
a cost-of-service based regulatory structure, regulators may permit
incurred costs, normally treated as expenses, to be deferred and
recovered through future revenues. Through their actions, regulators
also may reduce or eliminate the value of an asset, or create a
liability. If any portion of CL&P's operations were no longer subject
to the provisions of SFAS 71, as a result of a change in the cost-of-
service based regulatory structure or the effects of competition, CL&P
would be required to write off all of its related regulatory assets and
liabilities unless there is a formal transition plan which provides for
the recovery, through established rates, for the collection of approved
stranded costs and to maintain the cost-of-service basis for the
remaining regulated operations. At the time of transition, CL&P would
be required to determine any impairment of the carrying costs of
deregulated plant and inventory assets.
Management anticipates that a restructuring program will be implemented
within Connecticut during the next few years. In a restructured
environment, CL&P's generation business no longer will be rate
regulated on a cost-of-service basis. The majority of CL&P's
regulatory assets are related to its generation business.
The staff of the SEC has had concerns regarding the appropriateness of
the utilities' ability to continue application of SFAS 71 for the
generation portion of their business in a restructured environment.
The SEC referred the issue to the Emerging Issues Task Force (EITF) of
the FASB which reached a consensus and issued "Deregulation of the
Pricing of Electricity - Issues Related to the Application of FASB
Statements No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the
future recognition of regulatory assets for the portion of the business
that no longer qualifies for application of SFAS 71 depends on the
regulators' treatment of the recovery of those costs and other stranded
assets from cash flows of other portions of the business still
considered to be regulated, and (2) a utility should discontinue the
application of SFAS 71 when a legislative and regulatory plan has been
enacted, which would include transition plans into a competitive
environment, and when the stranded costs which are subject to future
rate recovery are determined. EITF 97-4 became effective in August
1997.
The Connecticut General Assembly is addressing a proposal for electric
industry restructuring in the state of Connecticut during 1998. As the
terms and conditions to be contained within the restructuring plan
cannot be determined at this time, management believes that its use of
regulatory accounting remains appropriate.
CL&P expects that its transmission and distribution business will
continue to be rate-regulated on a cost-of-service basis and,
accordingly, CL&P will continue to apply SFAS 71 to this portion of
its business.
For further information on CL&P's regulatory environment and the
potential impacts of restructuring, see Note 12A, "Commitments and
Contingencies - Restructuring and Rate Matters" and the MD&A.
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," requires the evaluation of long-
lived assets, including regulatory assets, for impairment when certain
events occur or when conditions exist that indicate the carrying
amounts of assets may not be recoverable. SFAS 121 requires that any
long-lived assets which are no longer probable of recovery through
future revenues be revalued based on estimated future cash flows.
If this revaluation is less than the book value of the asset, an
impairment loss would be charged to earnings.
Management continues to believe that it is probable that CL&P will
recover its investments in long-lived assets through future revenues.
This conclusion may change in the future as the implementation of
restructuring plans in the state of Connecticut will generally require
the formation of a separate generation entity that will be subject to
competitive market conditions. As a result, CL&P will be required to
assess the carrying amounts of its long-lived assets in accordance with
SFAS 121.
The components of CL&P's regulatory assets are as follows:
At December 31, 1997 1996
(Thousands of Dollars)
Income taxes, net (Note 2I) ................. $ 709,896 $ 753,390
Recoverable energy costs,
net (Note 2J) ............................. 104,796 97,900
Deferred demand-side management
costs (Note 2K) ........................... 52,100 90,129
Cogeneration costs (Note 2L) ................ 33,505 66,205
Unrecovered contractual
obligations (Note 4) ...................... 338,406 300,627
Other ....................................... 54,115 62,530
$1,292,818 $1,370,781
I. INCOME TAXES
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial statements
and the periods in which they affect the determination of taxable
income) is accounted for in accordance with the ratemaking treatment
of the applicable regulatory commissions. See Note 9, "Income Tax
Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, which give rise
to the accumulated deferred tax obligation is as follows:
At December 31, 1997 1996
(Restated) (Restated)
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ................ $1,056,690 $1,032,857
Regulatory assets - income tax
gross up ................................. 304,276 313,420
Net operating loss carryforwards ........... (7,670) -
Other ...................................... (4,679) 40,495
$1,348,617 $1,386,772
At December 31, 1997, CL&P had a state of Connecticut net operating
loss carryforward of approximately $131 million which can be used
against CL&P and its affiliates' combined Connecticut taxable income
and which, if unused, expires in the year 2002.
J. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed
for its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary current
cost of fuel, to be fully recovered in rates like any other fuel cost.
CL&P is currently recovering these costs through rates. As of December
31, 1997, CL&P's total D&D deferrals were approximately $50.1 million.
During 1997, CL&P implemented an energy adjustment clause (EAC) under
which fuel prices above or below base-rate levels are charged or
credited to customers. The EAC replaced CL&P's fuel adjustment and
generation utilization adjustment clauses and is designed to reconcile
and adjust the difference between actual fuel costs and the fuel
revenue collected through base rates on a six-month basis.
For the period January 1, 1997 through June 30, 1997, CL&P agreed to
a zero EAC rate. For the period July 1, 1997 through December 31,
1997, the DPUC approved an EAC rate through which CL&P recovered
approximately $11.5 million of deferred fuel costs. While this
proceeding did not include provisions for the recovery of
approximately $18 million of costs related to the early closing
of CYAPC's nuclear generating unit, it did allow for the recovery
of costs, subject to refund, related to the closure of MYAPC's
nuclear generating unit. CL&P has appealed the DPUC's ruling
related to CYAPC replacement power costs.
During December 1997, the DPUC approved an EAC rate for the period
January 1, 1998 through June 30, 1998. During this period, CL&P will
recover approximately $27.9 million of deferred fuel costs.
At December 31, 1997, CL&P's net recoverable energy costs, excluding
current net recoverable energy costs, were approximately $104.8
million.
For further information on recoverable energy costs, see the MD&A.
K. DEMAND-SIDE MANAGEMENT (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism. CL&P is allowed to recover DSM costs in
excess of costs reflected in base rates over periods ranging from
approximately four to ten years.
During April 1997, the DPUC approved CL&P's DSM budget of $36 million
for 1997. In October 1997, CL&P and other interested parties filed a
stipulation with the DPUC requesting that the DPUC approve certain
programs and establish a budget level of $32.7 million for 1998 and
$28.8 million for 1999. The $52.1 million of DSM costs on CL&P's
books as of December 31, 1997, currently being collected, will be fully
recovered by 2000.
L. COGENERATION COSTS
Beginning on July 1, 1996, the deferred cogeneration balance of
approximately $86 million is being amortized over a five year period.
An additional $9 million of amortization was applied to the deferred
balance in 1997, as required under a settlement agreement which CL&P
reached with the DPUC. CL&P continues to apply any savings associated
facility to the deferred balance. Under current expectations, CL&P
expects complete amortization of the deferred balance by December 31,
1998. At December 31, 1997, CL&P's deferred cogeneration costs balance
was approximately $33.5 million.
M. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the
selection and development of repositories for, and the disposal of,
spent nuclear fuel and high-level radioactive waste. Fees for nuclear
fuel burned on or after April 7, 1983, are billed currently to
customers and paid to the DOE on a quarterly basis. For nuclear fuel
used to generate electricity prior to April 7, 1983 (prior-period
fuel), payment must be made prior to the first delivery of spent fuel
to the DOE. Until such payment is made, the outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield
Rate. At December 31, 1997, fees due to the DOE for the disposal
of prior-period fuel were approximately $166.5 million, including
interest costs of $99.9 million.
The DOE was originally scheduled to begin accepting delivery of spent
fuel in 1998. However, delays in identifying a permanent storage site
have continually postponed plans for the DOE's long-term storage and
disposal site. Extended delays or a default by the DOE could lead
to consideration of costly alternatives. The company has primary
responsibility for the interim storage of its spent nuclear fuel.
Current capability to store spent fuel at Millstone 1 and 2 are
estimated to be adequate until 2004 and at Seabrook until 2010.
Storage facilities for Millstone 3 are expected to be adequate for
the projected life of the unit. Meeting spent fuel storage
requirements beyond these periods could require new and separate
storage facilities, the costs for which have not been determined.
In November 1997, the U.S. District Court of Appeals for the D.C.
Circuit ruled that the lack of an interim storage facility does
not excuse the DOE from meeting its contractual obligation to
begin accepting spent nuclear fuel no later than January 31, 1998.
Currently, the DOE has not taken the spent nuclear fuel as scheduled
and, as a result, may have to pay contract damages. The ultimate
outcome of this legal proceeding is uncertain at this time.
N. MARKET RISK-MANAGEMENT POLICIES
CL&P utilizes market risk-management instruments, including swaps,
collars, puts and calls, to hedge well-defined risks associated
with changes in fuel prices. To qualify for hedge treatment, the
underlying hedged item must expose CL&P to risks associated with market
fluctuations and the market-risk management instrument used must be
designated as a hedge and must reduce the company's exposure to market
fluctuations throughout the period.
Amounts receivable or payable under fuel-price management instruments
are recognized in operating revenues when realized. CL&P does not use
market risk-management instruments for speculative purposes. For
further information, see Note 13, "Market Risk Management."
3. LEASES
CL&P and WMECO may finance up to $400 million of nuclear fuel for Millstone
1 and 2 and their respective shares of the nuclear fuel for Millstone 3
under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is
scheduled to expire July 31, 1998. The NBFT capital lease agreement, which
was amended in February 1998, requires CL&P and WMECO to secure their
obligation to repay the NBFT with up to $90 million of first mortgage
bonds. CL&P and WMECO will issue these bonds by May 1998.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates
which reflect estimated kilowatt hours of energy provided plus financing
costs associated with the fuel in the reactors. Upon permanent discharge
from the reactors, ownership of the nuclear fuel transfers to CL&P and
WMECO.
CL&P has also entered into lease agreements, some of which are capital
leases, for the use of data processing and office equipment, vehicles, gas
turbines, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options. The
following rental payments have been charged to expense:
Year Capital Leases Operating Leases
1997 ........... $10,457,000 $19,749,000
1996 ........... 17,993,000 22,032,000
1995 ........... 56,307,000 23,793,000
Interest included in capital lease rental payments was $9,948,000 in 1997,
$10,144,000 in 1996 and $10,587,000 in 1995.
Future minimum rental payments, excluding executory costs such as property
taxes, state use taxes, insurance and maintenance, under long-term
noncancelable leases as of December 31, 1997, are:
Year Capital Leases Operating Leases
(Thousands of Dollars)
1998............... $142,500 $ 22,700
1999............... 2,900 21,300
2000............... 2,900 19,900
2001............... 2,900 14,400
2002............... 3,000 6,200
After 2002......... 54,300 22,800
Future minimum lease
payments.............. 208,500 $107,300
Less amount
representing
interest.............. 50,400
Present value of
future minimum
lease payments........ $158,100
Rocky River Realty Company (RRR) provides real estate support services,
including the leasing of properties and facilities, used by NU system
companies, including CL&P. During 1997, RRR repurchased certain notes that
were secured by real estate leases between RRR as lessor and NUSCO as
lessee. The repayment of these notes triggered the acceleration of rent
and CL&P was subsequently billed by NUSCO and paid its proportionate share
of the accelerated lease obligation. At December 31, 1997, CL&P has
recorded long-term prepaid rent of approximately $11.1 million. This asset
is being amortized on a straight line basis and will be fully amortized in
2017.
4. NUCLEAR DECOMMISSIONING
Millstone and Seabrook: CL&P's nuclear power plants have service lives
that are expected to end during the years 2010 through 2026. Upon
retirement, these units must be decommissioned. Current decommissioning
studies concluded that complete and immediate dismantlement at retirement
continues to be the most viable and economic method of decommissioning the
three Millstone units and Seabrook 1. Decommissioning studies are reviewed
and updated periodically to reflect changes in decommissioning
requirements, costs, technology and inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1
and 2, in year-end 1997 dollars, is $390.9 million and $350.2 million,
respectively. CL&P's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 in year-end 1997 dollars,
is $294.0 million and $19.2 million, respectively. The Millstone units
and Seabrook 1 decommissioning costs will be increased annually by their
respective escalation rates. Nuclear decommissioning costs are accrued
over the expected service life of the units and are included in
depreciation expense on the Consolidated Statements of Income. Nuclear
decommissioning costs amounted to $37.8 million each year in 1997 and 1996
and $30.5 million in 1995. Nuclear decommissioning, as a cost of removal,
is included in the accumulated provision for depreciation on the
Consolidated Balance Sheets. At December 31, 1997 and 1996, the balance
in the accumulated reserve for depreciation amounted to $407.3 million and
$329.1 million, respectively.
CL&P has established external decommissioning trusts through a trustee for
its portion of the costs of decommissioning Millstone 1, 2 and 3. CL&P's
portion of the cost of decommissioning Seabrook 1 is paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes levelized
collections for the Millstone units and escalated collections for Seabrook
1 and after-tax earnings on the Millstone and Seabrook decommissioning
funds of approximately 5.5 percent and 6.5 percent, respectively.
As of December 31, 1997, CL&P has collected through rates $277.9 million
toward the future decommissioning costs of its share of the Millstone
units, of which $240.3 million has been transferred to external
decommissioning trusts. As of December 31, 1997, CL&P has paid
approximately $2.9 million into Seabrook 1's decommissioning financing
fund. Earnings on the decommissioning trusts and financing fund increase
the decommissioning trust and the accumulated reserve for depreciation.
Unrealized gains and losses associated with the decommissioning trusts and
financing fund also impact the balance of the trusts and the accumulated
reserve for depreciation.
Changes in requirements or technology, the timing of funding or dismantling
or adoption of a decommissioning method other than immediate dismantlement
would change decommissioning cost estimates and the amounts required to be
recovered. CL&P attempts to recover sufficient amounts through its allowed
rates to cover its expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
regulatory agencies is reflected in CL&P's rates. Based on present
estimates and assuming its nuclear units operate to the end of their
respective license periods, CL&P expects that the decommissioning trusts
and financing fund will be substantially funded when the units are retired
from service.
Millstone 1 has been placed in extended maintenance status while management
is reviewing its options with respect to the unit. These include restart,
early retirement and other options. Relating to management's consideration
of the option to immediately retire Millstone 1 are certain Connecticut
state law issues. In its four-year rate review proceeding, the DPUC noted
that CL&P may not be able to obtain its remaining investment in Millstone 1
if it were to determine that the unit had been prematurely shut down due to
management imprudence. Additionally, there is a Connecticut statute which
may limit CL&P's ability to collect future decommissioning charges related
to Millstone 1 if Millstone 1 were to be terminated before the end of its
expected life.
At December 31, 1997, CL&P's net unrecovered Millstone 1 plant costs were
$215.7 million and the remaining unrecovered decommissioning costs were
approximately $198 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. CL&P's ownership share of
estimated costs, in year-end 1997 dollars, of decommissioning this unit is
$48.0 million.
On August 6, 1997, the board of directors of MYAPC voted unanimously to
cease permanently the production of power at its nuclear generating
facility (MY). The NU system companies had relied on MY for approximately
one percent of their capacity. During November 1997, MYAPC filed an
amendment to its power contracts clarifying the obligations of its
purchasing utilities following the decision to cease power production.
During January 1998, the FERC accepted the amendments and proposed rates,
subject to refund. At December 31, 1997, the remaining estimated
obligation, including decommissioning, amounted to approximately $867.2
million, of which CL&P's share was approximately $104.0 million.
On December 4, 1996, the board of directors of CYAPC voted unanimously
to cease permanently the production of power at its nuclear generating
plant (CY). During 1996, the NU system companies had relied on CY for
approximately three percent of their capacity. During late December 1996,
CYAPC filed an amendment to its power contracts clarifying the obligations
of its purchasing utilities following the decision to cease power
production. On February 27, 1997, the FERC approved an order for hearing
which, among other things, accepted CYAPC's contract amendment. The new
rates became effective March 1, 1997, subject to refund. At December 31,
1997, the remaining estimated obligation, including decommissioning,
amounted to $619.9 million, of which CL&P's share was approximately
$213.8 million.
YAEC is in the process of decommissioning its nuclear facility. At
December 31, 1997, the estimated remaining costs, including
decommissioning, amounted to $124.4 million, of which CL&P's share
was approximately $30.5 million.
Under the terms of the contracts with MYAPC, CYAPC and YAEC, the
shareholder-sponsor companies, including CL&P, are responsible for their
proportionate share of the costs of the units, including decommissioning.
Management expects that CL&P will continue to be allowed to recover these
costs from its customers. Accordingly, CL&P has recognized these costs as
regulatory assets with corresponding obligations.
Proposed Accounting: The staff of the SEC has questioned certain current
accounting practices of the electric utility industry, including CL&P,
regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating units in the financial
statements. In response to these questions, the FASB has agreed to review
the accounting for closure and removal costs, including decommissioning. If
current electric utility industry accounting practices for nuclear power
plant decommissioning are changed, the annual provision for decommissioning
could increase relative to 1997, and the estimated cost for decommissioning
could be recorded as a liability (rather than as accumulated depreciation),
with recognition of an increase in the cost of the related nuclear power
plant. Management believes that CL&P will continue to be allowed to recover
decommissioning costs through rates.
5. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P is
subject to periodic approval by either the SEC under the 1935 Act or by the
DPUC. SEC authorization allowed CL&P, as of January 1, 1998, to incur
total short-term borrowings up to a maximum of $375 million.
Credit Agreements: In May 1997, because of the potential for NU and CL&P
to violate their various financial ratio tests, NU amended the three-year
revolving credit agreement (Credit Agreement) with a group of 12 banks.
Under the amended Credit Agreement, CL&P and WMECO are able to borrow,
subject to the availability of first mortgage bond collateral, up to
$313.75 million and $150 million, respectively. At December 31, 1997, CL&P
and WMECO have issued first mortgage bonds to enable borrowings under this
facility up to a maximum of $225 million and $90 million, respectively.
NU, which cannot issue first mortgage bonds, will be able to borrow up to
$50 million if NU consolidated, CL&P and WMECO each meet certain interest
coverage tests for two consecutive quarters. In addition, CL&P and WMECO
each must meet certain minimum quarterly financial ratios to access the
Credit Agreement. Both CL&P and WMECO satisfied these tests for the
quarter ending December 31, 1997. The overall limit for all of the
borrowing system companies under the entire Credit Agreement is $313.75
million. The companies are obligated to pay a facility fee of .50 percent
per annum of each bank's total commitment under this Credit Agreement which
will expire in November 1999. At December 31, 1997 and 1996, there were
$50 million and $27.5 million, respectively, in borrowings under this
Credit Agreement. Of these amounts, CL&P had $35 million borrowed in 1997
and nothing borrowed in 1996.
In addition to the Credit Agreement, NU, CL&P, WMECO, HWP and RRR have
various revolving credit lines through separate bilateral credit
agreements. Under this facility, four banks maintain commitments to the
respective companies totaling $56.25 million. NU, CL&P and WMECO may borrow
up to the aggregate $56.25 million, whereas HWP and RRR may borrow up to
their SEC or board authorized short-term debt limit of $5 million and $22
million, respectively. Under the terms of this facility, the companies are
obligated to pay a facility fee of .15 percent per annum of each bank's
total commitment. These commitments will expire in December 1998. At
December 31, 1997 and 1996, there were no borrowings and $11.3 million in
borrowings, respectively, under this facility, all of which had been
borrowed by other NU system companies.
Under the credit facilities discussed above, CL&P may borrow funds on a
short-term revolving basis under its agreement, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding.
Standby loans are based upon several alternative variable rates. The
weighted average annual interest rate on CL&P's notes payable to banks
outstanding on December 31, 1997 was 6.95 percent. CL&P had no borrowings
under these facilities at December 31, 1996.
Money Pool: Certain subsidiaries of NU, including CL&P, are members of the
Northeast Utilities System Money Pool (Pool). The Pool provides a more
efficient use of the cash resources of the system, and reduces outside
short-term borrowings. NUSCO administers the Pool as agent for the member
companies. Short-term borrowing needs of the member companies are first
met with available funds of other member companies, including funds
borrowed by NU parent. NU parent may lend to the Pool but may not borrow.
Funds may be withdrawn from or repaid to the Pool at any time without prior
notice. Investing and borrowing subsidiaries receive or pay interest based
on the average daily Federal Funds rate. Borrowings based on loans from NU
parent, however, bear interest at NU parent's cost and must be repaid based
upon the terms of NU parent's original borrowing. At December 31, 1997,
CL&P had $61.3 million of borrowings outstanding from the Pool. At December
31, 1996, CL&P had no borrowings outstanding from the Pool. The interest
rate on borrowings from the Pool on December 31, 1997 was 5.8 percent.
Maturities of short-term debt obligations were for periods of three months
or less. For further information on short-term debt, including the ability
to access these agreements, see the MD&A.
6. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1997 Outstanding
Redemption December 31, December 31,
Description Price 1997 1997 1996 1995
(Thousands of Dollars)
$1.90 Series of 1947 $52.50 163,912 $ 8,196 $ 8,196 $ 8,196
$2.00 Series of 1947 54.00 336,088 16,804 16,804 16,804
$2.04 Series of 1949 52.00 100,000 5,000 5,000 5,000
$2.06 Series E of 1954 51.00 200,000 10,000 10,000 10,000
$2.09 Series F of 1955 51.00 100,000 5,000 5,000 5,000
$2.20 Series of 1949 52.50 200,000 10,000 10,000 10,000
$3.24 Series G of 1968 51.84 300,000 15,000 15,000 15,000
3.90% Series of 1949 50.50 160,000 8,000 8,000 8,000
4.50% Series of 1956 50.75 104,000 5,200 5,200 5,200
4.50% Series of 1963 50.50 160,000 8,000 8,000 8,000
4.96% Series of 1958 50.50 100,000 5,000 5,000 5,000
5.28% Series of 1967 51.43 200,000 10,000 10,000 10,000
6.56% Series of 1968 51.44 200,000 10,000 10,000 10,000
Total preferred stock
not subject to
mandatory redemption $116,200 $116,200 $116,200
All or any part of each outstanding series of such preferred stock may be
redeemed by CL&P at any time at established redemption prices plus accrued
dividends to the date of redemption.
7. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1997 Outstanding
Redemption December 31, December 31,
Description Price* 1997 1997 1996 1995
(Thousands of Dollars)
7.23% Series of 1992 $52.41 1,500,000 $ 75,000 $ 75,000 $ 75,000
5.30% Series of 1993 51.00 1,600,000 80,000 80,000 80,000
155,000 155,000 155,000
Less preferred stock
to be redeemed
within one year......... 75,000 3,750 - -
Total preferred stock
subject to mandatory
redemption.............. $151,250 $155,000 $155,000
*Each of these series is subject to certain refunding limitations for the first
five years after they were issued. Redemption prices reduce in future years.
The following table details redemption and sinking fund activity for preferred
stock subject to mandatory redemption:
Minimum
Annual
Sinking-Fund Shares Reacquired
Series Requirement 1997 1996 1995
(Thousand of Dollars)
9.00% Series of 1989 $ - - - 3,000,000
7.23% Series of 1992 (1) 3,750 - - -
5.30% Series of 1993 (2) 16,000 - - -
(1) Sinking fund requirements commence September 1, 1998.
(2) Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1998 through 2002, aggregate approximately $3.8
million in 1998, and $19.8 million for 1999 through 2002. There were no
minimum sinking-fund provisions in 1997. In case of default on sinking-
fund payments, no payments may be made on any junior stock by way of
dividends or otherwise (other than in shares of junior stock) so long as
the default continues. If CL&P is in arrears in the payment of dividends on
any outstanding shares of preferred stock, CL&P would be prohibited from
redeeming or purchasing less than all of the preferred stock outstanding.
All or part of each of the series named above may be redeemed by CL&P at
any time at established redemption prices plus accrued dividends to the
date of redemption, subject to certain refunding limitations.
8. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
1997 1996
(Thousands of Dollars)
First Mortgage Bonds:
7 5/8% Series UU due 1997............... $ - $193,288
6 1/2% Series T due 1998............... 20,000 20,000
7 1/4% Series VV due 1999............... 99,000 99,000
5 1/2% Series A due 1999............... 140,000 140,000
5 3/4% Series XX due 2000............... 200,000 200,000
7 7/8% Series A due 2001............... 160,000 160,000
7 3/4% Series C due 2002............... 200,000 -
6 1/8% Series B due 2004............... 140,000 140,000
7 3/8% Series TT due 2019............... 20,000 20,000
7 1/2% Series YY due 2023............... 100,000 100,000
8 1/2% Series C due 2024............... 115,000 115,000
7 7/8% Series D due 2024............... 140,000 140,000
7 3/8% Series ZZ due 2025............... 125,000 125,000
Total First Mortgage Bonds......... 1,459,000 1,452,288
Pollution Control Notes:
Variable rate, due 2016-2022.............. 46,400 46,400
Variable tax exempt, due 2028-2031........ 377,500 377,500
Fees and interest due for spent
fuel disposal costs (Note 2M)............. 166,458 157,968
Other....................................... 86 10,915
Less amounts due within one year............ 20,011 204,116
Unamortized premium and discount, net....... (6,117) (6,550)
Long-term debt, net....................... $2,023,316 $1,834,405
Long-term debt and cash sinking-fund requirements on debt outstanding at
December 31, 1997 for the years 1998 through 2002 are approximately $20.0
million, $239.0 million, $200.0 million, $160.0 million and $200.0 million,
respectively. The one-percent sinking- and improvement-fund requirements
for CL&P first mortgage bonds are no longer required, as of 1997, as
determined by a majority of bondholders.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by CL&P at any time at established redemption prices plus accrued
interest to the date of redemption, except certain series which are subject
to certain refunding limitations during their respective initial five-year
redemption periods.
Essentially all of CL&P's utility plant is subject to the lien of its first
mortgage bond indenture. As of December 31, 1997 and 1996, CL&P has
secured $315.5 million of pollution control notes with second mortgage
liens on Millstone 1, junior to the lien of its first mortgage bond
indenture. The average effective interest rate on the variable-rate
pollution control notes ranged from 3.6 percent to 3.7 percent for 1997 and
from 3.4 percent to 3.6 percent for 1996.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds with a
bond insurance and liquidity facility secured by First Mortgage Bonds.
9. INCOME TAX EXPENSE
The components of the federal and state income tax provisions (credited)/
charged to operations are:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Current income taxes:
Federal..................... $(53,339) $30,650 $ 93,906
State....................... (3,270) 9,789 37,898
Total current............. (56,609) 40,439 131,804
Deferred income taxes, net:
Federal..................... 8,436 (22,866) 52,075
State....................... (11,470) (9,409) 5,085
Total deferred............ (3,034) (32,275) 57,160
Investment tax credits, net... (7,366) (7,367) (7,640)
Total income tax
(credit)/expense.......... $(67,009) $ 797 $181,324
The components of total income tax expense are classified as
follows:
Income taxes charged to
operating expenses.......... $(59,436) $ 957 $178,346
Other income taxes............ (7,573) (160) 2,978
Total income tax
(credit)/expense............... $(67,009) $ 797 $181,324
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits and
disposal costs.................. $ 11,991 $ 3,981 $ 44,278
Energy adjustment clauses......... (14,039) (1,654) 23,302
Demand-side management............ (12,408) (17,099) 1,310
Nuclear plant deferrals........... 14,007 (18,861) (8,055)
Bond redemptions.................. (1,339) (1,789) (2,255)
Contractual settlements........... 1,754 2,513 (9,496)
Pension accruals.................. 6,524 2,944 5,382
State net operating loss
carryforwards................... (7,670) - -
Other............................. (1,854) (2,310) 2,694
Deferred income taxes, net........ $ (3,034) $(32,275) $ 57,160
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rate is as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income..... $(72,312) $(18,257) $135,289
Tax effect of differences:
State income taxes, net of
federal benefit............... (8,966) 248 27,939
Depreciation.................... 19,701 21,313 23,517
Deferred nuclear plants return.. (30) (444) (1,639)
Amortization of
regulatory assets ............ 3,901 8,601 20,218
Property tax.................... - - (159)
Investment tax credit
amortization.................. (7,366) (7,367) (7,640)
Adjustment for prior years'
taxes......................... (10) - (10,442)
Other, net...................... (1,927) (3,297) (5,759)
Total income tax
(credits)/expense............... $(67,009) $ 797 $181,324
10. EMPLOYEE BENEFITS
A. PENSION BENEFITS
The NU system's subsidiaries participate in a uniform noncontributory
defined benefit retirement plan covering all regular NU system
employees. Benefits are based on years of service and the employees'
highest eligible compensation during 60 consecutive months of
employment. CL&P's direct portion of the NU system's pension credit,
part of which was credited to utility plant, approximated $22.5
million in 1997, $8.8 million in 1996 and $10.4 million in 1995. The
company's pension (credit)/costs for 1997, 1996 and 1995 included
approximately $(949) thousand, $2.8 million and $0.1 million,
respectively, related to workforce reduction programs.
Currently, CL&P annually funds an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are
determined using market-related values of pension assets. Pension
assets are invested primarily in domestic and international equity
securities and bonds.
The components of net pension credit for CL&P are:
For the Years Ended December 31, 1997 1996 1995
(Thousands of Dollars)
Service cost................... $ 7,888 $ 11,896 $ 7,543
Interest cost.................. 37,939 37,226 37,110
Return on plan assets.......... (148,830) (103,248) (138,582)
Net amortization............... 80,507 45,300 83,516
Net pension credit............. $(22,496) $ (8,826) $(10,413)
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1997 1996 1995
Discount rate................. 7.75% 7.50% 8.25%
Expected long-term
rate of return.............. 9.25 8.75 8.50
Compensation/progression
rate........................ 4.75 4.75 5.00
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31, 1997 and 1996 of
$(420,499,000) and $(405,340,000),
respectively........................ $(451,802) $(434,473)
Projected benefit obligation.......... $(531,564) $(514,989)
Market value of plan assets........... 846,366 736,448
Market value in excess of projected
benefit obligation.................. 314,802 221,459
Unrecognized transition amount........ (6,445) (7,365)
Unrecognized prior service costs...... 3,524 3,818
Unrecognized net gain................. (269,560) (198,088
Prepaid pension asset................. $ 42,321 $ 19,824
The following actuarial assumptions were used in calculating the
plan's year-end funded status:
At December 31, 1997 1996
Discount rate......................... 7.25% 7.75%
Compensation/progression rate......... 4.25 4.75
B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system's subsidiaries provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees (referred to as SFAS 106 benefits).
These benefits are available for employees retiring from the NU system
who have met specified service requirements. For current employees
and certain retirees, the total SFAS 106 benefit is limited to two
times the 1993 per-retiree health care cost. The SFAS 106 obligation
has been calculated based on this assumption. CL&P's direct portion of
SFAS 106 costs, part of which were deferred or charged to utility
plant, approximated $12.8 million in 1997, $17.9 million in 1996 and
$20.7 million in 1995.
During 1997 and 1996, CL&P funded SFAS 106 postretirement costs
through external trusts. CL&P is funding, on an annual basis, amounts
that have been rate-recovered and which also are tax deductible under
the Internal Revenue Code. The trust assets are invested primarily in
equity securities and bonds.
The components of health care and life insurance cost are:
For the Years Ended December 31, 1997 1996 1995
(Thousands of Dollars)
Service cost ...................... $ 1,692 $ 2,270 $ 2,248
Interest cost ..................... 9,152 10,211 11,510
Return on plan assets ............. (7,755) (2,904) (1,015)
Amortization of unrecognized
transition obligation ........... 7,344 7,344 7,344
Other amortization, net ........... 2,370 956 602
Net health care and life
insurance cost .................. $12,803 $17,877 $20,689
For calculating SFAS 106 benefit costs, the following assumptions were
used:
For the Years Ended December 31, 1997 1996 1995
Discount rate ..................... 7.75% 7.50% 8.00%
Long-term rate of return -
Health assets, net of tax ....... 6.00 5.25 5.00
Life assets ..................... 9.25 8.75 8.50
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees ............................ $(102,282) $(109,299)
Fully eligible active employees ..... (219) (165)
Active employees not eligible
to retire ......................... (24,075) (27,913)
Total accumulated postretirement
benefit obligation ................. (126,576) (137,377)
Market value of plan assets .......... 46,055 38,783
Accumulated postretirement benefit
obligation in excess of
plan assets ........................ (80,521) (98,594)
Unrecognized transition amount ....... 110,162 117,506
Unrecognized net gain ................ (29,641) (18,912)
Accrued postretirement benefit
liability .......................... $ - $ -
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
At December 31, 1997 1996
Discount rate ........................ 7.25% 7.75%
Health care cost trend rate (a) ...... 5.76 7.23
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 4.40 percent by 2001.
The effect of increasing the assumed health care cost trend rate by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1997, by $7.3
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$563 thousand. The trust holding the health plan assets is subject to
federal income taxes at a 39.6 percent tax rate. CL&P currently is
recovering SFAS 106 costs through rates.
11. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
During 1996, CL&P entered into an agreement to sell up to $200 million of
undivided ownership interests in eligible customer receivables and accrued
utility revenues (receivables).
The FASB issued SFAS 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," in June 1996. SFAS
125 became effective on January 1, 1997, and establishes, in part, criteria
for concluding whether a transfer of financial assets in exchange for
consideration should be accounted for as a sale or as a secured borrowing.
During October 1997, CL&P restructured its sales agreement to comply with
the conditions of SFAS 125 and account for transactions occurring under
this program as sales of assets. CL&P has established a special purpose,
wholly owned subsidiary whose business consists of the purchase and resale
of receivables. For receivables sold, CL&P has retained collection
responsibilities as agent for the purchaser under CL&P's agreement. As
collections reduce previously sold receivables, new receivables may be
sold. At December 31, 1997, approximately $70 million of receivables had
been sold to a third-party purchaser by CL&P through the use of CL&P's
special purpose, wholly owned subsidiary, CL&P Receivables Corporation
(CRC). All receivables transferred to CRC are assets owned by CRC and are
not available to pay CL&P's creditors.
For CRC's sales agreement with its third-party purchaser, the receivables
are sold with limited recourse. CRC's sales agreement provides for a
formula-based loss reserve in which additional receivables may be assigned
to the third-party purchaser for costs such as bad debt. The third-party
purchaser absorbs the excess amount in the event that actual loss experience
exceeds the loss reserve. At December 31, 1997, approximately $7.2 million
of assets had been designated as collateral by CRC. This amount represents
the formula-based amount of credit exposure at December 31, 1997.
Historical losses for bad debt for CL&P have been substantially less.
CL&P's accounts receivable program could be terminated if its senior secured
debt is downgraded two more steps from its current ratings.
Concentrations of credit risk to the purchaser under the company's agreement
with respect to the receivables are limited due to CL&P's diverse customer
base within its service territory.
For additional information on the accounts receivable program and CL&P's
ability to utilize this program, see the MD&A.
12. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING AND RATE MATTERS
Although CL&P continues to operate under cost-of-service based
regulation, legislative restructuring initiatives during 1997 and 1998
in its jurisdiction has created some uncertainty with respect to future
rates and the recovery of strandable investments and certain future
costs such as purchase power obligations. Management is unable to
predict the ultimate outcome of restructuring initiatives, however, it
continues to believe that it is probable that CL&P will fully recover
its prudently incurred costs, including regulatory assets and
strandable investments based on the general nature of public utility
cost-of-service regulation.
For further information on restructuring, see Note 2H, "Summary of
Significant Accounting Policies - Regulatory Accounting and Assets,"
and the MD&A.
The DPUC is required to review a utility's rates every four years if
there had not been a rate proceeding during such period. The DPUC has
conducted such a review. For information regarding this review and
other rate matters, see the MD&A.
For information regarding the FERC rate proceedings for CYAPC and
MYAPC, see Note 4, "Nuclear Decommissioning."
B. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. Millstone
1, 2 and 3 have been out of service since November 4, 1995, February
21, 1996, and March 30, 1996, respectively, and are on the Nuclear
Regulatory Commission's (NRC) watch list. NU has restructured its
nuclear organization and is currently implementing comprehensive plans
to restart the units.
Subsequent to its January 31, 1996 announcement that Millstone had been
placed on its watch list, the NRC stated that the units cannot return
to service until independent, third-party verification teams have
reviewed the actions taken to improve the design, configuration and
employee concerns issues that prompted the NRC to place the units on
its watch list. The actual date of the return to service for each of
the units is dependent upon the completion of independent inspections
and reviews by the NRC and a vote by the NRC commissioners. NU hopes to
return Millstone 3 to service in the early spring of 1998 and Millstone
2 three to four months after Millstone 3. Millstone 1 is currently in
extended maintenance status.
Management cannot predict when the NRC will allow any of the Millstone
units to return to service and thus cannot precisely estimate the total
replacement power costs CL&P will ultimately incur. Replacement power
costs incurred by CL&P attributable to the Millstone outages averaged
approximately $23 million per month during 1997, and for 1998 are
projected to average approximately $7 million per month for Millstone
3, $7 million per month for Millstone 2 and $5 million per month for
Millstone 1 while the plants remain out of service. CL&P will continue
to expense its replacement power costs in 1998.
Based on the current estimates of expenditures and restart dates,
management believes the NU system has sufficient resources to fund the
restoration of the Millstone units and related replacement power costs.
If the return to service of Millstone 3 or 2 is delayed substantially
beyond the present restart estimates, if some financing facilities
become unavailable because of difficulties in meeting borrowing
conditions or renegotiating extensions, if CL&P and WMECO encounter
additional significant costs or if any other significant deviations
from management's assumptions occur, CL&P and WMECO could be unable to
meet their cash requirements. In those circumstances, management would
take even more stringent actions to reduce costs and cash outflows and
attempt to obtain additional sources of funds. The availability of
these funds would be dependent upon general market conditions and
CL&P's and WMECO's respective credit and financial conditions at that
time.
For information regarding Millstone restart costs, see the MD&A.
For information concerning the ability of CL&P to access its borrowing
facilities, see the MD&A.
Litigation: CL&P and WMECO, through NNECO as agent, operate Millstone
3 at cost, and without profit, under a sharing agreement that obligates
them to utilize good utility operating practice and requires the joint
owners to share the risk of employee negligence and other risks of
operation and maintenance pro-rata in accordance with their ownership
shares. This agreement also provides that CL&P and WMECO would be
liable only for damages to the non-NU owners for a deliberate violation
of the agreement pursuant to authorized corporate action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with CL&P and WMECO as well as lawsuits in Massachusetts
Superior Court against NU and its current and former trustees. The
non-NU owners raise a number of contract, tort and statutory claims
arising out of the operation of Millstone 3. The arbitrations and
lawsuits seek to recover compensatory damages, punitive damages, treble
damages and attorneys' fees. Owners representing approximately two-
thirds of the non-NU interests in Millstone 3 claimed compensatory
damages in excess of $200 million. In addition, one of the lawsuits
seeks to restrain NU from disposing of its shares of the stock of WMECO
and HWP, pending the outcome of the lawsuit. Management cannot estimate
the potential outcome of these suits but believes there is no legal
basis for the claims and intends to defend against them vigorously.
To date, no reserves have been established for this litigation. At
December 31, 1997, the NU system's costs related to this litigation
were estimated to be approximately $100 million for incremental O&M
costs and approximately $100 million for replacement power costs.
These costs are likely to increase as long as Millstone 3 remains out
of service.
The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P
have been negotiating since May 1996 over issues related to the
operation of Millstone 1 and 2. CMEEC has failed to make payments on
its accrued obligations since October 1996, claiming that CL&P
materially breached its contractual obligations. CL&P has denied the
allegations and requested payment. The matter has gone to arbitration
which has been scheduled for July 1998.
CL&P has filed an application with the Connecticut Superior Court in
Hartford requesting the court to grant interim relief to CL&P. CL&P
has asked the court to enforce the contract provisions by ordering
CMEEC to pay the outstanding obligations under the contract
(approximately $25 million) and to continue making payments
(approximately $1.8 million per month) during the arbitration
process.
On December 9, 1997, the Superior Court judge issued a decision denying
CL&P's request for an interim payment order. Management cannot predict
the outcome of this litigation and has taken steps to assert its legal
rights. CL&P has requested reargument, in order to present evidence,
and has requested that the Connecticut Superior Court vacate its order.
CL&P is prepared to appeal to a higher court, if necessary, after the
reargument.
C. ENVIRONMENTAL MATTERS
The NU system is subject to regulation by federal, state and local
authorities with respect to air and water quality, the handling and
disposal of toxic substances and hazardous and solid wastes, and the
handling and use of chemical products. The NU system has an active
environmental auditing and training program and believes that it is in
substantial compliance with current environmental laws and regulations.
However, the NU system is subject to certain pending enforcement
actions and governmental investigations in the environmental area.
Management cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations and
other facilities. Changing environmental requirements could also
require extensive and costly modifications to CL&P's existing
generating units and transmission and distribution systems, and could
raise operating costs significantly. As a result, CL&P may incur
significant additional environmental costs, greater than amounts
included in cost of removal and other reserves, in connection with the
generation and transmission of electricity and the storage,
transportation and disposal of byproducts and wastes. CL&P may also
encounter significantly increased costs to remedy the environmental
effects of prior waste handling activities. The cumulative long-term
cost impact of increasingly stringent environmental requirements cannot
be estimated accurately.
CL&P has recorded a liability based upon currently available
information for what it believes are its estimated environmental
remediation costs that it expects to incur for waste disposal sites.
In most cases, additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown
magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 1997,
the net liability recorded by CL&P for its estimated environmental
remediation costs, excluding any possible insurance recoveries or
recoveries from third parties, amounted to approximately $6.4 million,
which management has determined to be the most probable amount within
the range of $6.4 million to $16.4 million.
During 1997, CL&P adopted Statement of Position 96-1, "Environmental
Remediation Liabilities" (SOP). The principal objective of the SOP
is to improve the manner in which existing authoritative accounting
literature is applied by entities to specific situations of
recognizing, measuring and disclosing environmental remediation
liabilities. The adoption of the SOP resulted in an increase of
approximately $395 thousand to CL&P's environmental reserve in 1997.
CL&P cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against
it. However, considering known facts, existing laws and regulatory
practices, management does not believe the matters disclosed above will
have a material effect on CL&P's financial position or future results
of operations.
D. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at
one of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an owner
of a nuclear unit could be assessed in proportion to its ownership
interest in each of its nuclear units up to $75.5 million. Payments of
this assessment would be limited to $10.0 million in any one year per
nuclear incident based upon the owner's pro rata ownership interest in
each of its nuclear units. In addition, the owner would be subject to
an additional five percent or $3.8 million, in proportion to its
ownership interests in each of its nuclear units, if the sum of all
claims and costs from any one nuclear incident exceeds the maximum
amount of financial protection. Based upon its ownership interests in
Millstone 1, 2 and 3 and in Seabrook 1, CL&P's maximum liability,
including any additional assessments, would be $173.6 million per
incident, of which payments would be limited to $21.9 million per year.
In addition, through power purchase contracts with MYAPC, VYNPC, and
CYAPC, CL&P would be responsible for up to an additional $44.4 million
per incident, of which payments would be limited to $5.6 million per
year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences. CL&P is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessment against CL&P with respect to losses
arising during the current policy year is approximately $11.5 million
under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and the
excess cost of repair, replacement or decontamination or premature
decommissioning of utility property resulting from insured occurrences.
CL&P is subject to retroactive assessments if losses exceed the
accumulated funds available to the insurer. The maximum potential
assessments against CL&P with respect to losses arising during current
policy years are approximately $9.5 million under the replacement power
policies and $15.6 million under the excess property damage,
decontamination and decommissioning policies. The cost of a nuclear
incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry
basis for coverage of worker claims. All participating reactor
operators insured under this coverage are subject to retrospective
assessments of $3 million per reactor. The maximum potential
assessment against CL&P with respect to losses arising during the
current policy period is approximately $8.9 million. Effective
January 1, 1998, a new worker policy was purchased which is not
subject to retrospective assessments.
E. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision by
management. CL&P currently forecasts construction expenditures of
approximately $1.3 billion for the years 1998-2002, including $164.9
million for 1998. In addition, CL&P estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $247.7 million for the years 1998-2002, including $37.6
million for 1998. See Note 3, "Leases," for additional information
about the financing of nuclear fuel.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: CL&P, WMECO and PSNH rely on VY for approximately
1.7 percent of their capacity under long-term contracts. Under the
terms of their agreements, the NU system companies pay their ownership
(or entitlement) shares of costs which include depreciation, O&M
expenses, taxes, the estimated cost of decommissioning and a return on
invested capital. These costs are recorded as purchased power expense
and are recovered through the company's rates. CL&P's total cost of
purchases under contracts with VYNPC amounted to $14.1 million in 1997,
$14.8 million in 1996 and $14.7 million in 1995.
The other Yankee generating facilities, MY, CY and Yankee Rowe, were
permanently shutdown as of August 6, 1997, December 4, 1996 and
February 26, 1992, respectively. See Note 2E, "Summary of Significant
Accounting Policies - Investments and Jointly Owned Electric Utility
Plant," for further information on the Yankee companies, and Note 4,
"Nuclear Decommissioning," regarding the related decommissioning
obligations.
Nonutility Generators: CL&P has entered into various arrangements for
the purchase of capacity and energy from nonutility generators (NUGs).
These arrangements have terms from 10 to 30 years, currently expiring
in the years 2001 through 2028, and require CL&P to purchase energy at
specified prices or formula rates. For the 12-month period ending
December 31, 1997, approximately 14 percent of NU system electricity
requirements was met by NUGs. CL&P's total cost of purchases under
these arrangements amounted to $283.2 million in 1997, $279.5 million
in 1996 and $282.2 million in 1995. These costs may be deferred for
eventual recovery through rates.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH,
WMECO and HWP have entered into agreements to support transmission and
terminal facilities to import electricity from the Hydro-Quebec system
in Canada. CL&P is obligated to pay, over a 30-year period ending in
2020, its proportionate share of the annual O&M and capital costs of
these facilities.
Estimated Annual Costs: The estimated annual costs of CL&P's
significant long-term contractual arrangements are as follows:
1998 1999 2000 2001 2002
(Millions of Dollars)
VYNPC ............. $ 16.8 $ 16.9 $ 16.2 $ 17.7 $ 18.4
NUGs ............. 281.0 291.5 290.9 295.5 299.6
Hydro-Quebec ...... 18.5 17.9 17.6 17.1 16.7
For additional information regarding the recovery of purchased power
costs, see Note 2J, "Summary of Significant Accounting Policies -
Recoverable Energy Costs."
13. MARKET RISK MANAGEMENT
CL&P uses swap, collar, put and call instruments with financial
institutions to hedge against some of the fuel price risk created by long-
term negotiated energy contracts and nuclear replacement power generation
and fuel purchases. These agreements minimize exposure associated with
rising fuel prices by managing a portion of CL&P's cost of fuel for these
negotiated energy contracts and nuclear replacement power generation and
fuel purchases. As of December 31, 1997, CL&P had outstanding agreements
with a total notional value of approximately $327 million, and a negative
mark-to-market position of approximately $21 million.
The terms of the agreements require CL&P to post cash collateral with its
counterparties in the event of negative mark-to-market positions and
lowered credit ratings. The amount of the collateral is to be returned to
CL&P when the mark-to-market position becomes positive, when CL&P meets
specified credit ratings or when an agreement ends and all open positions
are properly settled. At December 31, 1997, cash collateral in the amount
of $15.4 million was posted under these terms, which is included in other,
at cost, on the accompanying Consolidated Balance Sheets.
These agreements have been made with various financial institutions, each
of which is rated "A1" or better by Moody's rating group. CL&P will be
exposed to credit risk on its fuel price management instruments if the
counterparties fail to perform their obligations. However, management
anticipates that the counterparties will be able to fully satisfy their
obligations under the agreements.
14. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities
(MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a
general partner, and is the guarantor of the MIPS securities. Subsequent
to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance,
along with CL&P's $3.1 million capital contribution, back to CL&P in the
form of an unsecured debenture. CL&P consolidates CL&P LP for financial
reporting purposes. Upon consolidation, the unsecured debenture is
eliminated and the MIPS securities are accounted for as minority interests.
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate
fair value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity
Securities," requires investments in debt and equity securities to be
presented at fair value. As a result of this requirement, the investments
held in CL&P's nuclear decommissioning trusts were adjusted to market by
approximately $49.2 million as of December 31, 1997, and $22.3 million as
of December 31, 1996, with corresponding offsets to the accumulated
provision for depreciation. The amounts adjusted in 1997 and 1996 represent
cumulative gross unrealized holding gains. The cumulative gross unrealized
holding losses were immaterial for both 1997 and 1996.
Preferred stock and long-term debt: The fair value of CL&P's fixed rate
securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair
value equal to their carrying value.
The carrying amounts of CL&P's financial instruments and the estimated fair
values are as follows:
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock not subject
to mandatory redemption..................... $ 116,200 $ 62,889
Preferred stock subject to
mandatory redemption........................ 155,000 135,600
Long-term debt -
First Mortgage Bonds........................ 1,459,000 1,435,772
Other long-term debt........................ 590,443 590,443
MIPS.......................................... 100,000 100,760
Carrying Fair
At December 31, 1996 Amount Value
(Thousands of Dollars)
Preferred stock not subject
to mandatory redemption...................... $ 116,200 $ 111,845
Preferred stock subject to
mandatory redemption......................... 155,000 120,900
Long-term debt -
First Mortgage Bonds......................... 1,452,288 1,410,665
Other long-term debt......................... 592,783 592,783
MIPS ............................................ 100,000 108,520
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
The Connecticut Light and Power Company and Subsidiaries
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets, as restated -
see Note 1, of The Connecticut Light and Power Company and Subsidiaries (a
Connecticut corporation and a wholly owned subsidiary of Northeast
Utilities) as of December 31, 1997 and 1996, and the related consolidated
statements of income, common stockholder's equity and cash flows, as
restated - see Note 1, for each of the three years in the period ended
December 31, 1997. These financial statements are the responsibility of
the company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of The Connecticut Light
and Power Company and Subsidiaries as of December 31, 1997 and 1996, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1997, in conformity with generally
accepted accounting principles.
As explained in Note 1 to the consolidated financial statements, the
company has given retroactive effect to the change in accounting for
nuclear compliance costs.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in
Note 1, as to which the date is June 10, 1998).
THE CONNECTICUT LIGHT AND POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section contains management's assessment of CL&P's (the company) financial
condition and the principal factors having an impact on the results of
operations. The company is a wholly-owned subsidiary of Northeast Utilities
(NU). This discussion should be read in conjunction with the company's
consolidated financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
The length of the ongoing outages at the three Millstone nuclear plants
(Millstone) and the high costs of the recovery efforts weakened CL&P's 1997 net
income, balance sheet and cash flows and will continue to have an adverse impact
on the company's financial condition until the units are returned to service.
CL&P had a net loss of approximately $140 million in 1997, compared to a net
loss of approximately $51 million in 1996. The poorer financial results in 1997
were due primarily to the fact that all three Millstone units were off line for
the entire year in 1997 and spending associated with the recovery efforts was
significantly higher in 1997 than it was in 1996. Millstone 3 operated for
nearly three months in 1996 and Millstone 2 for nearly two months. As a result,
the cost of replacing power ordinarily generated by the Millstone units rose by
approximately $65 million in 1997. The total operation and maintenance (O&M)
costs at Millstone were approximately $173 million higher in 1997.
The higher Millstone costs have caused CL&P to focus closely on maintaining
adequate liquidity and reducing nonnuclear O&M costs. In June 1997, CL&P
successfully sold $200 million in first mortgage bonds. CL&P's access to $225
million of revolving credit lines was renegotiated in the first half of 1997.
Also helping to maintain liquidity was the renegotiation in early 1998 of a $100
million credit line used by Niantic Bay Fuel Trust (NBFT) to purchase nuclear
fuel for Millstone. Additionally, nonnuclear O&M expenses in 1997 were reduced
by about $30 million from 1996.
The SEC has advised CL&P to adjust for certain costs associated with the ongoing
Millstone outages as they are incurred. For the past two years, CL&P has been
reserving for the unavoidable costs they expected to incur to meet NRC
requirements. These annual statements have been adjusted in accordance with the
SEC's directive. Management does not expect implementation of this accounting
change to affect the ability of CL&P and Western Massachusetts Electric Company
(WMECO) to meet their financial covenants contained in their $313.75 million
revolving credit arrangement.
In 1998, management expects Millstone-related expenses to fall significantly,
assuming Millstone 3 and Millstone 2 are returned to service at dates close to
current estimates, although the O&M expenses at Millstone 3 and 2 will be
considerably higher than before the station was placed on the Nuclear Regulatory
Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at
Millstone will depend on when the units return to operation and the cost of
restoring them to service. The company hopes to restart Millstone 3, the newest
and largest unit at the site, in the early spring of 1998 and Millstone 2 three
to four months after Millstone 3. The company cannot restart the Millstone units
until it receives formal approval from the NRC. As part of an effort to reduce
spending in 1998, Millstone 1 has been placed in extended maintenance status.
Management will review its options with respect to Millstone 1 in 1998,
including restart, early retirement and other options.
Rate reductions to customers served by CL&P are likely to offset a portion of
the benefit of lower Millstone-related costs. On March 1, 1998, CL&P's rates
were reduced by approximately 1.4 percent to reflect the removal of Millstone 1
from rates, and additional non cash reductions were made to revenue requirements
as a result of an interim rate order issued by the Connecticut Department of
Public Utility Control (DPUC). A pending CL&P rate case may result in
additional rate adjustments later in 1998. CL&P's revenues could be further
reduced if substantial delays in restarting Millstone 3 and Millstone 2 result
in a DPUC decision to remove those units from rates.
In addition to focusing on maintaining liquidity, management also must attend to
industry restructuring efforts in Connecticut. Restructuring legislation is
being considered in the Connecticut legislative session that began in February
1998.
In 1997, CL&P experienced modest economic growth in its retail sales that was
offset by the effects of mild winter weather. In 1998, management expects that
the Connecticut economy will continue to experience modest growth.
MILLSTONE
OUTAGES
CL&P has an 81-percent ownership interest in Millstone units 1 and 2 and a
52.93-percent ownership interest in Millstone unit 3. Millstone 1, 2 and 3 have
been out of service since November 4, 1995, February 21, 1996, and March 30,
1996, respectively.
Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC has stated that the units cannot return to service
until independent, third-party verification teams have reviewed the actions
taken to improve the design, configuration and employee concern issues that
prompted the NRC to place the units on its watch list. The actual date of the
return to service for each of the units is dependent upon the completion of
independent inspections, reviews by the NRC and a vote by the NRC Commissioners.
In January 1998, NU declared Millstone 3 physically ready for restart, which
meant that almost all of the restart-required physical work had been completed
in the plant. The NRC currently is conducting a series of inspections to
determine, among other things, whether the plant has effective leadership and
corrective action and employee concerns programs. The Independent Corrective
Action Verification Program, an NRC-ordered independent review of the plant's
design and licensing bases, is expected to be completed in March 1998.
In 1997, CL&P's share of nonfuel O&M costs expensed for Millstone increased to
approximately $445 million, compared to approximately $272 million in 1996.
CL&P's portion of replacement power costs attributable to the Millstone outages
totaled approximately $281 million in 1997 compared to $216 million expensed in
1996. These costs for 1998 are forecasted to average approximately $7 million
per month for Millstone 3, $7 million per month for Millstone 2 and $5 million
per month for Millstone 1 while the plants are out of service.
CL&P has been, and will continue to be, expensing all of the costs to restart
the units including replacement power and nonfuel O&M expenses. See "Rate
Matters" for issues related to the recovery of Millstone 1 costs.
NU and its subsidiaries are involved in several class action lawsuits and other
litigation in connection with their nuclear operations. See the "Notes to
Consolidated Financial Statements," Note 12B, for further information on this
litigation.
MILLSTONE 1
Management will review its options with respect to Millstone 1 during 1998. The
issues that management will consider in evaluating its options include the costs
to restart the unit, the economic benefits of the unit's continued operation and
certain Connecticut state law issues. In the CL&P four year rate review
proceeding, (discussed in detail under "Rate Matters"), the DPUC noted that CL&P
may not be able to recover its remaining investment in Millstone 1 if the DPUC
were to determine that the unit had been prematurely shut down due to management
imprudence. Additionally, there is a Connecticut statute which may limit CL&P's
ability to collect decommissioning charges in the future if Millstone 1 were to
be prematurely retired.
CL&P's net unrecovered Millstone 1 plant cost and the unrecovered
decommissioning costs at December 31, 1997, were approximately $216 million and
$198 million, respectively.
CAPACITY
During 1996 and continuing into 1997, CL&P took measures to improve its capacity
position, including obtaining additional generating capacity, improving the
availability of CL&P's generating units and improving its transmission
capability. During 1997, CL&P spent approximately $48 million to ensure
availability in Connecticut of adequate generating capacity in Connecticut, of
which $35 million was expensed. During 1998 these costs are expected to be
approximately $11 million.(DO WE WANT TO SAY WHY 1998 IS SO MUCH LOWER )In 1998,
CL&P does not anticipate the need to take additional measures to ensure adequate
generating capacity.
CL&P could incur up to an additional $50 million in 1998 for incremental
capacity purchases to meet NEPOOL requirements as a result of the Millstone
outages.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $227 million in 1997,
compared to 1996, primarily due to higher cash expenditures related to the
Millstone outages, and the pay down in 1997 of the 1996 year end accounts
payable balance. The 1996 year end accounts payable balance was relatively high
due to costs related to a severe December storm and costs associated with the
Millstone outages that had been incurred but not yet paid by the end of 1996.
Net cash from financing activities increased approximately $69 million,
primarily due to an increase in short-term borrowings and lower cash dividends
on common shares, partially offset by higher long-term debt retirements. Cash
used for investments decreased approximately $158 million, primarily due to
lower investments in the NU system Money Pool, partially offset by higher
capital expenditures and an increase in special deposits.
CL&P established facilities in 1996 under which it may sell, from time to time,
up to $200 million of its accounts receivable and accrued utility revenues. As
of December 31, 1997, CL&P sold approximately $70 million of receivables to
third-party purchasers.
NU's, CL&P's and WMECO's three-year revolving credit agreement (Credit
Agreement) was amended in May 1997 (the Credit Agreement). Under the Revolving
Credit Agreement, CL&P and WMECO are able to borrow up to approximately $225
million and $90 million, respectively, subject to a total borrowing limit of
$313.75 million for all three borrowers. NU will be able to borrow up to $50
million when NU, CL&P and WMECO have each maintained a consolidated operating
income to consolidated interest expense ratio of at least 2.50 to 1 for two
consecutive fiscal quarters. Currently, the companies cannot meet this
requirement. At December 31, 1997, CL&P had $35 million outstanding under the
New Credit Agreement.
Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has
any financing agreements containing cross defaults based on financial defaults
by NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy
Corporation (NAEC). Nevertheless, it is possible that investors will take
negative operating results or regulatory developments for one subsidiary of NU
into account when evaluating the other NU subsidiaries. That could, as a
practical matter and despite the contractual and legal separations among NU and
its subsidiaries, negatively affect the company's access to financial markets.
In December 1997 and January 1998, Moody's Investors Service (Moody's) and
Standard & Poor's (S&P), respectively, downgraded the senior secured debt of
CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was
the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since
the Millstone units went on the NRC watch list in 1996. All of NU system's
securities are rated below investment grade and remain under review for further
downgrade. CL&P's accounts receivable program could be terminated if its senior
secured debt is downgraded two more steps from its current ratings. Although
CL&P does not have any plans to issue debt in the near term, rating agency
downgrades generally increase the future cost of borrowing funds because lenders
will want to be compensated for increased risk. Additionally, this could affect
the terms and ability of the company to extend existing agreements.
CL&P's ability to borrow under the financing arrangements is dependent on the
satisfaction of contractual borrowing conditions. The financial covenants that
must be satisfied to permit CL&P and WMECO to borrow under the New Credit
Agreement are particularly restrictive and become more restrictive throughout
1998. Spending levels in 1998, particularly for the first half of the year while
the Millstone units are expected to be out of service, will be constrained to
levels intended to assure that the financial covenants in CL&P's and WMECO's
Credit Agreement are satisfied. However, there is no assurance that these
financial covenants will be met as the system may encounter additional
unexpected costs from such areas as storms, reduced revenues from regulatory
actions or the effect of weather on sales levels.
If the return to service of Millstone 3 or Millstone 2 is delayed substantially
beyond the present restart estimates, if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions or
renegotiating extensions, if the system encounters additional significant costs,
or any other significant deviations from management's current assumptions, the
currently available borrowing facilities could be insufficient to meet all of
CL&P's cash requirements. In those circumstances, management would take even
more stringent actions to reduce costs and cash outflows and would attempt to
take other actions to obtain additional sources of funds. The availability of
these funds would be dependent upon the general market conditions and CL&P's
credit and financial condition at that time.
RESTRUCTURING
CL&P continues to operate under cost-of-service based regulation, however,
future rates and the recovery of strandable costsinvestments are issues that are
being considered as part of broad restructuring legislation in the current
Connecticut legislative session. Strandable costs are expenditures or
commitments that have been made to meet public service obligations with the
expectation that they would be recovered from customers in the future. CL&P has
has exposure to strandable costs for itsits investments in high-cost nuclear
generating plants, state-mandated purchased power obligations and significant
regulatory assets. The company's exposure to strandable investments and
purchased power obligations exceeds its shareholder's equity. CL&P's financial
strength and resulting ability to compete in a restructured environment will be
negatively affected if the company is unable to recover its past investments and
commitments. Even if the company is given the opportunity to recover a large
portion of its strandable costs, earnings prospects in a restructured
environment will be affected in ways which cannot be estimated at this time.
The company is seeking to mitigate the impacts of restructuring by proposing
stable, lower rates, while pursuing customer choice options and full recovery of
itsits strandable costsinvestments. The company's strategy to recover
strandable costsinvestments includes efforts to promote state legislation that
will authorize the issuance of rate reduction bonds that would refinance these
investments and which would be repaid through non-bypassable charges to
customers. Management is unable to predict the ultimate outcome of these
initiatives which will be subject to regulatory and legislative approvals.
Management believes it is entitled to full recovery of its prudently incurred
costs, including regulatory assets and other strandable costs. See the "Notes
to Consolidated Financial Statements," Note 2H, for the potential accounting
impacts of restructuring.
RATE MATTERS
In July 1996, the DPUC approved a rate settlement agreement with CL&P (the
Settlement). Under the Settlement, CL&P froze base rates until at least
December 31, 1997, and agreed to accelerate the amortization of regulatory
assets during the period that the rate freeze remains in effect. The Settlement
provided that CL&P's target return on equity (ROE) would be 10.7 percent but did
not alter CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a
calendar year exceeds 10.7 percent after the target regulatory asset
amortization ($68 million in 1997) and after adjustment for any incremental NRC
billings and any rate disallowances for nuclear operations, then CL&P shall
retain two-thirds of any surplus and use the remaining one-third to provide a
reduction in bills. CL&P's actual ROE, as adjusted, fell below the target ROE
for 1996 and 1997 and, therefore, the accelerated amortization of regulatory
assets was reduced to the minimum amounts allowed under the Settlement ($73
million in 1996 and $54 million in 1997). For each full year that the rate
freeze remains in effect, CL&P agreed to amortize an additional $44 million of
regulatory assets.
On July 30, 1997, the DPUC issued a decision in its prudence review of nuclear
cost recovery issues disallowing CL&P's recovery of all of the replacement power
costs associated with the ongoing outages at Millstone. CL&P has expensed, and
will continue to expense, replacement power costs for the Millstone outages as
they are incurred.
The DPUC is required to review a utility's rates every four years if there has
not been a rate proceeding during such period. In 1997, the DPUC conducted such
a review of CL&P's rates, including an analysis of the possibility of removing
one or more of the Millstone nuclear units from CL&P's rate base. On December
31, 1997, the DPUC issued its ruling in this matter. The decision did not effect
a change in CL&P's rates, but set forth findings and conclusions that could be
used to do so in additional proceedings. The most significant conclusion was
that Millstone 1 should be removed from CL&P's rate base, which would cause an
annual revenue reduction of approximately $30.5 million. The decision stated
that the DPUC would open an interim rate case immediately to remove Millstone 1
from CL&P's rates and simultaneously to remove an additional $110.5 million of
other expenses from rates related to perceived overearnings. On February 25,
1998, the DPUC issued a decision reducing CL&P's rates by approximately 1.4
percent to reflect the removal of Millstone 1 from rates. This reduction
reflects the removal from rates of O&M, depreciation and investment return
related to Millstone 1, net of replacement power costs. In addition, the
decision requires CL&P to accelerate the amortization of regulatory assets by
$110.5 million, which includesing the $44 million from the 1996 Settlement. The
interim rate reduction became effective on March 1, 1998.
CL&P also was directed to file a full rate case on June 1, 1998, to address
potential overearnings amounting to an additional $150 million in 1998. The
effective date of any rate order will be September 28, 1998. In addition, the
DPUC has scheduled hearings for April 1, 1998 to determine the status of
Millstone 3 and Millstone 2. If the units are not operating by that date, the
DPUC will consider their removal from rates. A similar restart status hearing is
anticipated for June 1, 1998.
The DPUC also will consider CL&P's analyses of the economic benefits of the
continued operation of Millstone 1 and 2 in the context of CL&P's next
integrated resource planning proceeding, which begins in April 1998.
NUCLEAR DECOMMISSIONING
CONNECTICUT YANKEE
CL&P has a 34.5 percent ownership interest in the Connecticut Yankee nuclear
generating facility (CY or the plant). On December 4, 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease
permanently the production of power at the plant. The decision to retire CY from
commercial operation was based on an economic analysis of the costs of operating
it compared to the costs of closing it and incurring replacement power costs
over the remaining period of the plant's operating license, which would have
expired in 2007. The economic analysis showed that closing the plant and
incurring replacement power costs produced substantial savings.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December 1996, CY filed an amendment to its power
contracts with the FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1997, CL&P's
share of these obligations was approximately $214 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that the
company will continue to be allowed to recover such FERC approved costs from its
customers. Accordingly, CL&P has recognized its share of the estimated costs as
a regulatory asset, with a corresponding obligation, on its balance sheets.
MAINE YANKEE
CL&P has a 12 percent ownership interest in the Maine Yankee (MY) nuclear
generating facility. On August 6, 1997, the Board of Directors of Maine Yankee
Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14,
1998, FERC released a draft order on the MYAPC application to amend its power
contracts with the owner/purchasers and revise its decommissioning and other
charges. FERC has accepted the proposed application for filing and made the
amendments and the proposed charges under the contracts effective on January 15,
1998, subject to refund after hearings. At December 31, 1997, CL&P's share of
the estimated remaining obligation, including decommissioning, amounted to
approximately $104 million. Under the terms of the contracts with MYAPC, the
shareholders' sponsor companies, including CL&P, are responsible for their
proportionate share of the costs of the unit, including decommissioning.
Management expects that CL&P will be allowed to recover these costs from it's
customers. Accordingly, CL&P has recognized these costs as a regulatory asset,
with a corresponding obligation on its balance sheet.
MILLSTONE AND SEABROOK
CL&P's estimated cost to decommission its shares of the Millstone plants and
Seabrook is approximately $1.1 billion in year end 1997 dollars. These costs are
being recognized over the lives of the respective units with a portion currently
being recovered through rates. As of December 31, 1997, CL&P's share of the
market value of the contributions already made to the decommissioning trusts,
including their investment returns, was approximately $369 million.
See the "Notes to Consolidated Financial Statements," Note 4, for further
information on nuclear decommissioning, including the CL&P's share of costs to
decommission the other regional nuclear generating units.
ENVIRONMENTAL MATTERS
CL&P is potentially liable for environmental cleanup costs at a number of sites
inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of CL&P. At December 31, 1997, CL&P had recorded
an environmental reserve of approximately $6.4 million. See the "Notes to
Consolidated Financial Statements," Note 12C, for further information on
environmental matters.
YEAR 2000 ISSUE
The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU's systems to process critical financial and operational
information incorrectly. The NU system has assessed and continues to assess the
impact of the Year 2000 issue on its operating and reporting systems. The
assessment of the nuclear operating systems is continuing and is expected to be
completed in the summer of 1998.
The NU system will utilize both internal and external resources to reprogram or
replace, and test the software for Year 2000 modifications. The total estimated
remaining cost of the Year 2000 project for the NU system is $37 million and is
being funded through operating cash flows. This estimate does not include any
costs for the replacement or repair of equipment or devices that may be
identified during the assessment process. The majority of these costs will be
expensed as incurred over the next two years. To date, the NU system has
incurred and expensed approximately $4 million related to the assessment of and
preliminary efforts in connection with its Year 2000 project.
The costs of the project and the date on which the NU system plans to complete
the Year 2000 modifications are based on management's best estimates, which were
derived utilizing numerous assumptions of future events, including the continued
availability of certain resources, third-party modification plans and other
factors. However, there can be no guarantee that these estimates will be
achieved, and actual results could differ materially from those plans. If the
NU system's remediation plan is not successful, there could be a significant
disruption of the company's operations.
RISK-MANAGEMENT INSTRUMENTS
The following discussion about the company's risk-management activities includes
forward-looking statements that involve risk and uncertainties. Actual results
could differ materially from those projected in the forward-looking statements.
This analysis presents the hypothetical loss in earnings related to the fuel
price and interest rate market risks not covered by the risk- management
instruments at December 31, 1997. The company uses swaps, collars, puts, and
calls to manage the market risk exposures associated with changes in fuel prices
and variable interest rates. The company does not use these risk-management
instruments for speculative purposes. For more information on CL&P's use of
risk management instruments, see the "Notes to Consolidated Financial
Statements," Note 13.
In the generation of electricity, the most significant variable cost component
is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by
a regulatory fuel price adjustment clause. However, for a specific, well-defined
volume of fuel that is excluded from the fuel price adjustment clause
(unprotected volume), CL&P employs fuel price risk-management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks are created by the sale of
long-term, fixed-price electricity contracts to wholesale customers and the
purchase or generation of replacement power related to the ongoing Millstone
nuclear outages.
At December 31, 1997, CL&P had outstanding agreements with a total notional
value of approximately $327 million. The settlement amounts associated with the
instruments reduced fuel expense by approximately $7.8 million.
CL&P has had experience using various fuel price risk-management instruments
since 1994, most of which have been in the form of fuel price swaps. At
December 31, 1997 approximately 30 percent of the unprotected volume was covered
by fuel price risk-management instrument (hedge ratio) for 1997. This
effectively fixed or bounded the fuel cost and thus eliminated the market price
risk for this covered volume of fuel. At December 31, 1997, the company had a
hedge ratio of 44 percent for 1998.
At December 31, 1997, the 56 percent uncovered volume of fuel for 1998, as a
result of not being hedged, is subject to changes in actual market prices.
Therefore, assuming a hypothetical 10 percent increase in the average 1997 price
of fuel in 1998, the result would be a negative pre-tax impact on earnings of
approximately $12.4 million.
This analysis is based on the broad assumption that the entire uncovered volume
of fuel remains constant and will be purchased the spot market. This assumption
is subject to change as the uncovered volume of fuel likely will change during
the next year. Other assumptions used in this analysis, projections of the fuel
mix, the amount of long-term sales contracts or the projected Millstone restart
dates, also are subject to change.
RESULTS OF OPERATIONS
Income Statement Variances
(Millions of Dollars)
1997 over/(under) 1996 1996 over/(under) 1995
Amount Percent Amount Percent
Operating revenues $ 68 3% $ 10 - %
Fuel, purchased and net
interchange power 146 18 222 37
Other operation (1) - 113 18
Maintenance 56 19 107 56
Amortization of regulatory
assets, net 4 7 3 6
Federal and state income
taxes (68) (a) (181) (100)
Other income, net (23) (a) 6 42
Net income (89) (a) (256) (a)
(a) Percentage greater than 100
OPERATING REVENUES
Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $33
million, primarily due to a higher fuel adjustment clause rate in 1997.
Conservation recoveries increased by $17 million primarily due to a 1996 reserve
for over-recoveries of demand-side-management costs. Retail kilowatt hour sales
were essentially unchanged in 1997.
Total operating revenues increased in 1996, primarily due to higher retail sales
and regulatory decisions, partially offset by lower fuel recoveries and lower
wholesale revenues. Retail sales increased 1.8 percent ($29 million) primarily
due to modest economic growth in 1996. Regulatory decisions increased revenues
by $15 million primarily due to the mid-1995 retail rate increase, partially
offset by 1996 reserves for over-recoveries of demand-side management costs.
Fuel recoveries decreased $24 million primarily due to lower average fossil fuel
prices. Wholesale revenues decreased $18 million primarily due to higher
recognition in 1995 of lump-sum payments for the termination of a long-term
contract and capacity sales contracts that expired in 1995.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 1997, primarily
due to replacement power costs associated with the Millstone outages and the
expensing in 1997 of replacement power costs incurred in 1996.
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to replacement power due to the nuclear outages and the 1996 write-off of
the generation utilization adjustment clause (GUAC) balances under the
Settlement, partially offset by lower nuclear generation and the timing of the
recognition of costs under the company's fuel clauses.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($173 million), higher
charges from Maine Yankee ($9 million), partially offset by lower recognition of
nuclear refueling outage costs primarily as a result of the 1996 Rate Settlement
($72 million), lower capacity charges from Connecticut Yankee as a result of a
property tax refund ($27 million), lower administrative and general expenses
($23 million) primarily due to lower pensions and benefit costs and lower storm
expenses.
Other operation and maintenance expenses increased in 1996, primarily due to
higher costs associated with the Millstone restart effort ($93 million) and
higher 1996 costs to ensure adequate generating capacity ($39 million). In
addition, 1996 costs reflect higher storm and reliability expenditures, higher
recognition of conservation expenses and higher marketing costs.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 1997, primarily due to the
completion of cogeneration deferrals in 1996 and increased amortization in 1997,
partially offset by the completion of CL&P's Seabrook amortization in 1996.
Amortization of regulatory assets, net increased in 1996, primarily due to lower
cogeneration deferrals and the accelerated amortization of regulatory assets as
a result of the Settlement, partially offset by the completion of the Millstone
3 phase-in amortization in 1995.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased in 1997 and 1996, primarily due to
lower book taxable income.
OTHER INCOME, NET
Other income, net decreased in 1997, primarily due to cost associated with the
accounts receivable facility, nonutility marketing and advertising costs and
lower miscellaneous income.
Other income, net increased in 1996, primarily due to higher income on temporary
cash investments in 1996.
The Connecticut Light and Power Company and Subsidiaries
SELECTED FINANCIAL DATA(a)
1997 1996 1995 1994 1993
(Restated) (Restated)
(Thousands of Dollars)
Operating
Revenues....... $2,465,587 $2,397,460 $2,387,069 $2,328,052 $2,366,050
Operating (Loss)/
Income......... (7,619) 59,142 324,026 286,948 241,655
Net (Loss)/Income (139,597) (50,868) 205,216 198,288 191,449(b)
Cash Dividends on
Common Stock... 5,989 138,608 164,154 159,388 160,365
Total Assets..... 6,081,223 6,244,036 6,045,631 6,217,457 6,397,405
Long-Term Debt(c) 2,043,327 2,038,521 1,822,018 1,823,690 2,057,280
Preferred Stock
Not Subject to
Mandatory
Redemption.... 116,200 116,200 116,200 166,200 166,200
Preferred Stock
Subject to
Mandatory
Redemption(c). 155,000 155,000 155,000 230,000 230,000
Obligations Under
Capital Leases(c) 158,118 155,708 172,264 175,969 177,418
SEGMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated)
Quarter Ended(a)
1997 March 31 June 30 September 30 December 31
Operating Revenues $624,908 $574,841 $627,712 $638,126
Operating Income/(Loss) $ 9,943 $(19,659) $ 1,365 $ 732
Net Loss $(19,636) $(50,161) $(33,160) $(36,640)
1996
Operating Revenues $659,355 $542,999 $599,505 $595,601
Operating Income/(Loss) $ 77,641 $ 19,895 $ (3,051) $(35,343)
Net Income/(Loss) $ 50,515 $ (6,002) $(30,582) $(64,799)
(a) Reclassifications of prior data have been made to conform with the
current presentation.
(b) Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares by
$47.7 million.
(c) Includes portion due within one year.
The Connecticut Light and Power Company and Subsidiaries
STATISTICS
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31)
1997 $6,639,786 26,766 8,526 1,103,309 2,163
1996 6,512,659 26,043 8,639 1,099,340 2,194
1995 6,389,190 26,366 8,506(a) 1,094,527 2,270
1994 6,327,967 26,975 8,775 1,086,400 2,587
1993 6,214,401 26,107 8,519 1,078,925 2,676
(a) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.
EXHIBIT 13.3
WESTERN MASSACHUSETTS ELECTRIC COMPANY
AND SUBSIDIARY
AMENDED 1997 ANNUAL REPORT
Western Massachusetts Electric Company and Subsidiary
Amended 1997 Annual Report
Index
Contents Page
Consolidated Balance Sheets (Restated)............................... 2-3
Consolidated Statements of Income (Restated)......................... 4
Consolidated Statements of Cash Flows (Restated)..................... 5
Consolidated Statements of Common Stockholder's
Equity (Restated).................................................... 6
Notes to Consolidated Financial Statements (Restated)................ 7
Report of Independent Public Accountants............................. 39
Management's Discussion and Analysis of Financial
Condition and Results of Operations (Restated)..................... 40
Selected Financial Data (Restated)................................... 51
Statements of Quarterly Financial Data (Restated).................... 51
Statistics........................................................... 52
Preferred Stockholder and Bondholder Information.....................Back Cover
PART I. FINANCIAL INFORMATION
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................. $ 1,284,288 $ 1,257,097
Less: Accumulated provision for depreciation.......... 559,119 503,989
------------- ------------
725,169 753,108
Construction work in progress............................ 19,038 15,968
Nuclear fuel, net........................................ 30,907 30,296
------------- ------------
Total net utility plant.............................. 775,114 799,372
------------- ------------
Other Property and Investments:
Nuclear decommissioning trusts, at market................ 102,708 83,611
Investments in regional nuclear generating
companies, at equity.................................... 15,741 15,448
Other, at cost........................................... 4,900 4,367
------------- ------------
123,349 103,426
------------- ------------
Current Assets:
Cash..................................................... 105 67
Investments in securitizable assets...................... 25,280 -
Receivables, less accumulated provision for
uncollectible accounts of $50,000 in 1997
and of $2,121,000 in 1996.............................. 2,739 40,168
Accounts receivable from affiliated companies............ 3,933 3,525
Taxes receivable......................................... 10,768 1,778
Accrued utility revenues................................. - 12,394
Fuel, materials and supplies, at average cost............ 5,860 5,317
Prepayments and other.................................... 14,945 12,262
------------- ------------
63,630 75,511
------------- ------------
Deferred Charges:
Regulatory assets........................................ 211,377 210,852
Unamortized debt expense................................. 2,695 1,866
Other.................................................... 2,963 888
------------- ------------
217,035 213,606
------------- ------------
Total Assets......................................... $ 1,179,128 $ 1,191,915
============= ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$25 par value--authorized and
outstanding 1,072,471 shares in 1997 and 1996.......... $ 26,812 $ 26,812
Capital surplus, paid in................................ 151,171 150,911
Retained earnings (Note 1).............................. 58,608 104,212
------------- ------------
Total common stockholder's equity.............. 236,591 281,935
Cumulative preferred stock--
$100 par value-- authorized 1,000,000 shares;
outstanding 200,000 shares in 1997 and 1996;
$25 par value--authorized 3,600,000 shares;
outstanding 840,000 shares in 1997 and 1996
Preferred stock not subject to mandatory redemption..... 20,000 20,000
Preferred stock subject to mandatory redemption......... 19,500 21,000
Long-term debt.......................................... 386,849 334,742
------------- ------------
Total capitalization........................... 662,940 657,677
------------- ------------
Obligations Under Capital Leases.......................... 217 29,269
------------- ------------
Current Liabilities:
Notes payable to banks.................................. 15,000 -
Notes payable to affiliated company..................... 14,350 47,400
Long-term debt and preferred stock--current
portion................................................ 11,300 14,700
Obligations under capital leases--current
portion................................................ 32,670 2,965
Accounts payable........................................ 30,571 26,698
Accounts payable to affiliated companies................ 21,209 20,256
Accrued taxes........................................... 522 2,659
Accrued interest........................................ 3,318 5,643
Other................................................... 2,446 4,754
------------- ------------
131,386 125,075
------------- ------------
Deferred Credits:
Accumulated deferred income taxes....................... 246,453 249,886
Accumulated deferred investment tax credits............. 23,364 24,833
Deferred contractual obligations........................ 93,628 84,598
Other................................................... 21,140 20,577
------------- ------------
384,585 379,894
------------- ------------
Commitments and Contingencies (Note 12)
------------- ------------
Total Capitalization and Liabilities........... $ 1,179,128 $ 1,191,915
============= ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996
(Restated) (Restated) 1995
- ---------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues............................. $ 426,447 $ 421,337 $ 420,434
---------- ---------- ----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power. 140,976 115,691 86,738
Other..................................... 153,399 136,897 143,000
Maintenance.................................. 81,466 56,201 37,447
Depreciation................................. 39,753 39,710 37,924
Amortization of regulatory assets, net....... 6,428 9,170 19,562
Federal and state income taxes............... (15,142) 10,628 14,060
Taxes other than income taxes................ 19,316 19,850 18,639
---------- ---------- ----------
Total operating expenses (Note 1)...... 426,196 388,147 357,370
---------- ---------- ----------
Operating Income............................... 251 33,190 63,064
---------- ---------- ----------
Other Income:
Equity in earnings of regional nuclear
generating companies....................... 1,524 1,800 1,771
Other, net................................... (1,106) 1,153 1,232
Income taxes................................. 1,026 1,068 262
---------- ---------- ----------
Other income, net...................... 1,444 4,021 3,265
---------- ---------- ----------
Income before interest charges......... 1,695 37,211 66,329
---------- ---------- ----------
Interest Charges:
Interest on long-term debt................... 26,046 24,094 26,840
Other interest............................... 3,109 2,028 356
---------- ---------- ----------
Interest charges, net.................. 29,155 26,122 27,196
---------- ---------- ----------
Net (Loss)/Income (Note 1)..................... $ (27,460) $ 11,089 $ 39,133
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net (Loss)/Income........................................... $ (27,460) $ 11,089 $ 39,133
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 39,753 39,710 37,924
Deferred income taxes and investment tax credits, net..... (1,256) 1,195 3,418
Deferred Millstone 3 return............................... - - 7,146
Recoverable energy costs, net of amortization............. (8,184) (10,517) 1,285
Amortization of nuclear refueling outage, net of deferrals 8,819 6,188 (8,857)
Other sources of cash..................................... 27,804 21,248 32,266
Other uses of cash........................................ (21,215) (10,271) (8,039)
Changes in working capital:
Receivables and accrued utility revenues ................ 29,415 (1,853) (1,933)
Fuel, materials and supplies.............................. (543) (203) (285)
Accounts payable.......................................... 4,826 20,875 (11,669)
Sale of receivables and accrued utility revenues.......... 20,000 - -
Investment in securitizable assets........................ (25,280) - -
Accrued taxes............................................. (2,137) (805) (3,474)
Other working capital (excludes cash)..................... (16,882) (8,144) 1,256
----------- ----------- -----------
Net cash flows from operating activities (Note 1)............. 27,660 68,512 88,171
----------- ----------- -----------
Financing Activities:
Issuance of long-term debt.................................. 60,000 - -
Net (decrease)/increase in short-term debt.................. (18,050) 23,350 24,050
Reacquisitions and retirements of long-term debt............ (14,700) - (34,550)
Reacquisitions and retirements of preferred stock........... - (36,500) (15,675)
Cash dividends on preferred stock........................... (3,140) (5,305) (4,944)
Cash dividends on common stock.............................. (15,004) (16,494) (30,223)
----------- ----------- -----------
Net cash flows from/(used for) financing activities........... 9,106 (34,949) (61,342)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (26,249) (23,468) (27,084)
Nuclear fuel.............................................. (8) 541 75
----------- ----------- -----------
Net cash flows used for investments in plant................ (26,257) (22,927) (27,009)
NU System Money Pool........................................ - - 8,750
Investment in nuclear decommissioning trusts................ (9,645) (9,794) (8,503)
Other investment activities, net............................ (826) (977) 46
----------- ----------- -----------
Net cash flows used for investments........................... (36,728) (33,698) (26,716)
----------- ----------- -----------
Net Increase/(Decrease) In Cash For The Period................ 38 (135) 113
Cash - beginning of period.................................... 67 202 89
----------- ----------- -----------
Cash - end of period.......................................... $ 105 $ 67 $ 202
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 28,711 $ 21,725 $ 25,551
=========== =========== ===========
Income taxes................................................ $ (1,121) $ 7,816 $ 14,385
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust...................................... $ 660 $ 669 $ 7,851
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings(a)
Stock Paid In (Note 1) Total
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1995............... $26,812 $149,683 $111,586 $288,081
Net income for 1995.................. 39,133 39,133
Cash dividends on preferred
stock.............................. (4,944) (4,944)
Cash dividends on common stock....... (30,223) (30,223)
Loss on the retirement of preferred
stock.............................. (256) (256)
Capital stock expenses, net.......... 499 499
-------- --------- --------- ---------
Balance at December 31, 1995............. 26,812 150,182 115,296 292,290
Net income for 1996 (Note 1)......... 11,089 11,089
Cash dividends on preferred
stock.............................. (5,305) (5,305)
Cash dividends on common stock....... (16,494) (16,494)
Loss on the retirement of preferred
stock.............................. (374) (374)
Capital stock expenses, net.......... 729 729
-------- --------- --------- ---------
Balance at December 31, 1996 (Restated).. 26,812 150,911 104,212 281,935
Net loss for 1997 (Note 1)........... (27,460) (27,460)
Cash dividends on preferred
stock.............................. (3,140) (3,140)
Cash dividends on common stock....... (15,004) (15,004)
Capital stock expenses, net.......... 260 260
-------- --------- --------- ---------
Balance at December 31, 1997 (Restated).. $26,812 $151,171 $ 58,608 $236,591
======== ========= ========= =========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1997, these restrictions totaled
approximately $21.5 million.
The accompanying notes are an integral part of these financial statements.
Western Massachusetts Electric Company and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SECURITIES AND EXCHANGE COMMISSION INQUIRY
In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC)
inquired into Northeast Utilities'(NU) accounting for nuclear compliance costs.
These costs are the unavoidable incremental costs associated with the current
nuclear outages required to be incurred prior to restart of the units in
accordance with correspondence received from the Nuclear Regulatory Commission
(NRC) early in 1996. The SEC's view is that these unavoidable costs associated
with nuclear outages and procedures to be implemented at nuclear power plants in
response to regulatory requirements required prior to restart of the units
should be expensed as incurred. During 1996 and 1997, NU and its wholly owned
subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service
Company of New Hampshire (PSNH) and Western Massachusetts Electric Company
(WMECO), reserved for these unavoidable incremental costs that they expected to
incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to
reflect these costs as they are incurred. While NU and its independent auditors,
Arthur Andersen LLP, believed the accounting was required by, and was in
accordance with, generally accepted accounting principles, NU has agreed to
adjust its accounting for nuclear compliance costs and amend its 1996 and 1997
Form 10-K filings. The financial statements in this report have been restated
to reflect the change in accounting.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT WESTERN MASSACHUSETTS ELECTRIC COMPANY
Western Massachusetts Electric Company and Subsidiary (WMECO or the
company), CL&P, Holyoke Water Power Company (HWP), PSNH and North
Atlantic Energy Corporation (NAEC) are the operating subsidiaries
comprising the Northeast Utilities system (the NU system) and are
wholly owned by NU.
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire and western Massachusetts through CL&P, PSNH,
WMECO and HWP. The fifth wholly owned subsidiary, NAEC, sells all of
its entitlement to the capacity and output of the Seabrook nuclear power
plant (Seabrook) to PSNH. In addition to its franchised retail service,
the NU system furnishes firm and other wholesale electric services to
various municipalities and other utilities, and participates in limited
retail access programs, providing off-system retail electric service.
The NU system serves about 30 percent of New England's electric needs
and is one of the 25 largest electric utility systems in the country as
measured by revenues.
Other wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company (NUSCO) provides centralized
accounting, administrative, information resources, engineering,
financial, legal, operational, planning, purchasing and other services
to the NU system companies. Northeast Nuclear Energy Company (NNECO)
acts as agent for the NU system companies and other New England
utilities in operating the Millstone nuclear generating facilities. In
addition, CL&P and WMECO each have established a special purpose
subsidiary whose business consists of the purchase and resale of
receivables. For information regarding WMECO's subsidiary, see Note 11,
"Sale of Customer Receivables and Accrued Utility Revenues."
B. PRESENTATION
The consolidated financial statements of WMECO include the accounts of
its wholly owned subsidiary. Significant intercompany transactions have
been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and are
subject to approval by various federal and state regulatory agencies.
C. PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935
(1935 Act). NU and its subsidiaries, including WMECO, are subject to
the provisions of the 1935 Act. Arrangements among the NU system
companies, outside agencies and other utilities covering inter-
connections, interchange of electric power and sales of utility property
are subject to regulation by the Federal Energy Regulatory Commission
(FERC) and/or the SEC. WMECO is subject to further regulation for
rates, accounting, and other matters by the FERC and/or the applicable
state regulatory commissions.
For information regarding proposed changes in the nature of industry
regulation, see Note 12A, "Commitments and Contingencies - Restructuring
and Rate Matters."
D. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) 129, "Disclosure of Information
about Capital Structure." SFAS 129 establishes standards for disclosing
information about an entity's capital structure. WMECO's current
disclosures are consistent with the requirements of SFAS 129.
During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive
Income" and SFAS 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS 130 establishes standards for the reporting
and disclosure of comprehensive income. To date, WMECO has not had
material transactions that would be required to be reported as
comprehensive income. SFAS 131 determines the standards for reporting
and disclosing qualitative and quantitative information about a
company's operating segments. This information includes segment profit
or loss, certain segment revenue and expense items and segment assets
and a reconciliation of these segment disclosures to corresponding
amounts in the company's general purpose financial statements. WMECO
currently evaluates management performance using a cost-based budget,
and the information required by SFAS 131 is not available. Therefore,
these disclosure requirements are not applicable. Management believes
that the implementation of SFAS 130 and SFAS 131 will not have a
material impact on WMECO's current disclosures.
See Note 11, "Sale of Customer Receivables and Accrued Utility
Revenues," and Note 12C, "Commitments and Contingencies -- Environmental
Matters," for information on other newly issued accounting and reporting
standards related to those specific areas.
E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: WMECO owns common stock of four
regional nuclear generating companies (Yankee companies). WMECO's
investments in the Yankee companies are accounted for on the equity
basis due to WMECO's ability to exercise significant influence over
their operating and financial policies. The Yankee companies, with
WMECO's ownership interests, are:
Connecticut Yankee Atomic Power Company (CYAPC) ............... 9.5%
Yankee Atomic Electric Company (YAEC) ......................... 7.0
Maine Yankee Atomic Power Company (MYAPC) ..................... 3.0
Vermont Yankee Nuclear Power Corporation (VYNPC) .............. 2.5
WMECO's investments in the Yankee companies at December 31, 1997 are:
(Thousands of Dollars)
CYAPC .............................................. $10,552
YAEC ............................................... 1,465
MYAPC .............................................. 2,370
VYNPC .............................................. 1,354
-------
$15,741
-------
Each Yankee company owns a single nuclear generating unit. Under the
terms of the contracts with the Yankee companies, the shareholders-
sponsors are responsible for their proportionate share of the costs of
each unit, including decommissioning. The energy and capacity costs
from VYNPC and nuclear decommissioning costs of the Yankee companies
that have been shut down are billed as purchased power to WMECO.
The electricity produced by the Vermont Yankee nuclear generating
facility (VY) is committed substantially on the basis of ownership
interests and is billed pursuant to contractual agreements. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently on
February 26, 1992, December 4, 1996, and August 6, 1997, respectively.
Under ownership agreements with the Yankee companies, WMECO may be asked
to provide direct or indirect financial support for one or more of the
companies. For more information on the Yankee companies, see Note 3,
"Nuclear Decommissioning," and Note 12F, "Commitments and Contingencies
--Long-Term Contractual Arrangements."
Millstone 1: WMECO has a 19 percent joint-ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of
December 31, 1997 and 1996, plant-in-service included approximately $91
million and $90.2 million, respectively, and the accumulated provision
for depreciation included approximately $40.1 million and $37.2 million,
respectively, for WMECO's share of Millstone 1. WMECO's share of
Millstone 1 expenses is included in the corresponding operating expenses
on the accompanying Consolidated Statements of Income.
Millstone 2: WMECO has a 19 percent joint-ownership interest in
Millstone 2, a 870-MW nuclear generating unit. As of December 31, 1997
and 1996, plant-in-service included approximately $162.4 million and
$161.4 million, respectively, and the accumulated provision for
depreciation included approximately $57.6 million and $51.7 million,
respectively, for WMECO's share of Millstone 2. WMECO's share of
Millstone 2 expenses is included in the corresponding operating expenses
on the accompanying Consolidated Statements of Income.
Millstone 3: WMECO has a 12.24 percent joint-ownership interest in
Millstone 3, a 1,154-MW nuclear generating unit. As of December 31,
1997 and 1996, plant-in-service included approximately $378.7 million
and $377.7 million, respectively, and the accumulated provision for
depreciation included approximately $110.1 million and $99.8 million,
respectively, for WMECO's share of Millstone 3. WMECO's share of
Millstone 3 expenses is included in the corresponding operating expenses
on the accompanying Consolidated Statements of Income.
The three Millstone units are out of service. NU hopes to return
Millstone 3 to service in the early spring of 1998 and Millstone 2 three
to four months after Millstone 3. Millstone 1 has been placed in
extended maintenance status. Management is reviewing its options with
respect to Millstone 1, including restart, early retirement and other
options. In a draft ruling issued in February 1998, the Connecticut
Department of Public Utility Control (DPUC) determined that Millstone 1
was no longer "used and useful" and ordered it removed from rate base.
For more information regarding the Millstone units, see Note 3, "Nuclear
Decommissioning," and Note 12B, "Commitments and Contingencies - Nuclear
Performance."
F. DEPRECIATION
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agency.
Except for major facilities, depreciation rates are applied to the
average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is
retired from service, the original cost of plant, including costs of
removal, less salvage, is charged to the accumulated provision for
depreciation. The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.2 percent in
1997 and 1996 and 3.1 percent in 1995. See Note 3, "Nuclear
Decommissioning," for information on nuclear plant decommissioning.
WMECO's nonnuclear generating facilities have limited service lives.
Plant may be retired in place or dismantled based upon expected future
needs, the economics of the closure and environmental concerns. The
costs of closure and removal are incremental costs and, for financial
reporting purposes, are accrued over the life of the asset as part of
depreciation. At December 31, 1997 and 1996, the accumulated provision
for depreciation included approximately $3.2 million, respectively,
accrued for the cost of removal, net of salvage for nonnuclear
generation property.
G. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, commercial and industrial customers, utility revenues are
based on authorized rates applied to each customer's use of electricity.
In general, rates can be changed only through a formal proceeding before
the appropriate regulatory commission. Regulatory commissions also have
authority over the terms and conditions of nontraditional rate-making
arrangements. At the end of each accounting period, WMECO accrues an
estimate for the amount of energy delivered but unbilled.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of WMECO and the accompanying consolidated
financial statements conform to generally accepted accounting principles
applicable to rate-regulated enterprises and reflect the effects of the
rate-making process in accordance with SFAS 71, "Accounting for the
Effects of Certain Types of Regulation." Assuming a cost-of-service
based regulatory structure, regulators may permit incurred costs,
normally treated as expenses, to be deferred and recovered through
future revenues. Through their actions, regulators also may reduce or
eliminate the value of an asset, or create a liability. If any portion
of WMECO's operations were no longer subject to the provisions of SFAS
71, as a result of a change in the cost-of-service based regulatory
structure or the effects of competition, WMECO would be required to
write off related regulatory assets and liabilities unless there is a
formal transition plan which provides for the recovery, through
established rates, for the collection of approved stranded costs and to
maintain the cost-of-service basis for the remaining regulated
operations. At the time of transition, WMECO would be required to
determine any impairment to the carrying costs of deregulated plant and
inventory assets.
The staff of the SEC has had concerns regarding the appropriateness of
the utilities' ability to continue application of SFAS 71 for the
generation portion of their business in a restructured environment. The
SEC referred the issue to the Emerging Issues Task Force (EITF) of the
FASB which reached a consensus and issued "Deregulation of the Pricing
of Electricity - Issues Related to the Application of FASB Statements
No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the future
recognition of regulatory assets for the portion of the business that no
longer qualifies for application of SFAS 71 depends on the regulators'
treatment of the recovery of those costs and other stranded assets from
cash flows of other portions of the business still considered to be
regulated, and (2) a utility should discontinue the application of SFAS
71 when a legislative and regulatory plan has been enacted, which would
include transition plans into a competitive environment, and when the
stranded costs which are subject to future rate recovery are determined.
EITF 97-4 became effective in August 1997.
Electric utility industry restructuring within the state of
Massachusetts will be effective March 1, 1998. WMECO has submitted its
proposed restructuring plan to the Massachusetts Department of
Telecommunications and Energy (DTE), formerly the Massachusetts
Department of Public Utilities. If the DTE approves the plan in its
current form, WMECO would discontinue the application of SFAS 71.
However, the restructuring legislation enacted by the state of
Massachusetts specifically provides for future deferrals and the cost
recovery of generation-related assets as contemplated under the plan.
As such, WMECO is not expected to have to write off either its
generation-related assets or related regulatory assets. WMECO's
generation-related regulatory assets were valued at approximately $188
million at December 31, 1997. The majority of WMECO's regulatory assets
are related to its generation business.
For more information on the WMECO's regulatory environment and the
impacts of restructuring, see Note 12A, "Commitments and Contingencies-
Restructuring and Rate Matters," and Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A).
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," requires the evaluation of long-
lived assets, including regulatory assets, for impairment when certain
events occur or when conditions exist that indicate the carrying amounts
of assets may not be recoverable. SFAS 121 requires that any long-lived
assets which are no longer probable of recovery through future revenues
be revalued based on estimated future cash flows. If this revaluation is
less than the book value of the asset, an impairment loss would be
charged to earnings.
Management continues to believe it is probable that WMECO will recover
its investments in long-lived assets through future revenues. This
conclusion may change in the future as the implementation of
restructuring plans within Massachusetts will generally require the
formation of a separate generation entity that will be subject to
competitive market conditions. As a result, WMECO will be required to
assess the carrying amounts of its long-lived assets in accordance with
SFAS 121.
The components of WMECO's regulatory assets are as follows:
At December 31, 1997 1996
(Thousands of Dollars)
Income taxes, net (Note 2I) ..................... $ 63,716 $ 71,519
Unrecovered contractual obligations
(Note 3) ...................................... 93,628 84,598
Recoverable energy costs (Note 2J) .............. 26,270 17,510
Other ........................................... 27,763 37,225
$211,377 $210,852
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods
in which transactions affect income in the financial statements and the
periods in which they affect the determination of taxable income) is
accounted for in accordance with the ratemaking treatment of the
applicable regulatory commissions. See Note 8, "Income Tax Expense" for
the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, which give rise
to the accumulated deferred tax obligation is as follows:
At December 31, 1997 1996
(Restated)(Restated)
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences ................. $223,038 $218,389
Regulatory assets - income tax gross up ......... 30,175 29,457
Other ........................................... (6,760) 2,040
$246,453 $249,886
J. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for
its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary current
cost of fuel, to be fully recovered in rates, like any other fuel cost.
WMECO is currently recovering these costs through rates. As of December
31, 1997, WMECO's total D&D deferrals were approximately $11.3 million.
WMECO has a fuel adjustment clause (FAC) which includes energy costs
along with capacity and transmission charges and credits that result
from short-term transactions with other utilities and from certain FERC-
approved contracts among the NU system's operating companies. The
Massachusetts restructuring legislation will effectively eliminate the
FAC, effective March 1, 1998.
On August 20, 1997, WMECO filed with the DTE a joint motion for approval
of a settlement agreement with the Massachusetts Attorney General which
allowed WMECO to recover approximately $15.3 million of fuel costs for
the period September 1997 through February 1998. Under the current FAC
rate, WMECO continues to defer significant costs for future recovery.
At December 31, 1997, WMECO's net recoverable energy costs were
approximately $26.3 million, which includes approximately $11.3 million
of costs related to WMECO's share of the D&D assessment.
For additional information regarding recoverable energy costs see the
MD&A.
K. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, WMECO must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear fuel
and high-level radioactive waste. The DOE is responsible for the
selection and development of repositories for, and the disposal of,
spent nuclear fuel and high-level radioactive waste. Fees for nuclear
fuel burned on or after April 7, 1983, are billed currently to customers
and paid to the DOE on a quarterly basis. For nuclear fuel used to
generate electricity prior to April 7, 1983 (prior-period fuel), payment
must be made prior to the first delivery of spent fuel to the DOE.
Until such payment is made, the outstanding balance will continue to
accrue interest at the three-month Treasury Bill Yield Rate. At
December 31, 1997, fees due to the DOE for the disposal of prior-period
fuel were approximately $39.0 million, including interest costs of $23.4
million.
The DOE was originally scheduled to begin accepting delivery of spent
fuel in 1998. However, delays in identifying a permanent storage site
have continually postponed plans for the DOE's long-term storage and
disposal site. Extended delays or a default by the DOE could lead to
consideration of costly alternatives. The company has primary
responsibility for the interim storage of its spent nuclear fuel.
Current capability to store spent fuel at Millstone 1 and 2 are
estimated to be adequate until 2004. Storage facilities for Millstone 3
are expected to be adequate for the projected life of the unit. Meeting
spent fuel storage requirements beyond these periods could require new
and separate storage facilities, the costs for which have not been
determined.
In November 1997, the U.S. District Court of Appeals for the D.C.
Circuit ruled that the lack of an interim storage facility does not
excuse the DOE from meeting its contractual obligation to begin
accepting spent nuclear fuel no later than January 31, 1998. Currently,
the DOE has not taken the spent nuclear fuel as scheduled and, as a
result, may have to pay contract damages. The ultimate outcome of this
legal proceeding is uncertain at this time.
3. NUCLEAR DECOMMISSIONING
Millstone: WMECO's nuclear power plants have service lives that are
expected to end during the years 2010 through 2025. Upon retirement, these
units must be decommissioned. Current decommissioning studies concluded that
complete and immediate dismantlement at retirement continues to be the most
viable and economic method of decommissioning the three Millstone units.
Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning WMECO's ownership share of
Millstone 1, 2 and 3, in year-end 1997 dollars, is $91.7 million, $82.1
million and $67.8 million, respectively. The Millstone units decommissioning
costs will be increased annually by their respective escalation rates.
Nuclear decommissioning costs are accrued over the expected service life of
the units and are included in depreciation expense on the Consolidated
Statements of Income. Nuclear decommissioning costs amounted to $6.2 million
in 1997 and 1996 and $5.0 million in 1995. Nuclear decommissioning, as a
cost of removal, is included in the accumulated provision for depreciation
on the Consolidated Balance Sheets. At December 31, 1997 and 1996, the
balance in the accumulated reserve for depreciation amounted to $102.7
million and $83.6 million, respectively.
WMECO has established external decommissioning trusts through a trustee for
its portion of the costs of decommissioning Millstone 1, 2 and 3. Funding
of the estimated decommissioning costs assumes levelized collections for the
Millstone units and after-tax earnings on the Millstone decommissioning
funds of approximately 5.5 percent.
As of December 31, 1997, WMECO has collected, through rates, $59.7 million
toward the future decommissioning costs of its share of the Millstone units,
all of which has been transferred to external decommissioning trusts.
Earnings on the decommissioning trusts increase the decommissioning trust
balance and the accumulated reserve for depreciation. Unrealized gains and
losses associated with the decommissioning trusts also impact the balance of
the trust and the accumulated reserve for depreciation.
Changes in requirements or technology, the timing of funding or dismantling,
or adoption of a decommissioning method other than immediate dismantlement
would change decommissioning cost estimates and the amounts required to be
recovered. WMECO attempts to recover sufficient amounts through its allowed
rates to cover its expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
regulatory agencies is reflected in rates of WMECO. Based on present
estimates and assuming its nuclear units operate to the end of their
respective license periods, WMECO expects that the decommissioning trusts
will be substantially funded when the units are retired from service.
Millstone 1 has been placed in extended maintenance status while management
is reviewing its options with respect to the unit. These include restart,
early retirement and other options. Relating to management's consideration
of the option to immediately retire Millstone 1 are certain Connecticut state
law issues which relate to WMECO as minority owner. In its four-year rate
review proceeding, the DPUC noted that CL&P may not be able to obtain its
remaining investment in Millstone 1 if it were to determine that the unit had
been prematurely shut down due to management imprudence. Additionally, there
is a Connecticut statute which may limit CL&P's ability to collect future
decommissioning charges related to Millstone 1 if Millstone 1 were to be
terminated before the end of its expected life.
At December 31, 1997, WMECO's net unrecovered Millstone 1 plant costs were
$50.9 million and the remaining unrecovered decommissioning costs were
approximately $44 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. WMECO's ownership share of
estimated costs, in year-end 1997 dollars, of decommissioning this unit is
$12.6 million.
On August 6, 1997, the board of directors of MYAPC voted unanimously to
cease permanently the production of power at its nuclear generating facility
(MY). The NU system companies had relied on MY for approximately one
percent of their capacity. During November 1997, MYAPC filed an amendment
to its power contracts clarifying the obligations of its purchasing
utilities following the decision to cease power production. During January
1998, the FERC accepted the amendments and proposed rates, subject to
refund. At December 31, 1997, the remaining estimated obligation, including
decommissioning, amounted to approximately $867.2 million, of which WMECO's
share was approximately $26.0 million.
On December 4, 1996, the board of directors of CYAPC voted unanimously to
cease permanently the production of power at its nuclear generating plant
(CY). During 1996, the NU system companies had relied on CY for
approximately three percent of their capacity. During late December 1996,
CYAPC filed an amendment to its power contracts clarifying the obligations
of its purchasing utilities following the decision to cease power
production. On February 27, 1997, the FERC approved an order for hearing
which, among other things, accepted CYAPC's contract amendment. The new
rates became effective March 1, 1997, subject to refund. At December 31,
1997, the remaining estimated obligation, including decommissioning,
amounted to $619.9 million, of which WMECO's share was approximately $58.9
million.
YAEC is in the process of decommissioning its nuclear facility. At December
31, 1997, the estimated remaining costs, including decommissioning, amounted
to $124.4 million, of which WMECO's share was approximately $8.7 million.
Under the terms of the contracts with MYAPC, CYAPC and YAEC, the
shareholder-sponsor companies, including WMECO, are responsible for their
proportionate share of the costs of the units, including decommissioning.
Management expects that WMECO will continue to be allowed to recover these
costs from its customers. Accordingly, WMECO has recognized these costs as
regulatory assets, with corresponding obligations.
Proposed Accounting: The staff of the SEC has questioned certain current
accounting practices of the electric utility industry, including WMECO,
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating units in the financial statements. In response
to these questions, the FASB has agreed to review the accounting for closure
and removal costs, including decommissioning. If current electric utility
industry accounting practices for nuclear power plant decommissioning are
changed, the annual provision for decommissioning could increase relative to
1997, and the estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation), with recognition of an
increase in the cost of the related nuclear power plant. Management
believes that WMECO will continue to be allowed to recover decommissioning
costs through rates.
4. SHORT-TERM DEBT
Limits: The amount of short-term debt borrowings that may be incurred by
WMECO is subject to periodic approval by either the SEC under the 1935 Act
or by the DTE. SEC authorization allowed WMECO, as of January 1, 1998, to
incur short-term borrowings up to a maximum of $150 million. In addition,
the charter of WMECO contains a provision which restricts the total amount
of unsecured debt that it may borrow at any one time. As of January 1,
1998, this charter provision allowed WMECO to incur unsecured borrowings,
whether short-term or long-term, up to a maximum of approximately $114
million.
Credit Agreements: In May 1997, because of the potential for NU and CL&P to
violate their various financial ratio tests, NU amended the three-year
revolving credit agreement (Credit Agreement) with a group of 12 banks.
Under the amended Credit Agreement, CL&P and WMECO are able to borrow,
subject to the availability of first mortgage bond collateral, up to $313.75
million and $150 million, respectively. At December 31, 1997, CL&P and
WMECO have issued first mortgage bonds to enable borrowings under this
facility up to a maximum of $225 million and $90 million, respectively.
NU, which cannot issue first mortgage bonds, will be able to borrow up to
$50 million if NU consolidated, CL&P and WMECO each meet certain interest
coverage tests for two consecutive quarters. In addition, CL&P and WMECO
each must meet certain minimum quarterly financial ratios to access the
Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter
ending December 31, 1997. The overall limit for all of the borrowing system
companies under the entire Credit Agreement is $313.75 million. The
companies are obligated to pay a facility fee of .50 percent per annum of
each bank's total commitment under this Credit Agreement which will expire
in November 1999. At December 31, 1997 and 1996, there were $50 million and
$27.5 million, respectively, in borrowings under this Credit Agreement. Of
these borrowings, $15 million were borrowed by WMECO in 1997 and none were
borrowed by WMECO in 1996.
In addition to the Credit Agreement, NU, CL&P, WMECO, HWP and The Rocky
River Realty Company (RRR) have various revolving credit lines through
separate bilateral credit agreements. Under this facility, four banks
maintain commitments to the respective companies totaling $56.25 million.
NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas
HWP and RRR may borrow up to their SEC or board authorized short-term debt
limit of $5 million and $22 million, respectively. Under the terms of this
facility, the companies are obligated to pay a facility fee of .15 percent
per annum of each bank's total commitment. These commitments will expire in
December 1998. At December 31, 1997 and 1996, there were no borrowings
and $11.3 million in borrowings, respectively, under this facility.
Under the credit facilities discussed above, WMECO may borrow funds on a
short-term revolving basis under its respective agreements, using either
fixed-rate loans or standby loans. Fixed rates are set using competitive
bidding. Standby loans are based upon several alternative variable rates.
The weighted average annual interest rate on WMECO's notes payable to banks
outstanding on December 31, 1997 was 6.95 percent. WMECO had no borrowings
under these facilities at December 31, 1996.
Money Pool: Certain subsidiaries of NU, including WMECO, are members of the
Northeast Utilities System Money Pool (Pool). The Pool provides a more
efficient use of the cash resources of the system, and reduces outside
short-term borrowings. NUSCO administers the Pool as agent for the member
companies. Short-term borrowing needs of the member companies are first met
with available funds of other member companies, including funds borrowed by
NU parent. NU parent may lend to the Pool but may not borrow. Funds may be
withdrawn from or repaid to the Pool at any time without prior notice.
Investing and borrowing subsidiaries receive or pay interest based on the
average daily Federal Funds rate. However, borrowings based on loans from
NU parent bear interest at NU parent's cost and must be repaid based upon
the terms of NU parent's original borrowing. At December 31, 1997 and 1996,
WMECO had $14.4 million and $47.4 million, respectively, of borrowings
outstanding from the Pool. The interest rate on borrowings from the Pool at
December 31, 1997 and 1996 was 5.8 percent and 6.3 percent, respectively.
Maturities of short-term debt obligations were for periods of three months
or less.
For further information on short-term debt, including the ability to access
these agreements, see the MD&A.
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemptions are:
December 31 Shares
1997 Outstanding
Redemption December 31, December 31,
Description Price 1997 1997 1996 1995
(Thousands of Dollars)
7.72% Series B
of 1971 ........... $103.51 200,000 $20,000 $20,000 $20,000
1988 Adjustable
Rate DARTS ........ - - - - 33,500
Total preferred
stock not subject
to mandatory
redemption ........ $20,000 $20,000 $53,500
All or any part of each outstanding series of preferred stock may be
redeemed by the company at any time at established redemption prices plus
accrued dividends to the date of redemption.
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31 Shares
1997 Outstanding
Redemption December 31, December 31,
Description Price* 1997 1997 1996 1995
(Thousands of Dollars)
7.60% Series
of 1987 ........... $25.64 840,000 $21,000 $21,000 $24,000
Less preferred stock to
be redeemed within one
year, net of reacquired
stock .............. 60,000 1,500 - 1,500
Total preferred stock
subject to mandatory
redemption ......... $19,500 $21,000 $22,500
*Redemption price reduces in future years.
The minimum sinking-fund provisions of the 1987 Series subject to mandatory
redemption at December 31, 1997, for the years 1998 through 2002 is $1.5
million per year. In case of default on sinking-fund payments, no payments
may be made on any junior stock by way of dividends or otherwise (other than
in shares of junior stock) so long as the default continues. If the company
is in arrears in the payment of dividends on any outstanding shares of
preferred stock, the company would be prohibited from redemption or purchase
of less than all of the preferred stock outstanding. All or part of the
7.60% Series of 1987 may be redeemed by the company at any time at an
established redemption price plus accrued dividends to the date of
redemption subject to certain refunding limitations.
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
1997 1996
(Thousands of Dollars)
First Mortgage Bonds:
5 3/4% Series F, due 1997........... $ - $ 14,700
6 3/4% Series G, due 1998........... 9,800 9,800
6 1/4% Series X, due 1999........... 40,000 40,000
6 7/8% Series W, due 2000........... 60,000 60,000
7 3/8% Series B, due 2001........... 60,000 -
7 3/4% Series V, due 2002........... 85,000 85,000
7 3/4% Series Y, due 2024........... 50,000 50,000
Total First Mortgage Bonds..................... 304,800 259,500
Pollution Control Notes:
Tax Exempt Variable Series A, due 2028........ 53,800 53,800
Fees and interest due for spent
fuel disposal costs (Note 2K)................. 39,045 37,055
Less: Amounts due within one year............. 9,800 14,700
Unamortized premium and discount, net......... (996) (913)
Long-term debt, net............................ $386,849 $334,742
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1997 for the years 1998 through 2002 are
approximately $9.8 million, $40 million, $60 million, $60 million and $85
million, respectively. In addition, there are annual one-percent sinking-
and improvement-fund requirements, currently amounting to $1.5 million for
1998 and 1999 and $900 thousand for 2000 through 2002. Such sinking- and
improvement-fund requirements may be satisfied by the deposit of cash or
bonds by certification of property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by WMECO at any time at established redemption prices plus accrued
interest to the date of redemption, except certain series which are subject
to certain refunding limitations during their respective initial five-year
redemption periods.
Essentially all of WMECO's utility plant is subject to the lien of its
first mortgage bond indenture. As of December 31, 1997 and 1996, WMECO has
secured $53.8 million of pollution control notes with second mortgage liens
on Millstone 1, junior to the liens of its first mortgage bond indenture.
The average effective interest rate on the variable-rate pollution control
notes was 3.5 percent for 1997 and 3.3 percent for 1996.
8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions
(credited)/charged to operations are:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Current income taxes:
Federal............................ $(14,277) $ 7,007 $ 7,419
State.............................. (635) 1,358 2,961
Total current.................... (14,912) 8,365 10,380
Deferred income taxes, net:
Federal............................ 3 2,054 4,130
State.............................. 210 609 1,003
Total deferred................... 213 2,663 5,133
Investment tax credits, net.......... (1,469) (1,468) (1,715)
Total income tax (credit)/
expense............................ $(16,168) $ 9,560 $13,798
The components of total income tax expense are classified as follows:
Income taxes charged to
operating expenses................. $(15,142) $10,628 $14,060
Other income taxes .................. (1,026) (1,068) (262)
Total income tax (credit)/
expense............................ $(16,168) $9,560 $13,798
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Depreciation, leased nuclear
fuel, settlement credits,
and disposal costs............... $ 1,407 $ 32 $9,066
Energy adjustment clause........... 3,115 4,102 (1,549)
Demand side management............. 321 1,557 (1,184)
Nuclear plant deferrals............ (3,431) (2,258) 2,468
Pension............................ 999 (57) (482)
Bond redemptions................... (535) (502) (572)
Other............................. (1,663) (211) (2,614)
Deferred income taxes, net........ $ 213 $ 2,663 $5,133
A reconciliation between income tax expense and the expected tax expense at the
applicable statutory rate is as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income for........ $(15,270) $7,076 $18,526
Tax effect of differences:
Depreciation........................... 1,352 2,280 2,173
Amortization of regulatory assets...... 1,916 1,029 1,665
Investment tax credit amortization..... (1,469) (1,468) (1,715)
State income taxes, net of
federal benefit...................... (225) 1,279 2,577
Adjustment for prior years' taxes...... (967) - (7,702)
Dividends received reduction........... (408) (378) (481)
Other, net............................. (1,097) (258) (1,245)
Total income tax (credit)/expense........ $(16,168) $9,560 $13,798
9. LEASES
WMECO and CL&P may finance up to $400 million of nuclear fuel for Millstone
1 and 2 and their respective shares of the nuclear fuel for Millstone 3
under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is
scheduled to expire July 31, 1998. The NBFT capital lease agreement, which
was amended in February 1998, requires CL&P and WMECO to secure their
obligation to repay the NBFT with up to $90 million of first mortgage bonds.
CL&P and WMECO will issue these bonds by May 1998.
WMECO and CL&P make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates
which reflect estimated kilowatt hours of energy provided plus financing
costs associated with the fuel in the reactors. Upon permanent discharge
from the reactors, ownership of the nuclear fuel transfers to WMECO and
CL&P. WMECO has also entered into lease agreements, some of which may be
capital leases, for the use of data processing and office equipment,
vehicles, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options. The
following rental payments have been charged to expense:
Year Capital Leases Operating Leases
1997 .....................$ 1,820,000 $5,968,000
1996 .......................3,598,000 6,410,000
1995 ......................12,553,000 6,398,000
Interest included in capital lease rental payments was $1,820,000 in 1997,
$1,858,000 in 1996, and $1,954,000 in 1995.
Future minimum rental payments, excluding executory costs such as property
taxes, state use taxes, insurance and maintenance, under long-term
noncancelable leases, as of December 31, 1997, are:
Year Capital Leases Operating Leases
(Thousands of Dollars)
1998........................... $32,700 $ 3,700
1999........................... 36 3,400
2000........................... 36 3,100
2001........................... 36 2,800
2002........................... 36 2,500
After 2002..................... 70 18,600
Future minimum lease
payments..................... 32,914 $34,100
Less amount
representing
interest..................... 14
Present value of
future minimum
lease payments............... $32,900
10. EMPLOYEE BENEFITS
A. PENSION BENEFITS
The NU system's subsidiaries participate in a uniform noncontributory
defined benefit retirement plan covering all regular NU system
employees. Benefits are based on years of service and the employees'
highest eligible compensation during 60 consecutive months of
employment. WMECO's direct portion of the NU system's pension credit,
part of which was credited to utility plant, approximated $(5.7)
million in 1997, $(2.0) million in 1996 and $(2.7) million in 1995.
WMECO's pension (credits)/costs for 1997, 1996 and 1995 included
approximately $(529) thousand, $1.0 million and $0.0 million,
respectively, related to workforce reduction programs.
Currently, WMECO funds annually an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are
determined using market-related values of pension assets. Pension
assets are invested primarily in domestic and international equity
securities and bonds.
The components of net pension credit for WMECO are:
For the Years Ended December 31, 1997 1996 1995
(Thousand of Dollars)
Service cost....................... $ 1,346 $ 2,932 $ 1,645
Interest cost...................... 7,858 7,786 7,757
Return on plan assets.............. (31,874) (22,174) (29,798)
Net amortization................... 16,944 9,458 17,669
Net pension (credit)............... $(5,726) $(1,998) $(2,727)
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1997 1996 1995
Discount rate...................... 7.75% 7.50% 8.25%
Expected long-term rate
of return......................... 9.25 8.75 8.50
Compensation/progression rate...... 4.75 4.75 5.00
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31, 1997 and 1996 of
$(87,278,000) and $(85,094,000),
respectively ...................... $( 93,555) $( 91,170)
Projected benefit obligation......... $(109,536) $(107,816)
Market value of plan assets.......... 181,028 157,863
Market value in excess of
projected benefit obligation....... 71,492 50,047
Unrecognized transition amount....... (1,727) (1,963)
Unrecognized prior service costs..... 1,142 1,213
Unrecognized net gain................ (62,370) (46,486)
Prepaid pension asset ............... $ 8,537 $ 2,811
The following actuarial assumptions were used in calculating
the plan's year-end funded status:
At December 31, 1997 1996
Discount rate............................ 7.25% 7.75%
Compensation/progression rate............ 4.25 4.75
B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system's subsidiaries provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees (referred to as SFAS 106 benefits).
These benefits are available for employees retiring from the company
who have met specified service requirements. For current employees
and certain retirees, the total SFAS 106 benefit is limited to two
times the 1993 per-retiree health care cost. The SFAS 106 obligation
has been calculated based on this assumption. WMECO's direct portion
of SFAS 106 benefits, part of which were deferred or charged to
utility plant, approximated $2.8 million in 1997, $3.8 million in
1996, and $4.4 million in 1995. WMECO is funding SFAS 106
postretirement costs through external trusts. WMECO is funding, on an
annual basis, amounts that have been rate-recovered and which also are
tax deductible under the Internal Revenue Code. The trust assets are
invested primarily in equity securities and bonds.
The components of health care and life insurance costs are:
For the Years Ended December 31, 1997 1996 1995
(Thousands of Dollars)
Service cost........................ $ 355 $ 490 $ 490
Interest cost....................... 2,011 2,236 2,544
Return on plan assets............... (2,088) (883) (718)
Amortization of unrecognized
transition obligation............. 1,641 1,641 1,641
Other amortization, net............. 868 353 473
Net health care and life
insurance cost.................... $2,787 $3,837 $4,430
For calculating WMECO's SFAS 106 benefit costs, the following
assumptions were used:
For the Years Ended December 31, 1997 1996 1995
Discount rate....................... 7.75% 7.50% 8.00%
Long-term rate of return -
Health assets, net of tax......... 6.00 5.25 5.00
Life assets....................... 9.25 8.75 8.50
The following table represents the plan's funded status
reconciled to the Consolidated Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated postretirement benefit
obligation of:
Retirees..................................... $(23,123) $(24,614)
Fully eligible active employees.............. (84) (28)
Active employees not eligible to retire...... (4,619) (5,449)
Total accumulated postretirement
benefit obligation.......................... (27,826) (30,091)
Market value of plan assets................... 12,838 10,215
Accumulated postretirement benefit
obligation in excess of plan assets......... (14,988) (19,876)
Unrecognized transition amount................ 24,618 26,259
Unrecognized net gain......................... (9,630) (6,765)
Accrued postretirement benefit liability...... $ - $ (382)
The following actuarial assumptions were used in calculating the
plan's year-end funded status:
At December 31, 1997 1996
Discount rate................................. 7.25% 7.75%
Health care cost trend rate (a)............... 5.76 7.23
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 4.40 percent by 2001.
The effect of increasing the assumed health care cost trend rate by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1997, by $1.7
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$131 thousand. The trust holding the health plan assets is subject to
federal income taxes at a 39.6 percent tax rate.
WMECO currently is recovering SFAS 106 costs through rates.
11. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
During 1996, WMECO entered into an agreement to sell up to $40 million of
undivided ownership interests in eligible customer receivables and accrued
utility revenues (receivables).
The FASB issued SFAS 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," in June, 1996. SFAS
125 became effective on January 1, 1997, and establishes, in part, criteria
for concluding whether a transfer of financial assets in exchange for
consideration should be accounted for as a sale or as a secured borrowing.
During May 1997, WMECO had restructured its sales agreement to comply with
the conditions of SFAS 125 and account for transactions occurring under
this program as a sale of assets. WMECO established a special purpose,
wholly owned subsidiary whose business consists of the purchase and resale
of receivables. For receivables sold, WMECO has retained collection
responsibilities as agent for the purchaser under WMECO's agreement. As
collections reduce previously sold receivables, new receivables may be
sold. At December 31, 1997, approximately $20 million of receivables had
been sold to a third-party purchaser by WMECO, through the use of its
special purpose, wholly owned subsidiary, WMECO Receivables Corporation
(WRC). All receivables transferred to WRC are assets owned by WRC and are
not available to pay WMECO's creditors.
For WRC's sales agreement with the third-party purchaser, the receivables
were sold with limited recourse. WRC's sales agreement provides for a
formula-based loss reserve in which additional receivables may be assigned
to the third-party purchaser for costs such as bad debt. The third-party
purchaser absorbs the excess amount in the event that actual loss
experience exceeds the loss reserve. At December 31, 1997 approximately
$3.0 million of assets had been designated as collateral by WRC. This
amount represents the formula-based amount of credit exposure at December
31, 1997. Historical losses for bad debt for WMECO have been substantially
less.
During December 1997, Moody's Investors Service downgraded the rating on
WMECO's first mortgage bonds. This downgrade brought WMECO's bond ratings
to a level at which the sponsor of WMECO's accounts receivable program can
take various actions, in its discretion, which would have the practical
effect of limiting WMECO's ability to utilize the facility. To date, the
sponsor has not notified WMECO that it will elect to exercise those rights,
and the program is functioning in its normal mode. The WMECO accounts
receivable program is terminable if WMECO's first mortgage bond credit
ratings experience one more level of downgrade. CL&P's accounts receivable
program could be terminated if its senior secured debt is downgraded two
more steps from its current ratings.
Concentrations of credit risk to the purchaser under WMECO's agreement with
respect to the receivables are limited due to WMECO's diverse customer base
within its service territory.
For additional information on the accounts receivable program and WMECO's
ability to utilize this program, see the MD&A.
12. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING AND RATE MATTERS
During November 1997, the state of Massachusetts enacted a
comprehensive electric utility industry restructuring bill
(legislation). On December 31, 1997, WMECO filed its restructuring
plan with the DTE, as required by the legislation. The WMECO
restructuring plan describes the process by which WMECO will,
beginning March 1, 1998, initiate a ten percent rate reduction for all
customer rate classes and allow customers to choose their energy
supplier. As part of the plan, the DTE authorized recovery of certain
strandable above-market costs (strandable costs). The legislation
gives the DTE the authority to determine the amount of strandable
costs that will be eligible for recovery by utilities. Costs which
will qualify as strandable costs and be eligible for recovery include,
but are not limited to, certain above-market costs associated with
generating facilities, costs associated with long-term commitments to
purchase power at above-market prices from small power producers and
nonutility generators, and regulatory assets and associated
liabilities related to the generation portion of WMECO's business.
Under the statute, if a distribution company claims that it is unable
to meet a price reduction of ten percent initially and 15 percent by
September 1, 1999, the distribution company may so state to the DTE
and the DTE is provided with the authority to "explore all possible
mechanisms and options within the limits of the constitution" to
achieve the mandated rate reductions. The statute indicates that
allowing a substitute company to provide standard offer service is one
option that can be considered by the DTE.
The costs of transitioning to competition will be mitigated through
several steps, including divesting WMECO's non-nuclear generating
assets at an auction to be held as soon as June 1998, and
securitization of approximately $500 million in strandable costs by
September 30, 1998. NU presently expects to participate, through a
competitive affiliate, in the competitive bid process for WMECO's
generation resources. Any net proceeds in excess of book value
received from the divestiture of these units will be used to mitigate
strandable costs. As required by the legislation, WMECO will continue
to operate and maintain its transmission and local distribution
network and deliver electricity to all customers.
As noted above, the legislation has authorized Massachusetts utilities
to finance a portion of the strandable costs through securitization,
using rate reduction bonds. A separate transition charge will be
collected over the life of the bonds to recover principal, interest
and issuance costs.
WMECO's ability to recover its strandable costs will depend on several
factors, which include, but are not limited to, continuous recovery of
the costs over the transitional period supported by the legislation,
the aggregate amount of strandable costs which the company will be
allowed to recover and the market price of electricity. Management
believes that the company will recover its strandable costs. However,
a change in one or more of these factors could affect the recovery of
strandable costs and may result in a loss to the company.
FERC Rate Proceedings: For information regarding the FERC rate
proceedings for CYAPC and MYAPC, see Note 3, "Nuclear
Decommissioning."
B. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. Millstone
1, 2 and 3 have been out of service since November 4, 1995, February
21, 1996, and March 30, 1996, respectively, and are on the Nuclear
Regulatory Commission's (NRC) watch list. NU has restructured its
nuclear organization and is currently implementing comprehensive plans
to restart the units.
Subsequent to its January 31, 1996 announcement that Millstone had
been placed on its watch list, the NRC stated that the units cannot
return to service until independent, third-party verification teams
have reviewed the actions taken to improve the design, configuration
and employee concerns issues that prompted the NRC to place the units
on its watch list. The actual date of the return to service for each
of the units is dependent upon the completion of independent
inspections and reviews by the NRC and a vote by the NRC
commissioners. NU hopes to return Millstone 3 to service in the
early spring of 1998 and Millstone 2 three to four months after
Millstone 3. Millstone 1 is currently in extended maintenance
status.
Management cannot predict when the NRC will allow any of the
Millstone units to return to service and thus cannot precisely
estimate the total replacement power costs WMECO will ultimately
incur. Replacement power costs incurred by WMECO attributable to the
Millstone outages averaged approximately $5 million per month during
1997, and for 1998 are projected to average approximately $2 million
per month for Millstone 3, $2 million per month for Millstone 2 and
$1 million per month for Millstone 1 while the plants remain out of
service. WMECO will continue to expense its replacement power costs
in 1998.
Based on the current estimates of expenditures and restart dates,
management believes the NU system has sufficient resources to fund
the restoration of the Millstone units and related replacement power
costs. If the return to service of Millstone 3 or 2 is delayed
substantially beyond the present restart estimates, if some financing
facilities become unavailable because of difficulties in meeting
borrowing conditions or renegotiating extensions, if CL&P and WMECO
encounter additional significant costs or if any other significant
deviations from management's assumptions occur, CL&P and WMECO could
be unable to meet their cash requirements. In those circumstances,
management would take even more stringent actions to reduce costs and
cash outflows and attempt to obtain additional sources of funds. The
availability of these funds would be dependent upon general market
conditions and CL&P's and WMECO's respective credit and financial
conditions at that time.
For information regarding Millstone restart costs, see the MD&A.
For information concerning the ability of WMECO to access its
borrowing facilities, see the MD&A.
Litigation: CL&P and WMECO, through NNECO as agent, operate
Millstone 3 at cost, and without profit, under a sharing agreement
that obligates them to utilize good utility operating practice and
requires the joint owners to share the risk of employee negligence and
other risks of operation and maintenance pro-rata in accordance with
their ownership shares. This agreement also provides that CL&P and
WMECO would be liable only for damages to the non-NU owners for a
deliberate violation of the agreement pursuant to authorized corporate
action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with CL&P and WMECO as well as lawsuits in Massachusetts
Superior Court against NU and its current and former trustees. The
non-NU owners raise a number of contract, tort and statutory claims
arising out of the operation of Millstone 3. The arbitrations and
lawsuits seek to recover compensatory damages, punitive damages,
treble damages and attorneys' fees. Owners representing approximately
two-thirds of the non-NU interests in Millstone 3 claimed compensatory
damages in excess of $200 million. In addition, one of the lawsuits
seeks to restrain NU from disposing of its shares of the stock of
WMECO and HWP, pending the outcome of the lawsuit. Management cannot
estimate the potential outcome of these suits but believes there is no
legal basis for the claims and intends to defend against them
vigorously. To date, no reserves have been established for this
litigation. At December 31, 1997, the costs related to this
litigation for the NU system were estimated to be approximately $100
million for incremental O&M costs and approximately $100 million for
replacement power costs. These costs are likely to increase as long
as Millstone 3 remains out of service.
C. ENVIRONMENTAL MATTERS
The NU system is subject to regulation by federal, state and
local authorities with respect to air and water quality, the handling
and disposal of toxic substances and hazardous and solid wastes, and
the handling and use of chemical products. The NU system has an active
environmental auditing and training program and believes that it is in
substantial compliance with current environmental laws and
regulations. However, the NU system is subject to certain enforcement
actions and governmental investigations in the environmental area.
Management cannot predict the outcome of these enforcement acts and
investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations,
and other facilities. Changing environmental requirements could also
require extensive and costly modifications to WMECO's existing
generating units, and transmission and distribution systems, and could
raise operating costs significantly. As a result, WMECO may incur
significant additional environmental costs, greater than amounts
included in cost of removal and other reserves, in connection with the
generation and transmission of electricity and the storage,
transportation and disposal of by-products and wastes. WMECO may also
encounter significantly increased costs to remedy the environmental
effects of prior waste handling activities. The cumulative long-term
cost impact of increasingly stringent environmental requirements
cannot be estimated accurately.
WMECO has recorded a liability based upon currently available
information for what it believes are its estimated environmental
remediation costs that it expects to incur for waste disposal sites.
In most cases, additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown
magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 1997,
the net liability recorded by WMECO for its estimated environmental
remediation costs, excluding any possible insurance recoveries or
recoveries from third parties, amounted to approximately $1.6 million,
which management has determined to be the most probable amount within
the range of $1.6 million to $2.6 million.
During 1997, WMECO adopted Statement of Position 96-1,
"Environmental Remediation Liabilities" (SOP). The principal
objective of the SOP is to improve the manner in which existing
authoritative accounting literature is applied by entities to specific
situations of recognizing, measuring and disclosing environmental
remediation liabilities. The adoption of the SOP resulted in an
increase of approximately $370 thousand to WMECO's environmental
reserve in 1997.
WMECO cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against
it. However, considering known facts, existing laws and regulatory
practices, management does not believe the matters disclosed above
will have a material effect on WMECO's financial position or future
results of operations.
D. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at
one of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an owner
of a nuclear unit could be assessed in proportion to its ownership
interest in each of its nuclear units up to $75.5 million. Payments
of this assessment would be limited to $10.0 million in any one year
per nuclear incident based upon the owner's pro rata ownership
interest in each of its nuclear units. In addition, the owner would
be subject to an additional five percent or $3.8 million, in
proportion to its ownership interests in each of its nuclear units,
if the sum of all claims and costs from any one nuclear incident
exceeds the maximum amount of financial protection. Based upon its
ownership interests in Millstone 1, 2 and 3, WMECO's maximum
liability, including any additional assessments, would be $39.8
million per incident, of which payments would be limited to $5
million per year. In addition, through power purchase contracts
with MYAPC, VYNPC, and CYAPC, WMECO would be responsible for up to
an additional $11.9 million per incident, of which payments would be
limited to $1.5 million per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences. WMECO is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessment against WMECO with respect to losses
arising during the current policy year is approximately $2.7 million
under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and
the excess cost of repair, replacement, or decontamination or
premature decommissioning of utility property resulting from insured
occurrences. WMECO is subject to retroactive assessments if losses
exceed the accumulated funds available to the insurer. The maximum
potential assessments against WMECO with respect to losses arising
during current policy years are approximately $2.2 million under the
replacement power policies and $3.8 million under the excess property
damage, decontamination and decommissioning policies. The cost of a
nuclear incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry
basis for coverage of worker claims. All participating reactor
operators insured under this coverage are subject to retrospective
assessments of $3 million per reactor. The maximum potential
assessment against WMECO with respect to losses arising during the
current policy period is approximately $2.2 million. Effective
January 1, 1998, a new worker policy was purchased which is not
subject to retrospective assessments.
E. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and
revision by management. WMECO currently forecasts construction
expenditures of approximately $185 million for the years 1998-2002,
including $27 million for 1998. In addition, WMECO estimates that
nuclear fuel requirements, including nuclear fuel financed through the
NBFT, will be approximately $56.4 million for the years 1998-2002,
including $8.4 million for 1998. See Note 9, "Leases" for additional
information about the financing of nuclear fuel.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: The NU system companies rely on VY for
approximately 1.7 percent of their capacity under long-term contracts.
Under the terms of their agreements, the NU system companies pay their
ownership (or entitlement) shares of costs, which include
depreciation, O&M expenses, taxes, the estimated cost of
decommissioning and a return on invested capital. These costs are
recorded as purchased power expense and are recovered through the
companies' rates. WMECO's total cost of purchases under contracts
with VYNPC amounted to $3.9 million in 1997, $4.1 million in 1996 and
1995.
The other Yankee generating facilities, MY, CY and Yankee Rowe, were
permanently shut down as of August 6, 1997, December 4, 1996 and
February 26, 1992, respectively. See Note 2E, "Summary of Significant
Accounting Policies--Investments and Jointly Owned Electric Utility
Plant," for further information on the Yankee companies, and Note 3,
"Nuclear Decommissioning," regarding the related decommissioning
obligations.
Nonutility Generators: WMECO has entered into various arrangements
for the purchase of capacity and energy from nonutility generators
(NUGs). These arrangements have terms from 15 to 25 years, currently
expiring in the years 2008 through 2013, and requires WMECO to
purchase energy at specified prices or formula rates. For the 12
months ending December 31, 1997, approximately 14 percent of NU system
electricity requirements were met by NUGs. WMECO's total cost of
purchases under these arrangements amounted to $31.2 million in 1997,
$29.5 million in 1996, and $28.6 million in 1995. These costs may be
deferred for eventual recovery through rates.
Hydro-Quebec: Along with other New England utilities, WMECO, CL&P,
PSNH and HWP have entered into agreements to support transmission and
terminal facilities to import electricity from the Hydro-Quebec system
in Canada. WMECO is obligated to pay, over a 30-year period ending in
2020, its proportionate share of the annual O&M and capital costs of
these facilities.
Estimated Annual Costs: The estimated annual costs of WMECO's
significant long-term contractual arrangements are as follows:
1998 1999 2000 2001 2002
(Millions of Dollars)
VYNPC ................... $ 4.9 $ 4.9 $ 4.8 $ 5.2 $ 5.4
NUGs .................... 35.1 36.8 39.5 41.6 43.8
Hydro-Quebec ............ 3.8 3.6 3.6 3.5 3.4
For additional information regarding the recovery of purchased
power costs, see Note 2J, "Summary of Significant Accounting Policies
- Recoverable Energy Costs."
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate
fair value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity
Securities," requires investments in debt and equity securities to be
presented at fair value. As a result of this requirement, the investments
held in WMECO's nuclear decommissioning trust were adjusted to market by
approximately $17.9 million as of December 31, 1997, and $8.4 million as of
December 31, 1996, with a corresponding offset to the accumulated provision
for depreciation. The amounts adjusted in 1997 and 1996 represent
cumulative gross unrealized holding gains. The cumulative gross unrealized
holding losses were immaterial for both 1997 and 1996.
Preferred stock and long-term debt: The fair value of WMECO's fixed-rate
securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair
value equal to their carrying value.
The carrying amount of WMECO's financial instruments and the estimated fair
values are as follows:
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption........................... $ 20,000 $ 16,252
Preferred stock subject to
mandatory redemption............................ 21,000 20,580
Long-term debt - First Mortgage Bonds............ 304,800 302,627
Other long-term debt............................. 92,845 92,845
Carrying Fair
At December 31, 1996 Amount Value
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption........................... $ 20,000 $ 15,200
Preferred stock subject to
mandatory redemption............................ 21,000 18,404
Long-term debt - First Mortgage Bonds............ 259,500 260,440
Other long-term debt............................. 90,855 90,855
The fair values shown above have been reported to meet the disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets, as restated -
see Note 1, of Western Massachusetts Electric Company (a Massachusetts
corporation and a wholly owned subsidiary of Northeast Utilities) and
subsidiary as of December 31, 1997 and 1996, and the related consolidated
statements of income, common stockholder's equity and cash flows, as restated
- - see Note 1, for each of the three years in the period ended December 31,
1997. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Western Massachusetts
Electric Company and subsidiary as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1997, in conformity with generally accepted
accounting principles.
Western Massachusetts Electric Company and Subsidiary
As explained in Note 1 to the consolidated financial statements, the company
has given retroactive effect to the change in accounting for nuclear
compliance costs.
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in Note 1, as to
which the date is June 10, 1998)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section contains management's assessment of WMECO's (the company) financial
condition and the principal factors having an impact on the results of
operations. The company is a wholly-owned subsidiary of Northeast Utilities
(NU). This discussion should be read in conjunction with the company's
consolidated financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
The length of the ongoing outages at the three Millstone nuclear plants
(Millstone) and the high costs of the recovery efforts weakened WMECO's 1997 net
income, balance sheet and cash flows and will continue to have an adverse impact
on the company's financial condition until the units are returned to service.
WMECO had a net loss of approximately $27 million in 1997, compared to net
income of approximately $11 million in 1996. The poorer financial results in
1997 were due primarily to the fact that all three Millstone units were off line
for the entire year in 1997 and spending associated with the recovery efforts
was significantly higher in 1997 than it was in 1996. Millstone 3 operated for
nearly three months in 1996 and Millstone 2 for nearly two months. As a result,
the cost of replacing power ordinarily generated by the Millstone units rose by
approximately $15 million in 1997. The total operation and maintenance (O&M)
costs at Millstone were approximately $40 million higher in 1997.
The higher Millstone costs have caused WMECO to focus closely on maintaining
adequate liquidity and reducing non nuclear O&M costs. In July 1997, WMECO
successfully sold $60 million of first mortgage bonds. WMECO's access to $90
million of revolving credit lines was renegotiated in the first half of 1997.
Also helping to maintain liquidity was the renegotiation in early 1998 of a $100
million credit line used by Niantic Bay Fuel Trust (NBFT) to purchase nuclear
fuel for Millstone. Additionally, non nuclear O&M expenses in 1997 were reduced
by about $5 million from 1996.
The SEC has advised WMECO to adjust for certain costs associated with the
ongoing Millstone outages as they are incurred. For the past two years, WMECO
has been reserving for the unavoidable costs they expected to incur to meet NRC
requirements. These annual statements have been adjusted in accordance with the
SEC's directive. Management does not expect implementation of this accounting
change to affect the ability of The Connecticut Light and Power Company (CL&P)
and WMECO to meet their financial covenants contained in their $313.75 million
revolving credit arrangement.
In 1998, management expects Millstone-related expenses to fall significantly,
assuming Millstone 3 and Millstone 2 are returned to service at dates close to
current estimates, although the O&M expenses at Millstone 3 and 2 will be
considerably higher than before the station was placed on the Nuclear Regulatory
Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at
Millstone will depend on when the units return to operation and the cost of
restoring them to service. The company hopes to restart Millstone 3, the newest
and largest unit at the site, in early spring of 1998 and Millstone 2 three to
four months after Millstone 3. The company cannot restart the Millstone units
until it receives formal approval from the NRC. As part of an effort to reduce
spending in 1998, Millstone 1 has been placed in extended maintenance status.
Management will review its options with respect to Millstone 1 in 1998,
including restart, early retirement and other options.
Rate reductions to customers served by the company are likely to offset a
portion of the benefit of lower Millstone-related costs. On March 1, 1998,
WMECO reduced retail rates by 10 percent in compliance with industry
restructuring legislation passed in November 1997 by the Massachusetts
Legislature.
The 1997 Massachusetts legislation allowed full retail choice on March 1, 1998.
WMECO expects to recover fully its stranded costs through a combination of
securitization and divestiture of its non-nuclear generating assets.
MILLSTONE
OUTAGES
WMECO has a 19-percent ownership interest in Millstone units 1 and 2 and a
12.24-percent ownership interest in Millstone unit 3. Millstone 1, 2 and 3 have
been out of service since November 4, 1995, February 21, 1996, and March 30,
1996, respectively.
Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC has stated that the units cannot return to service
until independent, third-party verification teams have reviewed the actions
taken to improve the design, configuration and employee concern issues that
prompted the NRC to place the units on its watch list. The actual date of the
return to service for each of the units is dependent upon the completion of
independent inspections, reviews by the NRC and a vote by the NRC Commissioners.
In January 1998, NU declared Millstone 3 physically ready for restart, which
meant that almost all of the restart-required physical work had been completed
in the plant. The NRC currently is conducting a series of inspections to
determine, among other things, whether the plant has effective leadership and
corrective action and employee concerns programs. The Independent Corrective
Action Verification Program, an NRC-ordered independent review of the plant's
design and licensing bases, is expected to be completed in March 1998.
In 1997, WMECO's share of nonfuel O&M costs expensed for Millstone increased to
approximately $104 million, compared to approximately $64 million in 1996.
Replacement power costs attributable to the Millstone outages totaled
approximately $56 million in 1997 compared to $41 million expensed in 1996.
These costs for 1998 are forecasted to average approximately $2 million per
month for Millstone 3, $2 million per month for Millstone 2 and $1 million per
month for Millstone 1 while the plants are out of service.
The company has been, and will continue to be, expensing all of the costs to
restart the units including replacement power and nonfuel O&M expenses.
NU and its subsidiaries are involved in several class action lawsuits and other
litigation in connection with their nuclear operations. See the "Notes to
Consolidated Financial Statements," Note 12B, for further information on this
litigation.
MILLSTONE 1
Management will review its options with respect to Millstone 1 during 1998. The
issues that management will consider in evaluating its options include the costs
to restart the unit and the economic benefits of the unit's continued operation.
CAPACITY
During 1996 and continuing into 1997, WMECO took measures to improve its
capacity position, including obtaining additional generating capacity, improving
the availability of the company's generating units and improving the company
transmission capability. During 1997, WMECO spent approximately $10 million to
ensure availability of adequate generating generating capacityin Connecticut,
of which $6 million was expensed. During 1998 these costs are expected to be
approximately $11 million. In 1998, WMECO does not anticipate the need to take
additional measures to ensure adequate generating capacity.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $41 million in 1997,
compared to 1996, primarily due to higher cash expenditures related to the
Millstone outages, and the pay down in 1997 of the 1996 year end accounts
payable balance. The 1996 year end accounts payable balance was relatively high
due to costs related to a severe December storm and costs associated with the
Millstone outages that had been incurred but not yet paid by the end of 1996.
Net cash from financing activities increased approximately $44 million,
primarily due to the issuance of long-term debt in 1997 and lower reacquisitions
and retirements of long-term debt and preferred stock, partially offset by the
repayment of short-term debt.
WMECO established facilities in 1996 under which they may sell, from time to
time, up to $40 million, of its accounts receivable and accrued utility
revenues. As of December 31, 1997, WMECO sold approximately $20 million of
receivables to third-party purchasers.
NU's, WMECO's and CL&P's three-year revolving credit agreement (Credit
Agreement) was amended in May 1997 (the Credit Agreement). Under the Revolving
Credit Agreement, CL&P and WMECO are able to borrow up to approximately $225
million and $90 million, respectively, subject to a total borrowing limit of
$313.75 million for all three borrowers. NU will be able to borrow up to $50
million when NU, CL&P and WMECO have each maintained a consolidated operating
income to consolidated interest expense ratio of at least 2.50 to 1 for two
consecutive fiscal quarters. Currently, the companies cannot meet this
requirement. At December 31, 1997, WMECO had $15 million outstanding under the
New Credit Agreement.
Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has
any financing agreements containing cross defaults based on financial defaults
by NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy
Corporation (NAEC). Nevertheless, it is possible that investors will take
negative operating results or regulatory developments for one subsidiary of NU
into account when evaluating the other NU subsidiaries. That could, as a
practical matter and despite the contractual and legal separations among NU and
its subsidiaries, negatively affect the company's access to financial markets.
In December 1997 and January 1998, Moody's Investors Service (Moody's) and
Standard & Poor's (S&P), respectively, downgraded the senior secured debt of
CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was
the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since
the Millstone units went on the NRC watch list in 1996. All of the NU system's
securities are rated below investment grade and remain under review for further
downgrade. Although WMECO does not have any plans to issue debt in the near
term, rating agency downgrades generally increase the future cost of borrowing
funds because lenders will want to be compensated for increased risk.
Additionally, this could also affect the terms and ability of the company to
extend existing agreements.
The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in December 1997
brought those ratings to a level at which the sponsor of WMECO's accounts
receivable program can take various actions, in its discretion, which would have
the practical effect of limiting WMECO's ability to utilize the facility. The
WMECO accounts receivable program could be terminated if WMECO's first mortgage
bond credit ratings experience one more level of downgrade.
WMECO's ability to borrow under the financing arrangements is dependent on the
satisfaction of contractual borrowing conditions. The financial covenants that
must be satisfied to permit WMECO to borrow under the New Credit Agreement are
particularly restrictive and become more restrictive throughout 1998. Spending
levels in 1998, particularly for the first half of the year while the Millstone
units are expected to be out of service, have been, and will be constrained to
levels intended to assure that the financial covenants in WMECO's Credit
Agreement are satisfied. However, there is no assurance that these financial
covenants will be met as the system may encounter additional unexpected costs
from such areas as storms, reduced revenues from regulatory actions or the
effect of weather on sales levels.
If the return to service of Millstone 3 or Millstone 2 is delayed substantially
beyond the present restart estimates, if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions or
renegotiating extensions, if the system encounters additional significant costs,
or any other significant deviations from management's current assumptions, the
currently available borrowing facilities could be insufficient to meet all of
WMECO's cash requirements. In those circumstances, management would take even
more stringent actions to reduce costs and cash outflows and would attempt to
take other actions to obtain additional sources of funds. The availability of
these funds would be dependent upon the general market conditions and WMECO's
credit and financial condition at that time.
RESTRUCTURING
On November 25, 1997, Massachusetts enacted a comprehensive electric utility
industry restructuring bill. The bill provides that each Massachusetts electric
company, including WMECO, will decrease its rates by 10 percent and allow all
its customers to choose their retail electric supplier on March 1, 1998. The
statute requires a further 5 percent rate reduction, adjusted for inflation, by
September 1, 1999.
In addition, the legislation provides, among other things, for: (i) recovery of
stranded costs through a "transition charge" to customers, subject to review by
the Department of Telecommunications and Energy (DTE), formerly the Department
of Public Utilities (DPU, collectively the DTE), (ii) a possible limitation on
WMECO's return on equity should its transition cost charge go above a certain
level, (iii) securitization of allowed strandable costs, and (iv) divestiture of
nonnuclear generation. WMECO hopes it will be able to complete securitization in
1998.
The statute also provides that an electric company must transfer or separate
ownership of generation, transmission and distribution facilities into
independent affiliates or functionally separate such facilities within 30
business days after federal approval. Additionally, marketing companies formed
by an electric company are to be separate from the electric company and separate
from generation, transmission or distribution affiliates.
On December 31, 1997, WMECO filed its restructuring plan with the DTE
consistent with the Massachusetts restructuring legislation. The plan sets out
the process by which WMECO, as of March 1, 1998, initiated a 10 percent rate
reduction for all customer rate classes and allowed customers to choose their
energy supplier. WMECO intends to mitigate its strandable costs through several
steps, including divesting WMECO's nonnuclear generating plants at an auction to
be held as soon as June 30, 1998, and securitization of approximately $500
million of stranded costs. NU intends to participate through a nonregulated
affiliate in the competitive bid process for WMECO's generation resources. Any
proceeds in excess of book value received from the divestiture of these units
will be used to mitigate stranded costs. As required by the legislation, WMECO
will continue to operate and maintain the transmission and local distribution
network and deliver electricity to all customers. On February 20, 1998, the DTE
issued an order approving, in all material respects, WMECO's restructuring plan
on an interim basis. A final decision is expected in 1998.
Because WMECO is obligated to reduce rates on March 1, 1998, before the means of
financing for restructuring are completed, WMECO's cash flows and financial
condition will be negatively affected. These impacts would become significant if
there are material delays in, or significantly reduced proceeds from, the
divestiture of nonnuclear generation and securitization. See the "Notes to
Consolidated Financial Statements," Note 12A, for the potential accounting
impacts of restructuring.
RATE MATTERS
In April, 1996, the DTE approved a settlement (the Agreement) that included the
continuation through February 1998 of a 2.4 percent rate reduction instituted in
June 1994. Additionally, the Agreement terminated certain pending and potential
reviews of WMECO's generating plant performance and accelerated its amortization
of strandable generation assets by approximately $6 million in 1996 and $10
million in 1997.
On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a
settlement agreement with the Massachusetts Attorney General for a fuel
adjustment clause (FAC) which would allow for a lower rate to WMECO customers
for the billing months of September 1997 through February 1998. WMECO is not
recovering replacement power costs during this period and has indicated that it
would not seek recovery of any of replacement power costs associated with the
Millstone outages. WMECO has been expensing and will continue to expense these
costs. The Massachusetts restructuring legislation effectively eliminates the
FAC, effective March 1, 1998.
NUCLEAR DECOMMISSIONING
CONNECTICUT YANKEE
WMECO has a 9.5 percent ownership interest in the Connecticut Yankee nuclear
generating facility (CY or the plant). On December 4, 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease
permanently the production of power at the plant. The decision to retire CY from
commercial operation was based on an economic analysis of the costs of operating
it compared to the costs of closing it and incurring replacement power costs
over the remaining period of the plant's operating license, which would have
expired in 2007. The economic analysis showed that closing the plant and
incurring replacement power costs produced substantial savings.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December 1996, CY filed an amendment to its power
contracts with the FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1997, WMECO's
share of these obligations was approximately $59 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that the
company will continue to be allowed to recover such FERC approved costs from its
customers. Accordingly, WMECO has recognized its share of the estimated costs
as a regulatory asset, with a corresponding obligation, on its balance sheets.
MAINE YANKEE (MY)
WMECO has a 3 percent ownership interest in the Maine Yankee (MY) nuclear
generating facility. On August 6, 1997, the Board of Directors of Maine Yankee
Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14,
1998, FERC released a draft order on the MYAPC application to amend its power
contracts with the owner/purchasers and revise its decommissioning and other
charges. FERC has accepted the proposed application for filing and made the
amendments and the proposed charges under the contracts effective on January 15,
1998, subject to refund after hearings. At December 31, 1997, WMECO'S share of
the estimated remaining obligation, including decommissioning, amounted to
approximately $26 million. Under the terms of the contracts with MYAPC, the
shareholders' sponsor companies, including WMECO, are responsible for their
proportionate share of the costs of the unit, including decommissioning.
Management expects that WMECO will be allowed to recover these costs from its
customers. Accordingly, WMECO has recognized these costs as a regulatory asset,
with a corresponding obligation on its balance sheet.
MILLSTONE
WMECO's estimated cost to decommission its share of the Millstone plants is
approximately $242 million in year end 1997 dollars. These costs are being
recognized over the lives of the respective units with a portion being currently
recovered through rates. As of December 31, 1997, the market value of the
contributions already made to the decommissioning trusts, including their
investment returns, was approximately $103 million. See the "Notes to
Consolidated Financial Statements," Note 3, for further information on nuclear
decommissioning.
ENVIRONMENTAL MATTERS
WMECO is potentially liable for environmental cleanup costs at a number of sites
inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of WMECO. At December 31, 1997, WMECO had
recorded an environmental reserve of approximately $1.4 million. See the "Notes
to Consolidated Financial Statements," Note 12C, for further information on
environmental matters.
YEAR 2000 ISSUE
The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU's systems to process critical financial and operational
information incorrectly. The NU system has assessed and continues to assess the
impact of the Year 2000 issue on its operating and reporting systems. The
assessment of the nuclear operating systems is continuing and is expected to be
completed in the summer of 1998.
The NU System will utilize both internal and external resources to reprogram or
replace, and test the software for Year 2000 modifications. The total estimated
remaining cost of the Year 2000 project for the NU system is $37 million and is
being funded through operating cash flows. This estimate does not include any
costs for the replacement or repair of equipment or devices that may be
identified during the assessment process. The majority of these costs will be
expensed as incurred over the next two years. To date, the NU system has
incurred and expensed approximately $4 million related to the assessment of and
preliminary efforts in connection with its Year 2000 project.
The costs of the project and the date on which the NU system plans to complete
the Year 2000 modifications are based on management's best estimates, which were
derived utilizing numerous assumptions of future events, including the continued
availability of certain resources, third-party modification plans and other
factors. However, there can be no guarantee that these estimates will be
achieved, and actual results could differ materially from those plans. If the
NU system's remediation plan is not successful, there could be a significant
disruption of the company's operations.
RESULTS OF OPERATIONS
Income Statement Variances
Millions of Dollars
1997 over/(under) 1996 1996 over/(under) 1995
Amount Percent Amount Percent
Operating revenues $ 5 1% $ 1 - %
Fuel, purchased and net
interchange power 25 22 29 33
Other operation 17 12 (6) (4)
Maintenance 25 45 19 50
Amortization of regulatory
assets, net (3) (30) (10) (53)
Federal and state
income taxes (26) (a) (4) (31)
Other income, net (2) (a) - -
Interest on long-term debt 2 8 (3) (10)
Net income (39) (a) (28) (72)
(a) Percentage greater than 100
OPERATING REVENUES
Total operating revenues increased in 1997, primarily due to higher transmission
and capacity revenues and higher retail revenues. Retail revenues were higher
due to lower price discounts to customers, partially offset by lower retail
sales. Retail kilowatt-hour sales were 1 percent lower in 1997 primarily as a
result of mild winter weather.
Total operating revenues increased in 1996, primarily due to higher retail
sales, partially offset by lower fuel and conservation recoveries. Retail
kilowatt-hour sales increased 2.7 percent ($9 million) primarily due to modest
economic growth in 1996. Fuel recoveries decreased $6 million, primarily due to
the timing of the recovery of costs under the company's fuel clause.
Conservation recoveries decreased approximately $6 million primarily due to
lower demand side management costs.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 1997, primarily
due to replacement power costs associated with the Millstone outages.
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to higher replacement power associated with the Millstone outages, partially
offset by the timing of the recognition of costs under the company's fuel clause
and lower nuclear generation.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($40 million), higher
capacity charges from Maine Yankee ($2 million) and higher costs to ensure
adequate capacity ($6 million), partially offset by lower capacity charges from
Connecticut Yankee as a result of a property tax refund ($4 million) and lower
administrative and general expenses ($5 million) primarily due to lower pensions
and benefit costs.
Other operation and maintenance expenses increased in 1996, primarily due to
higher costs associated with the Millstone restart effort ($21 million),
partially offset by lower costs for demand side management programs and a 1995
work stoppage.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased in 1997, primarily due to the
completion of the amortization of the Millstone 3 unuseful investment in 1996.
Amortization of regulatory assets, net decreased in 1996, primarily due to the
completion of the amortization of the Millstone 3 phase-in plans in 1995 and
unuseful investment in June, 1996, partially offset by higher amortization as a
result of the 1996 rate settlement.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased in 1997, primarily due to lower book
taxable income.
Federal and state income taxes decreased in 1996, primarily due to lower book
taxable income, partially offset by 1995 tax benefits from a favorable tax
ruling and the expiration of the 1991 federal statute of limitations.
OTHER INCOME, NET
Other income, net decreased in 1997, primarily due to costs associated with the
accounts receivable facility.
INTEREST ON LONG-TERM DEBT
Interest on long-term debt increased in 1997 due to the issuance of additional
long-term debt. Interest on long-term debt decreased in 1996, primarily due to
lower average interest rates as a result of refinancing activities and lower
average 1996 debt levels.
Western Massachusetts Electric Company and Subsidiary
SELECTED FINANCIAL DATA (a)
1997 1996 1995 1994 1993
(Restated) (Restated)
(Thousands of Dollars)
Operating Revenues...$ 426,447 $ 421,337 $ 420,434 $ 421,477 $ 415,055
Operating Income.... 251 33,190 63,064 70,940 60,348
Net (Loss)/Income.... (27,460) 11,089 39,133 49,457 40,594(b)
Cash Dividends on
Common Stock....... 15,004 16,494 30,223 29,514 28,785
Total Assets......... 1,179,128 1,191,915 1,142,346 1,183,618 1,204,642
Long-Term Debt (c)... 396,649 349,442 347,470 379,969 393,232
Preferred Stock Not
Subject to Mandatory
Redemption.......... 20,000 20,000 53,500 68,500 73,500
Preferred Stock Subject
to Mandatory
Redemption(c)....... 21,000 21,000 24,000 24,675 27,000
Obligations Under
Capital Leases(c)... 32,887 32,234 36,011 36,797 36,902
(a) Reclassifications of prior data have been made to conform with the current
presentation.
(b) Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares by $3.9
million.
(c) Includes portion due within one year.
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated)
Quarter Ended (a)
1997 March 31 June 30 Sept. 30 Dec. 31
Operating Revenues........ $106,054 $104,130 $111,166 $105,097
Operating Income/(Loss)... $ 675 $ (4,794) $ 1,875 $ 2,495
Net Loss.................. $ (5,033) $(11,492) $ (5,303) $ (5,632)
1996
Operating Revenues........ $114,797 $102,602 $ 99,866 $104,072
Operating Income ......... $ 18,004 $ 10,522 $ 3,441 $ 1,223
Net Income/(Loss)......... $ 12,421 $ 5,161 $ (1,282) $ (5,211)
STATISTICS
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands kWh Sales Residential Customers Employees
of Dollars) (Millions) Customer (kWh) (Average) (December 31)
1997 $1,334,233 4,300 7,121 195,324 507
1996 1,303,361 4,626 7,335 194,705 497
1995 1,285,269 4,846 7,105* 193,964 527
1994 1,271,513 4,978 7,433 193,187 617
1993 1,242,927 4,715 7,351 192,542 657
*Effective January 1, 1996, the amounts shown reflect billed and unbilled
sales. 1995 has been restated to reflect this change.
EXHIBIT 13.4
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
AMENDED 1997 ANNUAL REPORT
Public Service Company of New Hampshire
Amended 1997 Annual Report
Index
Contents Page
Balance Sheets (Restated).......................................... 2
Statements of Income (Restated).................................... 4
Statements of Cash Flows (Restated)................................ 5
Statements of Common Stockholder's Equity (Restated)............... 6
Notes to Financial Statements (Restated)........................... 7
Report of Independent Public Accountants........................... 40
Management's Discussion and Analysis of Financial
Condition and Results of Operations (Restated)................... 42
Selected Financial Data (Restated)................................. 50
Statistics......................................................... 52
Statements of Quarterly Financial Data (Restated).................. 52
Preferred Stockholder and Bondholder Information................... Back Cover
PART I. FINANCIAL INFORMATION
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at cost:
Electric................................................ $ 1,898,319 $ 1,877,955
Less: Accumulated provision for depreciation......... 590,056 552,780
------------- -------------
1,308,263 1,325,175
Unamortized acquisition costs........................... 402,285 491,709
Construction work in progress........................... 10,716 11,032
Nuclear fuel, net....................................... 1,308 1,313
------------- -------------
Total net utility plant............................. 1,722,572 1,829,229
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market............... 4,332 3,229
Investments in regional nuclear generating
companies and subsidiary company, at equity............ 19,169 19,578
Other, at cost.......................................... 3,773 1,835
------------- -------------
27,274 24,642
------------- -------------
Current Assets:
Cash and cash equivalents............................... 94,459 1,015
Notes receivable from affiliated companies.............. - 18,250
Receivables, less accumulated provision for
uncollectible accounts of $1,702,000 in 1997
and of $1,700,000 in 1996............................. 89,338 105,381
Accounts receivable from affiliated companies........... 38,520 32,452
Accrued utility revenues................................ 36,885 36,317
Fuel, materials, and supplies, at average cost.......... 40,161 44,852
Recoverable energy costs, net--current portion.......... 31,886 -
Prepayments and other................................... 11,271 24,629
------------- -------------
342,520 262,896
------------- -------------
Deferred Charges:
Regulatory assets....................................... 695,418 684,504
Deferred receivable from affiliated company............. 32,472 33,284
Unamortized debt expense................................ 11,749 12,731
Other................................................... 5,154 3,926
------------- -------------
744,793 734,445
------------- -------------
Total Assets........................................ $ 2,837,159 $ 2,851,212
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$1 par value.
Authorized and outstanding 1,000 shares................ $ 1 $ 1
Capital surplus, paid in................................ 423,713 423,058
Retained earnings (Note 1).............................. 170,501 175,254
------------- -------------
Total common stockholder's equity.............. 594,215 598,313
Preferred stock subject to mandatory redemption......... 75,000 100,000
Long-term debt.......................................... 516,485 686,485
------------- -------------
Total capitalization........................... 1,185,700 1,384,798
------------- -------------
Obligations Under Seabrook Power Contracts
and Other Capital Leases................................. 799,450 871,707
------------- -------------
Current Liabilities:
Long-term debt and preferred stock--current portion..... 195,000 25,000
Obligations under Seabrook Power Contracts and other
capital leases--current portion........................ 122,363 42,910
Accounts payable........................................ 21,231 37,675
Accounts payable to affiliated companies................ 32,677 31,130
Accrued taxes........................................... 69,445 81
Accrued interest........................................ 7,197 7,992
Accrued pension benefits................................ 46,061 44,790
Other................................................... 9,417 36,616
------------- -------------
503,391 226,194
------------- -------------
Deferred Credits:
Accumulated deferred income taxes....................... 204,406 258,654
Accumulated deferred investment tax credits............. 3,972 4,511
Deferred contractual obligations........................ 83,042 50,271
Deferred revenue from affiliated company................ 32,472 33,284
Other................................................... 24,726 21,793
------------- -------------
348,618 368,513
------------- -------------
Commitments and Contingencies (Note 11)
------------- -------------
Total Capitalization and Liabilities........... $ 2,837,159 $ 2,851,212
============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- --------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................. $1,108,459 $1,110,169 $ 979,971
----------- ----------- ----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power..... 326,745 356,679 257,008
Other......................................... 368,363 326,337 313,604
Maintenance...................................... 38,320 45,728 42,244
Depreciation..................................... 44,377 42,983 44,337
Amortization of regulatory assets, net........... 56,557 56,884 55,547
Federal and state income taxes................... 86,450 80,677 69,817
Taxes other than income taxes.................... 43,623 45,123 41,786
----------- ----------- ----------
Total operating expenses (Note 1).......... 964,435 954,411 824,343
----------- ----------- ----------
Operating Income................................... 144,024 155,758 155,628
----------- ----------- ----------
Other Income:
Equity in earnings of regional nuclear
generating companies and subsidary company..... 1,373 2,075 1,645
Other, net....................................... 698 8,075 3,162
Income taxes..................................... (2,391) (7,723) (770)
----------- ----------- ----------
Other (loss)/income, net................... (320) 2,427 4,037
----------- ----------- ----------
Income before interest charges............. 143,704 158,185 159,665
----------- ----------- ----------
Interest Charges:
Interest on long-term debt....................... 51,259 57,557 76,320
Other interest................................... 273 3,163 90
----------- ----------- ----------
Interest charges, net...................... 51,532 60,720 76,410
----------- ----------- ----------
Net Income (Note 1)................................ $ 92,172 $ 97,465 $ 83,255
=========== =========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net Income.................................................. $ 92,172 $ 97,465 $ 83,255
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 44,377 42,983 44,337
Deferred income taxes and investment tax credits, net..... 21,645 94,983 69,986
Recoverable energy costs, net of amortization............. (12,336) 31,663 (15,266)
Amortization of acquisition costs......................... 56,557 56,884 55,547
Deferred Seabrook capital costs........................... (8,376) - -
Other sources of cash..................................... 51,054 65,922 15,973
Other uses of cash........................................ (67,590) (51,188) -
Changes in working capital:
Receivables and accrued utility revenues.................. 9,407 (36,907) (10,506)
Fuel, materials and supplies.............................. 4,691 (3,135) (4,264)
Accounts payable.......................................... (14,897) (7,714) 2,375
Accrued taxes............................................. 69,364 (717) (3,506)
Other working capital (excludes cash)..................... (13,365) (13,559) 16
----------- ----------- -----------
Net cash flows from operating activities (Note 1)............. 232,703 276,680 237,947
----------- ----------- -----------
Financing Activities:
Reacquisitions and retirements of long-term debt............ - (172,500) (141,000)
Reacquisitions and retirements of preferred stock........... (25,000) - -
Cash dividends on preferred stock........................... (11,925) (13,250) (13,250)
Cash dividends on common stock.............................. (85,000) (52,000) (52,000)
----------- ----------- -----------
Net cash flows used for financing activities.................. (121,925) (237,750) (206,250)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (33,570) (37,480) (46,672)
Nuclear fuel.............................................. 5 129 (184)
----------- ----------- -----------
Net cash flows used for investments in plant................ (33,565) (37,351) (46,856)
NU System Money Pool........................................ 18,250 850 15,900
Investment in nuclear decommissioning trusts................ (490) (521) (489)
Other investment activities, net............................ (1,529) (1,010) (431)
----------- ----------- -----------
Net cash flows used for investments........................... (17,334) (38,032) (31,876)
----------- ----------- -----------
Net Increase/(Decrease) in Cash For The Period................ 93,444 898 (179)
Cash - beginning of period.................................... 1,015 117 296
----------- ----------- -----------
Cash - end of period.......................................... $ 94,459 $ 1,015 $ 117
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 51,775 $ 58,835 $ 74,543
=========== =========== ===========
Income taxes................................................ $ 10,612 $ (457) $ 1,369
=========== =========== ===========
Increase in obligations:
Seabrook Power Contracts and other capital leases........... $ 6,197 $ 93 $ 28,028
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In (Note 1) Total
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1995............... $ 1 $421,784 $125,034 $546,819
Net income for 1995.................. 83,255 83,255
Cash dividends on preferred stock.... (13,250) (13,250)
Cash dividends on common stock....... (52,000) (52,000)
Capital stock expenses, net.......... 601 601
-------- --------- --------- ---------
Balance at December 31, 1995............. 1 422,385 143,039 565,425
Net income for 1996 (Note 1)......... 97,465 97,465
Cash dividends on preferred stock.... (13,250) (13,250)
Cash dividends on common stock....... (52,000) (52,000)
Capital stock expenses, net.......... 673 673
-------- --------- --------- ---------
Balance at December 31, 1996 (Restated).. 1 423,058 175,254 598,313
Net income for 1997 (Note 1)......... 92,172 92,172
Cash dividends on preferred stock.... (11,925) (11,925)
Cash dividends on common stock....... (85,000) (85,000)
Capital stock expenses, net.......... 655 655
-------- --------- --------- ---------
Balance at December 31, 1997 (Restated).. $ 1 $423,713 $170,501 $594,215
======== ========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
Public Service Company of New Hampshire
NOTES TO FINANCIAL STATEMENTS
1. SECURITIES AND EXCHANGE COMMISSION INQUIRY
In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC)
inquired into Northeast Utilities' (NU) accounting for nuclear compliance costs.
These costs are the unavoidable incremental costs associated with the current
nuclear outages required to be incurred prior to restart of the units in
accordance with correspondence received from the Nuclear Regulatory Commission
(NRC) early in 1996. The SEC's view is that these unavoidable costs associated
with nuclear outages and procedures to be implemented at nuclear power plants in
response to regulatory requirements required prior to restart of the units
should be expensed as incurred. During 1996 and 1997, NU and its wholly owned
subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service
Company of New Hampshire (PSNH) and Western Massachusetts Electric Company
(WMECO), reserved for these unavoidable incremental costs that they expected to
incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to
reflect these costs as they are incurred. While NU and its independent auditors,
Arthur Andersen LLP, believed the accounting was required by, and was in
accordance with, generally accepted accounting principles, NU has agreed to
adjust its accounting for nuclear compliance costs and amend its 1996 and 1997
Form 10-K filings. The financial statements in this report have been restated
to reflect the change in accounting.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
Public Service Company of New Hampshire (PSNH or the company), CL&P,
WMECO, North Atlantic Energy Corporation (NAEC), and Holyoke Water
Power Company (HWP) are the operating subsidiaries comprising the
Northeast Utilities system (the NU system) and are wholly owned by NU.
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire, and western Massachusetts through CL&P,
PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its
entitlement to the capacity and output of the Seabrook nuclear
generating unit (Seabrook, a 1,148-megawatt (MW) nuclear generating
unit) to PSNH under two long-term contracts (the Seabrook Power
Contracts). In addition to its franchised retail service, the NU
system furnishes firm and other wholesale electric services to various
municipalities and other utilities, and participates in limited retail
access programs, providing off-system retail electric service. The NU
system serves about 30 percent of New England's electric needs and is
one of the 25 largest electric utility systems in the country as
measured by revenues.
Other wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. North Atlantic Energy
Service Corporation (NAESCO) acts as agent for CL&P and NAEC, and has
operational responsibilities for Seabrook. Northeast Nuclear Energy
Company (NNECO) acts as agent for the NU system companies and other New
England utilities in operating the Millstone nuclear generating
facilities.
B. PRESENTATION
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 liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and are
subject to approval by various federal and state regulatory agencies.
C. PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935
(1935 Act). NU and its subsidiaries, including PSNH, are subject to
the provisions of the 1935 Act. Arrangements among the NU system
companies, outside agencies and other utilities covering inter-
connections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. PSNH is subject to further
regulation for rates, accounting and other matters by the FERC and/or
the applicable state regulatory commissions.
For information regarding proposed changes in the nature of industry
regulation, see Note 11A, "Commitments and Contingencies -
Restructuring and Rate Matters."
D. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued a new accounting
standard in February 1997: Statement of Financial Accounting Standards
(SFAS) 129, "Disclosure of Information about Capital Structure." SFAS
129 establishes standards for disclosing information about an entity's
capital structure. PSNH's current disclosures are consistent with the
requirements of SFAS 129.
During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive
Income" and SFAS 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS 130 establishes standards for the reporting
and disclosure of comprehensive income. To date, the NU system
companies have not had material transactions that would be required to
be reported as comprehensive income. SFAS 131 determines the standards
for reporting and disclosing qualitative and quantitative information
about a company's operating segments. This information includes segment
profit or loss, certain segment revenue and expense items and segment
assets and a reconciliation of these segment disclosures to
corresponding amounts in the company's general purpose financial
statements. Management performance is currently evaluated using a cost-
based budget and the information required by SFAS 131 is not available.
Therefore, these disclosure requirements are not applicable. Management
believes that the implementation of SFAS 130 and SFAS 131 will not have
a material impact on PSNH's current disclosures.
See Note 11C, "Commitments and Contingencies-Environmental Matters,"
for information on other newly issued accounting and reporting
standards related to this area.
E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: PSNH owns common stock of four
regional nuclear generating companies (Yankee companies). PSNH's
investments in the Yankee companies are accounted for on the equity
basis due to PSNH's ability to exercise significant influence over
their operating and financial policies. The Yankee companies, with
PSNH's ownership interests, are:
Connecticut Yankee Atomic Power Company (CYAPC) ................ 5.0%
Yankee Atomic Electric Company (YAEC) .......................... 7.0
Maine Yankee Atomic Power Company (MYAPC) ...................... 5.0
Vermont Yankee Nuclear Power Corporation (VYNPC) ............... 4.0
PSNH's equity investments in the Yankee companies at December 31, 1997
are:
(Thousands of Dollars)
CYAPC .............................................. $ 5,761
YAEC ............................................... 1,427
MYAPC .............................................. 3,880
VYNPC .............................................. 2,085
$13,153
Each Yankee company owns a single nuclear generating unit. Under the
terms of the contracts with the Yankee companies, the shareholders-
sponsors, including PSNH, are responsible for their proportionate share
of the costs of each unit, including decommissioning. The energy and
capacity costs from VYNPC and nuclear decommissioning costs of the
Yankee companies that have been shut down are billed as purchased power
to PSNH.
The electricity produced by the Vermont Yankee nuclear generating
facility (VY) is committed substantially on the basis of ownership
interests and is billed pursuant to contractual agreements. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently on
February 26, 1992, December 4, 1996, and August 6, 1997, respectively.
Under ownership agreements with the Yankee companies, PSNH may be asked
to provide direct or indirect financial support for one or more of the
companies. For more information on the Yankee companies, see Note 5,
"Nuclear Decommissioning," and Note 11F, "Commitments and Contingencies
- Long-Term Contractual Arrangements."
Millstone 3: PSNH has a 2.85 percent joint ownership interest in
Millstone 3, a 1,154-MW nuclear generating unit. As of December 31,
1997 and 1996, plant-in-service included approxi-mately $118.7 million
and the accumulated provision for depreciation included approximately
$32.3 million and $29.4 million, respectively, for PSNH's share of
Millstone 3. PSNH's share of Millstone 3 expenses is included in the
corresponding operating expenses on the accompanying Statements of
Income. The Millstone 3 unit is out of service. NU hopes to return
Millstone 3 to service in early spring of 1998. For more information
on the Millstone 3 unit, see Note 11B, "Commitments and Contingencies -
Nuclear Performance."
Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman
Unit 4 (Wyman), a 632-MW oil-fired generating unit. At December 31,
1997 and 1996, plant-in-service included approximately $6.0 million,
respectively and the accumulated provision for depreciation included
approximately $3.9 million and $3.7 million, respectively, for PSNH's
share of Wyman. PSNH's share of Wyman expenses is included in the
corresponding operating expenses on the accompanying Statements of
Income.
F. DEPRECIATION
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agencies.
Except for major facilities, depreciation rates are applied to the
average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is
retired from service, the original cost of plant, including costs of
removal, less salvage, is charged to the accumulated provision for
depreciation. The depreciation rates for the several classes of
electric plant-in-service are equivalent to a composite rate of 3.7
percent in 1997 and 1996, and 3.8 percent in 1995. See Note 5,
"Nuclear Decommissioning," for information on nuclear plant
decommissioning.
PSNH's non-nuclear generating facilities have limited service lives.
Plant may be retired in place or dismantled based upon expected future
needs, the economics of the closure and environmental concerns. The
costs of closure and removal are incremental costs and, for financial
reporting purposes, are accrued over the life of the asset as part of
depreciation. At December 31, 1997 and 1996, the accumulated provision
for depreciation included approximately $34.2 million and $31.1
million, respectively, accrued for the cost of removal, net of salvage
for nonnuclear generation property.
G. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, industrial and commercial customers and limited retail
access programs, utility revenues are based on authorized rates applied
to each customer's use of electricity. In general, rates can be changed
only through a formal proceeding before the appropriate regulatory
commission. Regulatory commissions also have authority over the terms
and conditions of nontraditional rate making arrangements. At the end
of each accounting period, PSNH accrues an estimate for the amount of
energy delivered but unbilled.
For information on the PSNH rate proceeding and its impact on PSNH, see
Management's Discussion and Analysis of Financial Condition and Results
of Operations (MD&A).
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of PSNH and the accompanying financial
statements conform to generally accepted accounting principles
applicable to rate-regulated enterprises and reflect the effects of the
ratemaking process in accordance with SFAS 71, "Accounting for the
Effects of Certain Types of Regulation." Assuming a cost-of-service
based regulatory structure, regulators may permit incurred costs,
normally treated as expenses, to be deferred and recovered through
future revenues. Through their actions, regulators also may reduce or
eliminate the value of an asset, or create a liability. If any portion
of PSNH's operations were no longer subject to the provisions of SFAS
71, as a result of a change in the cost-of-service based regulatory
structure or the effects of competition, PSNH would be required to write
off all of its related regulatory assets and liabilities unless there is
a formal transition plan which provides for the recovery, through
established rates, for the collection of approved stranded costs and to
maintain the cost-of-service basis for the remaining regulated
operations. At the time of transition, PSNH would be required to
determine any impairment to the carrying costs of deregulated plant and
inventory assets.
Management anticipates that a restructuring program will be implemented
within New Hampshire during the next few years. In a restructured
environment, PSNH's generation business no longer will be rate regulated
on a cost-of-service basis. The majority of PSNH's regulatory assets
are related to its generation business.
The staff of the SEC has had concerns regarding the appropriateness of
the utilities' ability to continue application of SFAS 71 for the
generation portion of their business in a restructured environment. The
SEC referred the issue to the Emerging Issues Task Force (EITF) of the
FASB which reached a consensus and issued "Deregulation of the Pricing
of Electricity - Issues Related to the Application of FASB Statements
No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the future
recognition of regulatory assets for the portion of the business that no
longer qualifies for application of SFAS 71 depends on the regulators'
treatment of the recovery of those costs and other stranded assets from
cash flows of other portions of the business still considered to be
regulated, and (2) a utility should discontinue the application of SFAS
71 when a legislative and regulatory plan has been enacted, which would
include transition plans into a competitive environment, and when the
stranded costs which are subject to future rate recovery are determined.
EITF 97-4 became effective in August 1997.
The issue of restructuring the electric utility industry in New
Hampshire is currently the focus of negotiations and proceedings within
the federal and state court systems . Management believes that PSNH's
use of regulatory accounting remains appropriate while this issue
remains in litigation.
PSNH expects that its transmission and distribution business will
continue to be rate-regulated on a cost-of-service basis, and
accordingly, will continue to apply SFAS 71 to this portion of its
business.
For more information on PSNH's regulatory environment and the potential
impacts of rstructuring, see Note 11A, "Commitments and Contingencies -
Restructuring and Rate Matters," and the MD&A.
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," requires the evaluation of long-
lived assets, including regulatory assets, for impairment when certain
events occur or when conditions exist that indicate the carrying amounts
of assets may not be recoverable. SFAS 121 requires that any long-lived
assets which are no longer probable of recovery through future revenues
be revalued based on estimated future cash flows. If this revaluation is
less than the book value of the asset, an impairment loss would be
charged to earnings.
Management continues to believe that it is probable that PSNH will
recover its investments in long-lived assets through future revenues.
This conclusion may change in the future as the implementation of
restructuring plans within the state of New Hampshire will generally
require the formation of a separate generation entity which will be
subject to competitive market conditions. As a result, PSNH will be
required to assess the carrying amounts of its long-lived assets in
accordance with SFAS 121.
The components of PSNH's regulatory assets are as follows:
At December 31, 1997 1996
(Thousands of Dollars)
Recoverable energy costs, net
(Note 2K) ................................. $191,686 $211,236
Income taxes, net (Note 2I)................... 128,244 151,431
Unrecovered contractual
obligations (Note 5)........................ 83,042 50,271
Deferred costs, nuclear
plants (Note 3)............................ 281,856 269,233
Seabrook deferral (Note 2K)................... 8,376 -
Other......................................... 2,214 2,333
$695,418 $684,504
I. INCOME TAXES
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial statements
and the periods in which they affect the determination of taxable
income) is accounted for in accordance with the ratemaking treatment of
the applicable regulatory commissions. See Note 10, "Income Tax
Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give rise
to the accumulated deferred tax obligation is as follows:
At December 31, 1997 1996
(Restated) (Restated)
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences ........... $103,985 $225,263
Net operating loss (NOL)
carryforwards ............................. (94,822) (94,149)
Regulatory assets - income tax
gross up .................................. 49,101 68,652
Other ....................................... 146,142 58,888
$204,406 $258,654
At December 31, 1997, PSNH had a NOL carryforward of approximately $293
million, that can be used against PSNH's federal taxable income and
which, if unused, expires between the years 2000 and 2006. PSNH also
had Investment Tax Credit (ITC) carryforwards of $40 million which if
unused, expires between the years 1998 and 2004. For a portion of the
carryforward amounts indicated above, the reorganization of PSNH under
Chapter 11 of the United States Bankruptcy Code limits the annual
amount of NOL and ITC carryforwards that may be used. Approximately
$31 million of the NOL and $9 million of the ITC carryforwards are
subject to this limitation.
See Note 11A, "Commitments and Contingencies - Restructuring and Rate
Matters," for the possible impacts on PSNH from the NHPUC's decision
related to industry restructuring.
J. UNAMORTIZED ACQUISITION COSTS
The unamortized PSNH acquisition costs represent the aggregate value
placed by the 1989 rate agreement with the state of New Hampshire (Rate
Agreement) on PSNH's assets in excess of the net book value of PSNH's
non-Seabrook assets, plus the $700 million value assigned to Seabrook by
the Rate Agreement, as part of the bankruptcy resolution on June 5, 1992
(Acquisition Date). The Rate Agreement provides for the recovery
through rates, with a return, of the unamortized PSNH acquisition costs.
The Rate Agreement provides that $425 million of the unamortized PSNH
acquisition costs be amortized over the first seven years after PSNH's
May 16, 1991 reorganization from bankruptcy (Reorganization Date) with
the remaining amount to be amortized over the 20-year period after the
Reorganization Date. The unrecovered balance of PSNH acquisition costs
at December 31, 1997, was approximately $402.3 million. In accordance
with the Rate Agreement, approximately $32.9 million of this amount will
be recovered through rates by June 1, 1998, and the remaining amount of
approximately $369.4 million will be recovered through rates by 2011.
As of December 31, 1997, PSNH has collected approximately $591 million
of acquisition costs through rates.
K. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed for
its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary current
cost of fuel, to be fully recovered in rates like any other fuel cost.
PSNH is currently recovering these costs through rates. As of December
31, 1997, PSNH's total D&D deferrals were approximately $300 thousand.
The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail
customers, for a ten-year period that began in May 1991, the retail
portion of differences between the fuel and purchased power costs
assumed in the Rate Agreement and PSNH's actual costs, which include the
costs related to the Seabrook Power Contracts and the Clean Air Act
Amendment. The cost components of the FPPAC are subject to a prudence
review by the New Hampshire Public Utilities Commission (NHPUC).
Under the Rate Agreement, charges made by NAEC through the Seabrook
Power Contracts, including the deferred Seabrook capital expenses, are
being deferred by PSNH and subsequently will be subsequently billed and
collected by PSNH through the FPPAC. PSNH began to defer the amount of
these costs on December 1, 1997 and will continue to do so for the
period December 1, 1997 through May 31, 1998. Beginning on June 1,
1998, these costs will be recovered over a 36-month period. At December
31, 1997, PSNH has deferred approximately $8.4 million of these costs,
which balance is recorded in PSNH's deferred costs, nuclear plants.
On February 10, 1998, the NHPUC established a FPPAC rate for the period
December 1, 1997 through May 31, 1998. The new FPPAC rate increased
customer billings by approximately six percent. This rate continues to
defer a substantial portion of these costs.
At December 31, 1997, PSNH's net recoverable energy costs, excluding
current net recoverable energy costs, were approximately $191.7 million.
This amount includes approximately $172.9 million of deferred small
power producer costs.
See Note 11A, "Commitments and Contingencies - Restructuring and Rate
Matters" for the possible impacts on PSNH of the NHPUC's decision
related to industry restructuring.
L. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, PSNH must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the
selection and development of repositories for, and the disposal of,
spent nuclear fuel and high-level radioactive waste. Fees are billed
currently to customers and paid to the DOE on a quarterly basis.
The DOE was originally scheduled to begin accepting delivery of spent
fuel in 1998. However, delays in identifying a permanent storage site
have continually postponed plans for the DOE's long-term storage and
disposal site. Extended delays or a default by the DOE could lead to
consideration of costly alternatives. The company has primary
responsibility for the interim storage of its spent nuclear fuel.
Current capability to store spent fuel at Seabrook are estimated to be
adequate until the year 2010. Meeting spent fuel storage requirements
beyond this period could require new and separate storage facilities,
the costs for which have not been determined. Storage facilities for
Millstone 3 are expected to be adequate for the projected life of the
unit.
In November 1997, the U.S. District Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse the
DOE from meeting its contractual obligation to begin accepting spent
nuclear fuel no later than January 31, 1998. Currently, the DOE has not
taken the spent nuclear fuel as scheduled and, as a result, may have to
pay contract damages. The ultimate outcome of this legal proceeding is
uncertain at this time.
M. CASH AND CASH EQUIVALENTS
Cash and cash equivalents includes cash on hand and short-term cash
investments which are highly liquid in nature and have original
maturities of three months or less.
3. SEABROOK POWER CONTRACTS
PSNH and NAEC have entered into two power contracts that obligate PSNH to
purchase NAEC's 35.98 percent ownership of the capacity and output of
Seabrook for the term of Seabrook's Nuclear Regulatory Commission (NRC)
operating license. Under these power contracts, PSNH is obligated to pay
NAEC's cost of service during this period, regardless of whether Seabrook 1
is operating. NAEC's cost of service includes all of its Seabrook-related
costs, including operation and maintenance (O&M) expenses, fuel expense,
income and property tax expense, depreciation expense, certain overhead and
other costs and a return on its allowed investment.
PSNH has included its right to buy power from NAEC on its Balance Sheets as
part of utility plant and regulatory assets with a corresponding
obligation. At December 31, 1997, this right was valued at approximately
$917.1 million.
The contracts established the value of the initial investment in Seabrook
(initial investment) at $700 million. As prescribed by the Rate Agreement,
as of May 1, 1996, NAEC phased into rates 100 percent of its investment in
Seabrook 1. This plan is in compliance with SFAS 92,"Regulated Enterprises-
Accounting for Phase-in Plans." From the Acquisition Date through November
1997, NAEC recorded $203.9 million of deferred return on its investment in
Seabrook 1. At November 30, 1997, NAEC's utility plant included $84.1
million of deferred return that was transferred as part of the Seabrook
plant assets to NAEC on the Acquisition Date. Beginning on December 1,
1997, the deferred return, including the portion transferred to NAEC, is
currently being billed through the Seabrook Power Contracts to PSNH and
will be fully recovered from customers by May 2001. NAEC depreciated its
initial investment over the term of Seabrook 1's operating license (39
years), and any subsequent plant additions are depreciated on a straight-
line basis over the remaining term of the power contracts at the time the
subsequent additions are placed in service.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license, PSNH will be unconditionally required to pay NAEC termination
costs for 39 years, less the period during which Seabrook 1 has operated.
These termination costs will reimburse NAEC for its share of Seabrook 1
shut-down and decommissioning costs, and will pay NAEC a return of and on
any undepreciated balance of its initial investment over the remaining term
of the power contracts, and the return of and on any capital additions to
the plant made after the Acquisition Date over a period of five years after
shut down (net of any tax benefits to NAEC attributable the cancellation).
Contract payments charged to operating expenses are approximately:
Year Contract Payments
(Thousands of Dollars)
1997................................. $188,000
1996................................. 159,000
1995................................. 154,000
Interest included in the contract payment was $57 million in 1997, $55
million in 1996, and $51 million in 1995.
Future minimum payments, excluding executory costs, such as property taxes,
state use taxes, insurance and maintenance, under the terms of the
contracts, as of December 31, 1997, are approximately:
Year Seabrook Power Contracts
(Thousands of Dollars)
1998 ................................ $199,000
1999 ................................ 184,000
2000 ................................ 183,000
2001 ................................ 108,000
2002 ................................ 69,100
After 2002............................. 1,077,000
Future minimum payments................ 1,820,100
Less amount representing
interest............................. 903,000
Present value of Seabrook Power
Contracts payments .................. $ 917,100
See Note 11A, "Commitments and Contingencies - Restructuring and Rate
Matters" for the possible impacts the NHPUC's restructuring decision may
have on the Seabrook Power Contracts.
4. LEASES
PSNH has entered into lease agreements, some of which are capital leases,
for the use of data processing and office equipment, vehicles and office
space. The provisions of these lease agreements generally provide for
renewal options. The following rental payments have been charged to
expense:
Year Capital Leases Operating Leases
1997............ $1,579,000 $5,657,000
1996............ 1,105,000 4,884,000
1995............ 1,103,000 5,291,000
Interest included in capital lease rental payments was $272,000 in 1997,
$292,000 in 1996, and $351,000 in 1995.
Future minimum rental payments, excluding executory costs, such as property
taxes, state use taxes, insurance and maintenance, under long-term
noncancellable leases, as of December 31, 1997, are:
Year Capital Leases Operating Leases
(Thousands of Dollars)
1998 ...................... $1,500 $ 6,100
1999 ...................... 1,200 5,300
2000 ...................... 1,000 4,700
2001 ...................... 1,000 4,200
2002 ...................... 100 2,200
After 2002 .................... 500 5,100
Future minimum lease
payments .................... 5,300 $27,600
Less amount representing
interest ..................... 600
Present value of future
minimum lease payments ...... $4,700
5. NUCLEAR DECOMMISSIONING
Millstone and Seabrook: Millstone 3 and Seabrook 1 have service lives that
are expected to end during the years 2025 and 2026, respectively. Upon
retirement, these units must be decommissioned. Current decommissioning
studies concluded that complete and immediate dismantlement at retirement
continues to be the most viable and economic method of decommissioning
Millstone 3 and Seabrook 1. Decommissioning studies are reviewed and
updated periodically to reflect changes in decommissioning requirements,
costs, technology and inflation.
The estimated cost of decommissioning PSNH's 2.85 percent ownership share
of Millstone 3 and NAEC's 35.98 percent share of Seabrook 1, in year-end
1997 dollars, is $15.6 million and $170.2 million, respectively. Millstone
3 and Seabrook 1 decommissioning costs will be increased annually by their
respective escalation rates. PSNH's Millstone 3 decommissioning costs are
accrued over the expected service life of the unit and are included in
depreciation expense on its Statements of Income. Nuclear decommissioning
costs related to PSNH's share of Millstone 3 amounted to $0.4 million in
1997 and 1996, and $0.3 million in 1995. Nuclear decommissioning, as a
cost of removal, is included in the accumulated provision for depreciation
on PSNH's Balance Sheets. At December 31, 1997 and 1996, the balance in
the accumulated reserve for depreciation amounted to $4.3 million and $3.2
million, respectively.
PSNH makes payments to an independent decommissioning trust for its portion
of the costs of decommissioning Millstone 3. NAEC's portion of the cost of
decommissioning Seabrook 1 is paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the
estimated decommissioning costs assumes levelized collections for Millstone
3 and escalated collections for Seabrook 1, and after-tax earnings on the
Millstone and Seabrook decommissioning funds of approximately 5.5 percent
and 6.5 percent, respectively. Under the terms of the Rate Agreement, PSNH
is obligated to pay NAEC's share of Seabrook's decommissioning costs, even
if the unit is shut down prior to the expiration of its operating license.
Accordingly, NAEC bills PSNH directly for its share of the costs of
decommissioning Seabrook 1. PSNH records its Seabrook decommissioning costs
as a component of purchased power expense on its Statements of Income.
Under the Rate Agreement, PSNH's Seabrook decommissioning costs are
recovered through base rates.
As of December 31, 1997, PSNH collected through rates approximately $2.6
million toward the future decommissioning costs of its share of
Millstone 3, which has been transferred to the external decommissioning
trust. As of December 31, 1997, NAEC has paid approximately $21.1 million
(including payments made prior to the Acquisition Date by PSNH), into
Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning trust and financing fund increase the decommissioning trust
balance and the accumulated reserve for depreciation. Unrealized gains and
losses associated with the decommissioning trust and financing fund also
impact the balance of the trust, and the accumulated reserve for
depreciation.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. PSNH attempts to recover sufficient amounts
through its allowed rates to cover its expected decommissioning costs.
Only the portion of currently estimated total decommissioning costs that
has been accepted by regulatory agencies is reflected in rates of PSNH.
Based on present estimates and assuming its nuclear units operate to the
end of their respective licensing periods, PSNH expects that the
decommissioning trust and financing fund will be substantially funded when
the units are retired from service.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. PSNH's ownership share of
estimated costs, in year-end 1997 dollars, of decommissioning the unit owned
and operated by VYNPC is $20.2 million.
On August 6, 1997, the board of directors of MYAPC voted unanimously to
cease permanently the production of power at its nuclear generating facility
(MY). The NU system companies had relied on MY for approximately one
percent of their capacity. During November 1997, MYAPC filed an amendment
to its power contracts clarifying the obligations of its purchasing
utilities following the decision to cease power production. During January
1998, the FERC accepted the amendments and proposed rates, subject to
refund. At December 31, 1997, the remaining estimated obligation, including
decommissioning, amounted to approximately $867.2 million, of which PSNH's
share was approximately $43.4 million.
On December 4, 1996, the board of directors of CYAPC voted unanimously to
cease permanently the production of power at its nuclear generating plant
(CY). During 1996, the NU system companies had relied on CY for
approximately three percent of their capacity. During late December 1996,
CYAPC filed an amendment to its power contracts clarifying the obligations
of its purchasing utilities following the decision to cease power
production. On February 27, 1997, the FERC approved an order for hearing
which, among other things, accepted CYAPC's contract amendment. The new
rates became effective March 1, 1997, subject to refund. At December 31,
1997, the remaining estimated obligation, including decommissioning,
amounted to $619.9 million, of which PSNH's share was approximately $31.0
million.
YAEC is in the process of decommissioning its nuclear facility. At December
31, 1997, the estimated remaining costs, including decommissioning, amounted
to $124.4 million, of which PSNH's share was approximately $8.7 million.
Under the terms of the contracts with MYAPC, CYAPC and YAEC, the
shareholder-sponsor companies, including PSNH, are responsible for their
proportionate share of the costs of the units, including decommissioning.
Management expects that PSNH will continue to be allowed to recover these
costs from its customers. Accordingly, PSNH has recognized these costs as
regulatory assets, with corresponding obligations.
Proposed Accounting: The staff of the SEC has questioned certain current
accounting practices of the electric utility industry, including PSNH,
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating units in the financial statements. In response
to these questions, the FASB has agreed to review the accounting for closure
and removal costs, including decommissioning. If current electric utility
industry accounting practices for nuclear power plant decommissioning are
changed, the annual provision for decommissioning could increase relative to
1997, and the estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation), with recognition of an
increase in the cost of the related nuclear power plant. Management
believes that PSNH will continue to be allowed to recover decommissioning
costs through rates.
6. SHORT-TERM DEBT
The amount of short-term borrowings that may be incurred by PSNH is subject
to periodic approval by the SEC under the 1935 Act or by the NHPUC.
Effective May 1997, PSNH was authorized under a waiver from the NHPUC, to
incur short-term borrowings up to a maximum of $125 million.
PSNH has a $125 million revolving credit agreement that will expire in
April 1999. The revolving credit agreement is with a group of 16 banks.
PSNH is obligated to pay a facility fee of .50 percent per annum on the
commitment of $125 million. At December 31, 1997 and 1996, there were no
borrowings under the facility.
Under the credit facility discussed above, PSNH may borrow funds on a
short-term revolving basis under its agreement, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding.
Standby loans are based upon several alternative variable rates.
Money Pool: Certain subsidiaries of NU, including PSNH, are members of the
Northeast Utilities System Money Pool (Pool). The Pool provides a more
efficient use of the cash resources of the system, and reduces outside
short-term borrowings. NUSCO administers the Pool as agent for the member
companies. Short-term borrowing needs of the member companies are first
met with available funds of other member companies, including funds
borrowed by NU parent. NU parent may lend to the Pool but may not borrow.
Funds may be withdrawn from or repaid to the Pool at any time without prior
notice. Investing and borrowing subsidiaries receive or pay interest based
on the average daily Federal Funds rate. However, borrowings based on
loans from NU parent bear interest at NU parent's cost and must be repaid
based upon the terms of NU parent's original borrowing. At December 31,
1997 and 1996, PSNH had no outstanding borrowings from the Pool.
Maturities of PSNH's short-term debt obligations are for periods of three
months or less. For further information on short-term debt, see the MD&A.
7. EMPLOYEE BENEFITS
A. PENSION BENEFITS
The NU system subsidiaries participate in a uniform noncontributory
defined benefit retirement plan covering all regular NU system
employees. Benefits are based on years of service and employees'
highest eligible compensation during 60 consecutive months of
employment. PSNH's direct portion of the NU system's pension cost,
part of which was charged to utility plant, approximated $1.3 million
in 1997, $6.2 million in 1996, and $2.3 million in 1995. Pension
(credits)/costs for 1997 and 1996 included approximately $(1.0) million
and $1.9 million, respectively, related to workforce reduction
programs.
Currently, PSNH funds annually an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are
determined using market-related values of pension assets. Pension
assets are invested primarily in domestic and international equity
securities and bonds.
The components of net pension cost for PSNH are:
For the Years Ended December 31, 1997 1996 1995
(Thousands of Dollars)
Service cost.......................... $ 2,987 $ 6,161 $ 3,462
Interest cost......................... 13,398 12,808 11,923
Return on plan assets................. (34,622) (24,393) (33,156)
Net amortization...................... 19,508 11,608 20,108
Net pension cost...................... $ 1,271 $ 6,184 $ 2,337
For calculating pension cost, the following assumptions were
used:
For the Years Ended December 31, 1997 1996 1995
Discount rate.......................... 7.75% 7.50% 8.25%
Expected long-term rate of return...... 9.25 8.75 8.50
Compensation/progression rate.......... 4.75 4.75 5.00
The following table represents the plan's funded status
reconciled to the Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31, 1997 and 1996 of
$(140,089,000) and $(131,624,000),
respectively ........................... $(152,709) $(143,377)
Projected benefit obligation ............. $(187,968) $(179,192)
Market value of plan assets .............. 195,612 173,035
Market value in excess (less than) of
projected benefit obligation ............. 7,644 (6,157)
Unrecognized transition amount ............ 4,003 4,337
Unrecognized prior service costs .......... 7,597 8,135
Unrecognized net gain ..................... (65,305) (51,105)
Accrued pension liability ................. $(46,061) $ (44,790)
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
For the Years Ended December 31, 1997 1996
Discount rate................................ 7.25% 7.75%
Compensation/progression rate................ 4.25 4.75
B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system subsidiaries provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees (referred to as SFAS 106 benefits).
These benefits are available for employees retiring from the NU system
who have met specified service requirements. For current employees and
certain retirees, the total SFAS 106 benefit is limited to two times
the 1993 per-retiree health care cost. The SFAS 106 obligation has been
calculated based on this assumption. PSNH's direct portion of SFAS 106
benefits, part of which was deferred or charged to utility plant,
approximated $4.9 million in 1997, $6.2 million in 1996, and $7.2
million in 1995.
PSNH is funding SFAS 106 postretirement costs through external trusts.
PSNH is funding, on an annual basis, amounts that have been rate-
recovered and which also are tax-deductible under the Internal Revenue
Code. The trust assets are invested primarily in equity securities and
bonds.
The components of health care and life insurance cost are:
For the Years Ended December 31, 1997 1996 1995
(Thousands of Dollars)
Service cost .................... $ 802 $ 914 $ 933
Interest cost ................... 3,352 3,559 4,063
Return on plan assets ........... (3,753) (1,720) (1,694)
Amortization of unrecognized
transition obligation ......... 2,941 2,941 2,941
Other amortization, net ......... 1,541 547 998
Net health care and life
insurance cost ................ $4,883 $6,241 $7,241
For calculating PSNH's SFAS 106 benefit costs, the following
assumptions were used:
For the Years Ended December 31, 1997 1996 1995
Discount rate .................... 7.75% 7.50% 8.00%
Long-term rate of return -
Health assets, net of tax ..... 6.00 5.25 5.00
Life assets ................... 9.25 8.75 8.50
The following table represents the plan's funded status reconciled to
the Balance Sheets:
At December 31, 1997 1996
(Thousands of Dollars)
Accumulated postretirement benefit
obligation of:
Retirees ............................ $(36,790) $(38,245)
Fully eligible active
employees ......................... (31) (22)
Active employees not
eligible to retire ................ (9,788) (9,696)
Total accumulated post-
retirement benefit
obligation ........................... (46,609) (47,963)
Market value of plan assets ............ 22,908 17,882
Accumulated postretirement
benefit obligation in
excess of plan assets ................ (23,701) (30,081)
Unrecognized transition
amount ............................... 44,108 47,049
Unrecognized net gain .................. (20,407) (17,139)
Accrued postretirement benefit
liability ............................ $ - $ (171)
The following actuarial assumptions were used in calculating
the plan's year-end funded status:
At December 31, 1997 1996
Discount rate ............................. 7.25% 7.75%
Health care cost trend rate (a) ........... 5.76 7.23
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 4.40 percent by 2001.
The effect of increasing the assumed health care cost trend rate by one
percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1997, by $3.1
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$245 thousand. The trust holding the health plan assets is subject to
federal income taxes at a 39.6 percent tax rate.
PSNH currently is recovering SFAS 106 costs through rates.
8. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
Shares
Outstanding December 31,
Description December 31, 1997 1997 1996 1995
(Thousands of Dollars)
10.60%
Series A of 1991 .......... 4,000,000 $100,000 $125,000 $125,000
Less preferred stock
to be redeemed
within one year ......... 1,000,000 25,000 25,000 -
Total preferred stock
subject to
mandatory redemption .... $ 75,000 $100,000 $125,000
In case of default on dividends or sinking-fund payments, no payments may
be made on any junior stock by way of dividends or otherwise (other than in
shares of junior stock) so long as the default continues. If PSNH is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, PSNH would be prohibited from redemption or purchase of less than
all of the preferred stock outstanding. The Series A Preferred
Stock is not subject to optional redemption by PSNH. It is subject to an
annual sinking fund requirement of $25 million, which began on June 30,
1997, sufficient to retire annually 1,000,000 shares at $25 per share.
9. LONG-TERM DEBT
Details of long-term debt outstanding are:
At December 31 1997 1996
(Thousands of Dollars)
First Mortgage Bonds:
9.17% Series B, due 1998..................... $170,000 $170,000
Total First Mortgage Bonds............... 170,000 170,000
Pollution Control Revenue Bonds:
7.65% Tax-Exempt Series A, due 2021............ 66,000 66,000
7.50% Tax-Exempt Series B, due 2021............ 108,985 108,985
7.65% Tax-Exempt Series C, due 2021............ 112,500 112,500
Adjustable Rate, Taxable, Series D,
due 2021 ....................................... 39,500 39,500
Adjustable Rate, Taxable, Series E,
due 2021 ....................................... 69,700 69,700
Adjustable Rate, Tax-Exempt, Series D,
due 2021 ....................................... 75,000 75,000
Adjustable Rate, Tax-Exempt, Series E
due 2021 ....................................... 44,800 44,800
Less: Amounts due within one year ............... 170,000 -
Long-term debt, net ....................... $516,485 $686,485
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1997 aggregate approximately $170 million for
1998. There are neither sinking-fund requirements nor debt maturities
existing for the years 1999 through 2002. Also, there are annual renewal
and replacement fund requirements equal to 2.25 percent of the average of
net depreciable utility property owned by PSNH at the Reorganization Date,
plus cumulative gross property additions thereafter. PSNH expects to meet
these future fund requirements by certifying property additions. Any
deficiency would need to be satisfied by the deposit of cash or bonds.
Essentially, all utility plant of PSNH is subject to the lien of its first
mortgage bond indenture. PSNH's Revolving Credit Facility has a second
lien, junior to the lien of its first mortgage bond indenture, on all PSNH
property located in New Hampshire which will expire in April 1999. At
December 31, 1997, there were no borrowings under the Revolving Credit
Facility.
Concurrent with the issuance of PSNH's Series A and B First Mortgage Bonds,
PSNH entered into financing arrangements with the Business Finance
Authority of the state of New Hampshire (BFA). Pursuant to these
arrangements, the BFA issued seven series of Pollution Control Revenue
Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1997,
approximately $516.5 million of PCRBs were outstanding. The average
effective interest rates on the variable-rate pollution control notes
ranged from 3.8 percent to 5.6 percent for 1997, and from 3.5 percent to
5.5 percent for 1996. PSNH's obligation to repay each series of PCRBs is
secured by a series of First Mortgage Bonds that were issued under its
indenture. Each such series of First Mortgage Bonds contains terms and
provisions with respect to maturity, principal payment, interest rate, and
redemption that correspond to those of the applicable series of PCRBs. For
financial reporting purposes, these bonds would not be considered
outstanding unless PSNH fails to meet its obligations under the PCRBs.
The PCRBs, except for Series D and E, are redeemable on or after May 1,
2001, at the option of the company with accrued interest and at specified
premiums. Under current interest rate elections by PSNH, the Series D and
E PCRBs are redeemable, at par plus accrued interest at the end of each
interest-rate period. Future interest-rate elections by PSNH could
significantly defer or eliminate the availability of optional redemptions
by PSNH, and could affect costs as well.
10.INCOME TAX EXPENSE
The components of the federal and state income tax provisions charged to
operations are:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Current income taxes:
Federal ............................... $67,148 $(4,978) $(1,166)
State ................................. 48 (1,605) 1,767
Total current ....................... 67,196 (6,583) 601
Deferred income taxes, net:
Federal ............................... 20,983 95,225 72,147
State ................................. 1,202 306 (1,606)
Total deferred ..................... 22,185 95,531 70,541
Investment tax credits, net ............. (540) (548) (555)
Total income tax expense ................ $88,841 $88,400 $70,587
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses ............................... $86,450 $80,677 $69,817
Other income taxes ...................... 2,391 7,723 770
Total income tax expense ................ $88,841 $88,400 $70,587
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Depreciation ............................ $(1,937) $(1,055) $ 1,294
Deferred tax asset associated
with NOL .............................. - 96,756 57,543
Energy adjustment clauses ............... 16,839 (10,716) 5,098
Amortization of regulatory
settlement ............................ 11,501 11,501 11,501
Other ................................... (4,218) (955) (4,895)
Deferred income taxes, net .............. $22,185 $95,531 $70,541
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rate is as follows:
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income ........... $63,355 $64,931 $53,845
Tax effect of differences:
Depreciation .......................... 1,890 1,896 1,868
Amortization of acquisition costs ..... 31,298 31,410 31,522
Seabrook intercompany loss ............ (4,616) (7,504) (13,048)
Investment tax credit amortization .... (540) (548) (555)
State income taxes, net of
federal benefit ..................... 1,085 (845) 105
Other, net ............................ (3,631) (940) (3,150)
Total income tax expense ................ $88,841 $88,400 $70,587
11. COMMITMENTS AND CONTINGENCIES
A.RESTRUCTURING AND RATE MATTERS
The 1996 restructuring legislation that the NHPUC is charged with
implementing provides that the NHPUC may not adopt a restructuring plan
that imposes a severe financial hardship on a utility. Management
believes that PSNH is entitled to full recovery of its prudently
incurred costs, including regulatory assets and other strandable costs.
It bases this belief both on the general nature of public utility
industry cost-of-service based regulation and the specific circumstances
of the resolution of PSNH's previous bankruptcy proceedings and its
acquisition by NU, including the recoveries provided by the Rate
Agreement and related agreements.
On February 28, 1997, the NHPUC issued its decision related to
restructuring the state's electric utility industry and setting interim
stranded cost charges for PSNH pursuant to legislation enacted in New
Hampshire in 1996. In the decision, the NHPUC announced a departure
from cost-based ratemaking and instead adopted a market-priced approach
to ratemaking and stranded cost recovery. Accordingly, unless the NHPUC
modifies its position or the litigation described below results in
necessary modifications to the final plan which leads management to
conclude that the ratemaking approach utilized in the NHPUC's
restructuring decision will not go into effect, PSNH no longer will be
subject to the provisions of SFAS 71. That would result in PSNH
writing off from its balance sheet substantially all of its regulatory
assets. The amount of the potential write-off triggered by the order is
currently estimated at over $400 million, after taxes. PSNH does not
believe that under the decision, it would be required to recognize any
additional loss resulting from the impairment of the value of its other
long-lived assets under the provisions of SFAS 121.
On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary
restraining order, preliminary and permanent injunctive relief and for
declaratory judgment in the United States District Court for New
Hampshire (District Court). The case was subsequently transferred to
Rhode Island. On March 10, 1997, the Chief Judge of the Rhode Island
federal court issued a temporary restraining order which stayed the
NHPUC's February 28, 1997 decision to the extent it established a rate-
setting methodology that is not designed to recover PSNH's costs of
providing service and would require PSNH to write off any regulatory
assets.
During 1997, a mediation process ended without a resolution. The
District Court had suspended the procedural schedule associated with
this court proceeding pending the resolution of appeals of certain
preliminary rulings by the U.S. Circuit Court of Appeals for the First
Circuit (First Circuit). On February 3, 1998, the First Circuit denied
the appeals taken by would-be intervenors in PSNH's federal court
proceeding concerning the NHPUC's final plan on restructuring. The
First Circuit affirmed a previous court decision stating that the
opposing interests in this case were adequately represented by the NHPUC
or by PSNH. As a result of this decision, the proceedings in the
District Court may resume. On February 17, 1998, the NHPUC filed a
petition for rehearing with the First Circuit. The temporary
restraining order issued by the District Court in March 1997 will remain
in effect until further orders by either court.
During 1997, the NHPUC reopened its proceeding to reconsider certain
limited matters in its restructuring orders. The scope of the PSNH-
specific rehearing proceedings included alternative rate-setting
methodologies proposed by the intervenors; to decide the appropriate
methodology to be used to determine PSNH's interim stranded costs; and
to set PSNH's interim stranded cost charges utilizing the determined
methodology. In testimony filed with the NHPUC in November 1997, PSNH
proposed a new methodology to quantify its strandable costs. Under this
proposal, PSNH would divest all owned generation and purchased-power
obligations via auction. To the extent that the auction fails to
produce sufficient revenues to cover the net book value of owned
generation and contractual payment obligations of purchased-power, the
difference would be recovered from customers through a non-bypassable
distribution charge. The new proposal also relies upon securitization
of certain assets to further reduce rates.
On December 15, 1997, the NHPUC officially announced that industry
restructuring would not take place on January 1, 1998. Management
believes that industry restructuring will not take place in New
Hampshire until the courts resolve the issues brought before them, or
the parties involved reach a settlement.
PSNH and NAEC are parties to a variety of financing agreements providing
that the credit thereunder can be terminated or accelerated if they do
not maintain specified minimum ratios of common equity to capitalization
(as defined in each agreement). In addition, PSNH and NAEC are parties
to a variety of financing agreements providing in effect that the credit
thereunder can be terminated or accelerated if there are actions taken,
either by PSNH or NAEC or by the state of New Hampshire, that deprive
PSNH and/or NAEC of the benefits of the Rate Agreement and/or the
Seabrook Power Contracts.
If the NHPUC's February 28, 1997 decision were to become effective, it
would, unless PSNH and NAEC receive waivers from their respective
lenders, result in (i) write-offs that would cause PSNH's common equity
to fall below the contractual minimums (ii) reductions in income that
would cause PSNH's income to fall below the contractual minimums, (iii)
potential violation of the contractual provisions with respect to
actions depriving PSNH and NAEC of the benefits of the Rate Agreement
and (iv) the potential for cross defaults to other PSNH and NAEC
financing documents. Substantially all of PSNH's and NAEC's debt
obligations would be affected.
If these events transpired and if the creditors holding PSNH and NAEC
debt obligations decide to exercise their rights to demand payment then
either creditors or PSNH and NAEC could initiate proceedings under
Chapter 11 of the bankruptcy laws.
As a result of the NHPUC decision and the potential consequences
discussed above, the reports of our auditors on the individual financial
statements of PSNH and NAEC contain explanatory paragraphs. Those
explanatory paragraphs indicate that a substantial doubt exists
currently about the ability of PSNH and NAEC to continue as going
concerns. The accounts of PSNH and NAEC are included in the
consolidated financial statements of NU on the basis of a going concern.
While the effect of the implementation of that decision would have a
material adverse impact on NU's financial position, results of
operations, and cash flows, it would not in and of itself result in
defaults under borrowing or other financial agreements of NU or its
other subsidiaries.
On May 2, 1997, PSNH made a rate filing with the NHPUC. For information
regarding this rate proceeding, see the MD&A.
For information regarding the FERC rate proceedings for CYAPC and MYAPC,
see Note 5, "Nuclear Decommissioning."
B. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. Millstone 1,
2 and 3 have been out of service since November 4, 1995, February 21,
1996 and March 30, 1996, respectively, and are on the NRC's watch list.
PSNH's ownership interest in the Millstone units is limited to a 2.85
percent joint ownership interest in Millstone 3. NU has restructured its
nuclear organization and is currently implementing comprehensive plans
to restart the units.
Subsequent to its January 31, 1996 announcement that Millstone had been
placed on its watch list, the NRC stated that the units cannot return
to service until independent, third-party verification teams have
reviewed the actions taken to improve the design, configuration and
employee concerns issues that prompted the NRC to place the units on
its watch list. The actual date of the return to service for each of
the units is dependent upon the completion of independent inspections
and reviews by the NRC and a vote by the NRC commissioners. NU hopes
to return Millstone 3 to service in early spring of 1998 and Millstone
2 three to four months after Millstone 3. Millstone 1 is currently in
extended maintenance status.
Management cannot predict when the NRC will allow any of the Millstone
units to return to service and thus cannot precisely estimate the total
replacement power costs the NU system companies will ultimately incur.
Replacement power costs incurred by NU attributable to the Millstone
outages averaged approximately $28 million per month during 1997, and
for 1998 are projected to average approximately $9 million per month
for Millstone 3, $9 million per month for Millstone 2, and $6 million
per month for Millstone 1 while the plants remain out of service. To
date, PSNH's share of replacement power costs has not been material.
PSNH's share of replacement power costs is not expected to be material
for 1998, while Millstone 3 is out of service. CL&P, WMECO and PSNH
will continue to expense their replacement power costs in 1998.
Based on the current estimates of expenditures and restart dates,
management believes the NU system has sufficient resources to fund the
restoration of the Millstone units and related replacement power costs.
If the return to service of Millstone 3 or 2 is delayed substantially
beyond the present restart estimates, if some financing facilities
become unavailable because of difficulties in meeting borrowing
conditions or renegotiating extensions, if CL&P and WMECO encounter
additional significant costs or if any other significant deviations
from management's assumptions occur, CL&P and WMECO could be unable to
meet their cash requirements. In those circumstances, management would
take even more stringent actions to reduce costs and cash outflows and
attempt to obtain additional sources of funds. The availability of
these funds would be dependent upon general market conditions and
CL&P's and WMECO's respective credit and financial conditions at that
time.
For information regarding Millstone restart costs, see the MD&A.
Litigation: On August 7, 1997, the non-NU owners of Millstone 3 filed
demands for arbitration with CL&P and WMECO as well as lawsuits in
Massachusetts Superior Court against NU and its current and former
trustees. The non-NU owners raise a number of contract, tort and
statutory claims arising out of the operation of Millstone 3. The
arbitrations and lawsuits seek to recover compensatory damages, punitive
damages, treble damages and attorneys' fees. Owners representing
approximately two-thirds of the non-NU interests in Millstone 3 claimed
compensatory damages in excess of $200 million. In addition, one of the
lawsuits seeks to restrain NU from disposing of its shares of the stock
of WMECO and HWP, pending the outcome of the lawsuit. Management cannot
estimate the potential outcome of these suits but believes there is no
legal basis for the claims and intends to defend against them
vigorously. To date, no reserves have been established for this
litigation. At December 31, 1997, the costs related to this litigation
for the NU system were estimated to be $100 million for incremental O&M
costs and approximately $100 million for replacement power costs. These
costs are likely to increase as long as Millstone 3 remains out of
service.
C. ENVIRONMENTAL MATTERS
The NU system is subject to regulation by federal, state and local
authorities with respect to air and water quality, the handling and
disposal of toxic substances and hazardous and solid wastes, and the
handling and use of chemical products. The NU system has an active
environmental auditing and training program and believes that it is in
substantial compliance with current environmental laws and regulations.
However, the NU system is subject to certain pending enforcement
actions and governmental investigations in the environmental area.
Management cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations and
other facilities. Changing environmental requirements could also
require extensive and costly modifications to PSNH's existing
generating units, and transmission and distribution systems, and could
raise operating costs significantly. As a result, PSNH may incur
significant additional environmental costs, greater than amounts
included in cost of removal and other reserves, in connection with the
generation and transmission of electricity and the storage,
transportation and disposal of by-products and wastes. PSNH may also
encounter significantly increased costs to remedy the environmental
effects of prior waste handling activities. The cumulative long-term
cost impact of increasingly stringent environmental requirements cannot
be estimated accurately.
PSNH has recorded a liability based upon currently available
information for what it believes are its estimated environmental
remediation costs that it expects to incur for waste disposal sites.
In most cases, additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown
magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 1997,
the net liability recorded by PSNH for its estimated environmental
remediation costs, excluding any possible insurance recoveries or
recoveries from third parties, amounted to approximately $5.6 million,
which management has determined to be the most probable amount.
During 1997, PSNH adopted Statement of Position 96-1, "Environmental
Remediation Liabilities" (SOP). The principal objective of the SOP is
to improve the manner in which existing authoritative accounting
literature is applied by entities to specific situations of
recognizing, measuring and disclosing environmental remediation
liabilities. The adoption of the SOP resulted in an increase of
approximately $400 thousand to PSNH's environmental reserve in 1997.
PSNH cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against
it. However, considering known facts, existing laws, and regulatory
practices, management does not believe the matters disclosed above will
have a material effect on PSNH's financial position or future results
of operations.
D. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at one
of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an owner of
a nuclear unit could be assessed in proportion to its ownership
interest in each of its nuclear units up to $75.5 million. Payments of
this assessment would be limited to $10.0 million in any one year per
nuclear incident based upon the owner's pro rata ownership interest in
each of its nuclear units. In addition, the owner would be subject to
an additional five percent or $3.8 million, in proportion to its
ownership interests in each of its nuclear units, if the sum of all
claims and costs from any one nuclear incident exceeds the maximum
amount of financial protection. Under the terms of the Seabrook Power
Contracts with NAEC, PSNH could be obligated to pay for any assessment
charged to NAEC as a "cost of service." Based on its ownership
interest in Millstone 3 and NAEC's ownership interest in Seabrook 1,
PSNH's maximum liability, including any additional assessments, would
be $30.8 million per incident of which payments would be limited to
$3.9 million per year. In addition, through power purchase contracts
with MYAPC, VYNPC and CYAPC, PSNH would be responsible for up to an
additional $11.1 million per incident, of which payments would be
limited to a maximum of $1.4 million per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences at Millstone 3 and CY. PSNH is subject to
retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessment against PSNH
with respect to losses arising during the current policy year is
approximately $0.4 million under the primary property insurance
program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and the
excess cost of repair, replacement, or decontamination or premature
decommissioning of utility property resulting from insured occurrences.
PSNH is subject to retroactive assessments if losses exceed the
accumulated funds available to the insurer. The maximum potential
assessments against PSNH (including costs resulting from PSNH's
contracts with NAEC), with respect to losses arising during current
policy years are approximately $2.2 million under the replacement power
policies and $5.2 million under the excess property damage,
decontamination and decommissioning policies. Although PSNH has
purchased the limits of coverage currently available from the
conventional nuclear insurance pools, the cost of a nuclear incident
could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry
basis for coverage of worker claims. All participating reactor
operators insured under this coverage are subject to retrospective
assessments of $3 million per reactor. The maximum potential assessment
against PSNH (including costs resulting from the Seabrook Power
Contracts with NAEC), with respect to losses arising during the current
policy period is approximately $1.8 million. Effective January 1,
1998, a new worker policy was purchased which is not subject to
retrospective assessments.
E. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision by
management. PSNH currently forecasts construction expenditures of
approximately $302.6 million for the years 1998-2002, including
approximately $41.9 million for 1998. In addition, PSNH estimates that
nuclear fuel requirements, for its share of Millstone 3, will be $5.1
million for the years 1998-2002, including $1.7 million for 1998.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: PSNH, CL&P and WMECO rely on VY for approximately
1.7 percent of their capacity under long-term contracts. Under the
terms of their agreements, the NU system companies pay their ownership
(or entitlement) shares of costs, which include depreciation, O&M
expenses, taxes, the estimated cost of decommissioning and a return on
invested capital. These costs are recorded as purchased power expense
and are recovered through the companies' rates. PSNH's total cost of
purchases under contracts with VYNPC, amounted to $6.2 million in 1997,
$6.5 million in 1996 and 1995.
The other Yankee generating facilities, MY, CY and Yankee Rowe, were
permanently shutdown as of August 6, 1997, December 4, 1996, and
February 26, 1992, respectively. See Note 2E, "Summary of Significant
Accounting Policies-Investments and Jointly Owned Electric Utility
Plant," for more information on the Yankee companies. See Note 5,
"Nuclear Decommissioning," regarding information on the related
decommissioning studies.
Nonutility Generators (NUGs): PSNH has requirements under various
arrangements for the purchase of capacity and energy from NUGs. These
arrangements have terms from 20 to 30 years, currently expiring in the
years 1998 through 2023, and require PSNH to purchase energy at
specified prices or formula rates. For the 12 months ending December
31, 1997, approximately 14 percent of the NU system electricity
requirements were met by NUGs. PSNH's total cost of purchases under
these arrangements amounted to $133.1 million in 1997, $132.6 million
in 1996, and $124.0 million in 1995. These costs may be deferred for
eventual recovery through rates. For additional information, see Note
2K, "Summary of Significant Accounting Policies-Recoverable Energy
Costs."
New Hampshire Electric Cooperative: PSNH entered into a buy-back
agreement to purchase the capacity and energy of the New Hampshire
Electric Cooperative, Inc.'s (NHEC) share of Seabrook 1 and to pay all
of NHEC's Seabrook 1 costs for a ten-year period, which began on July
1, 1990. The total cost of purchases under this agreement was $23.4
million in 1997, $14.6 million in 1996, and $15.8 million in 1995. The
total cost of these purchases has been collected through the FPPAC in
accordance with the Rate Agreement. In connection with the agreement,
NHEC agreed to continue as a firm-requirements customer of PSNH for 15
years.
Hydro-Quebec: Along with other New England utilities, PSNH, CL&P,
WMECO, and HWP have entered into agreements to support transmission and
terminal facilities to import electricity from the Hydro-Quebec system
in Canada. PSNH is obligated to pay, over a 30-year period ending in
2020, its proportionate share of the annual O&M and capital costs of
these facilities.
Estimated Annual Costs: The estimated annual costs of PSNH's
significant long-term contractual arrangements are as follows:
1998 1999 2000 2001 2002
(Millions of Dollars)
VYNPC ................... $ 7.1 $ 7.1 $ 6.7 $ 7.4 $ 7.7
NUGs .................... 139.4 142.9 147.1 151.3 155.5
NHEC .................... 30.0 30.0 14.6 - -
Hydro-Quebec ............ 10.2 9.8 9.7 9.4 9.2
For additional information regarding the recovery of purchased
power costs, see Note 2K, "Summary of Significant Accounting Policies -
Recoverable Energy Costs."
G. DEFERRED RECEIVABLE FROM AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance
with the phase-in under the Rate Agreement, it began accruing a
deferred return on a portion of its Seabrook investment. From May 16,
1991 to the Acquisition Date, PSNH accrued a deferred return of $50.9
million. On the Acquisition Date, PSNH sold the $50.9 million deferred
return to NAEC as part of the Seabrook-related assets.
At the time PSNH transferred the deferred return to NAEC, it realized,
for income tax purposes, a gain that is deferred under the consolidated
income tax rules. Beginning December 1, 1997, this gain is being
restored for income tax purposes, as the deferred return of $50.9
million, and the associated income taxes of $32.9 million, are being
collected by NAEC through the Seabrook Power Contracts. As NAEC
recovers the $32.9 million in years eight through ten of the Rate
Agreement, it will be obligated to make these corresponding payments to
PSNH.
On the Acquisition Date, PSNH recorded the $32.9 million of income
taxes associated with the deferred return as a deferred receivable from
NAEC, with a corresponding entry to deferred revenue, on its Balance
Sheet. In 1993, due to changes in tax rates, this amount was adjusted
to $33.2 million.
For further information related to the phase-in of the Seabrook power
plant, see Note 3, "Seabrook Power Contracts."
See Note 11A, "Commitments and Contingencies - Restructuring and Rate
Matters" for the possible impacts of the NHPUC's decision related to
industry restructuring on this intercompany transaction between PSNH
and NAEC.
12.FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate
fair value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity
Securities," requires investments in debt and equity securities to be
presented at fair value. Unrealized gains and losses resulting from the
use of SFAS 115 accounting have not been material.
Preferred stock and long-term debt: The fair value of PSNH's fixed-rate
securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair
value equal to their carrying value. The carrying amounts of PSNH's
financial instruments and the estimated fair values are as follows:
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption........................ $100,000 $ 99,000
Long-term debt - First Mortgage Bonds......... 170,000 170,425
Other long-term debt.......................... 516,485 537,599
Carrying Fair
At December 31, 1996 Amount Value
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption........................ $125,000 $125,000
Long-term debt - First Mortgage Bonds......... 170,000 175,729
Other long-term debt.......................... 516,485 523,536
The fair values shown above have been reported to meet the disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Public Service Company of New Hampshire:
We have audited the accompanying balance sheets, as restated - see Note 1,
of Public Service Company of New Hampshire (a New Hampshire corporation and
a wholly owned subsidiary of Northeast Utilities) as of December 31, 1997
and 1996, and the related statements of income, common stockholder's
equity, and cash flows, as restated - see Note 1, for each of the three
years in the period ended December 31, 1997. These financial statements
are the responsibility of the company's management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Public Service Company
of New Hampshire as of December 31, 1997 and 1996, and the results of its
operations and its cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
The accompanying financial statements have been prepared assuming that the
company will continue as a going concern. As discussed in Note 11A, on
February 28, 1997, the State of New Hampshire Public Utilities Commission
(the NHPUC) issued an order outlining its final plan to restructure the
electric utility industry. The final plan announced a departure from cost-
based rate making, which, if implemented, would require the company to
discontinue the application of Financial Accounting Standard No. 71,
"Accounting for the Effects of Certain Types of Regulation," (FAS 71). The
implementation of the final plan, including the effect of the
discontinuation of FAS 71, would result in after tax write-off of over $400
million. Such a write-off would cause the company to be in technical
default under financial covenants imposed by lenders, which, would, if not
waived or renegotiated, give rise to the rights of lenders to accelerate
the repayment of approximately $686 million of the company's indebtedness
and approximately $495 million of an affiliated company's indebtedness.
These conditions raise substantial doubt about the company's ability to
continue as a going concern. The financial statements referred to above do
not include any adjustments that might result from the outcome of this
uncertainty.
As explained in Note 1 to the consolidated financial statements, the
company has given retroactive effect to the change in accounting for
nuclear compliance costs.
/s/ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 1998 (except with respect to the matter discussed in
Note 1, as to which the date is June 10, 1998)
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
Management's Discussion and Analysis of Financial
Condition and Results of Operations
This section contains management's assessment of Public Service Company of New
Hampshire's (PSNH or the company) financial condition and the principal factors
having an impact on the results of operations. The company is a wholly-owned
subsidiary of Northeast Utilities (NU). This discussion should be read in
conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
Net income was approximately $92 million for 1997 compared to approximately $97
million for 1996. The decrease in net income was primarily due to higher
operation expenses.
Retail kilowatt-hour sales were essentially unchanged in 1997.
A significant issue facing PSNH in 1998 is the industry restructuring efforts in
New Hampshire. A temporary restraining order issued by a U.S. District Court is
currently blocking the New Hampshire Public Utilities Commission (NHPUC) from
implementing a February 1997 restructuring order that would have resulted in a
write-off by PSNH of more than $400 million. Management hopes to negotiate an
alternative restructuring proposal in 1998 that will produce significant PSNH
rate reductions and allow retail customers to choose their electric suppliers,
but still give PSNH and North Atlantic Energy Corporation (NAEC) an opportunity
to maintain an adequate financial condition and earn fair returns on their
investments.
RESTRUCTURING
In February, 1997, the NHPUC issued orders to restructure the state's electric
utility industry and set interim stranded cost charges for PSNH. In the orders,
the NHPUC announced a departure from cost-based ratemaking and adopted a market-
priced approach to stranded cost recovery. PSNH, NU, NAEC and Northeast
Utilities Service Company (NUSCO) filed for a temporary restraining order,
preliminary and permanent injunctive relief and a declaratory judgment in the
United States District Court of New Hampshire. The case subsequently was
transferred to the United States District Court of Rhode Island (District Court)
where a temporary restraining order was granted, staying, indefinitely, the
enforcement of the NHPUC's restructuring orders as they affected PSNH. Certain
appeals to the preliminary ruling have been denied and proceedings in the
District Court are expected to resume.
The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate
methodology to be used to determine PSNH's interim stranded costs and to set
PSNH's interim stranded cost charges utilizing the determined methodology. The
NHPUC has not indicated when it will issue a decision in these proceedings.
On December 15, 1997, the NHPUC officially announced that industry restructuring
would not take place on January 1, 1998. On December 24, 1997, the Governor's
office filed a motion with the NHPUC formally requesting that certain issues
concerning the rate agreement (Rate Agreement) between NU, PSNH and the state of
New Hampshire, entered into in 1989 in connection with NU's reorganization plan
to resolve PSNH's bankruptcy, be transferred to the New Hampshire Supreme Court
for decision. The motion recommends that the NHPUC not issue any new rulings
concerning the Rate Agreement pending such Supreme Court decision. On February
20, 1998, the NHPUC petitioned the New Hampshire Supreme Court to review two
issues regarding the Rate Agreement; (i) whether the Rate Agreement creates
private rights which would allow PSNH to seek damages under a contract theory if
PSNH receives less than the full amount it claims as strandable costs under the
Rate Agreement, and (ii) if yes, against whom and under what conditions such
rights be enforceable. The Supreme Court first must determine whether it will
accept the NHPUC's petition.
As part of the rehearing proceedings, PSNH proposed a new methodology to
quantify its stranded costs. Under this proposal, PSNH would divest its owned
generation and purchased power obligations via auction. To the extent that the
auction fails to produce sufficient revenues to cover the net book value of
owned generation and contractual payment obligations of purchased power, the
difference would be recovered from customers through a non-bypassable
distribution charge. The new proposal also relies upon securitization of
certain assets to further reduce rates.
On February 20, 1998, PSNH forwarded a settlement offer to representatives from
the state of New Hampshire that was consistent with PSNH's proposal in the
rehearing proceedings, including among other things, a 20 percent rate reduction
at the beginning of 1999, an auction of PSNH's non-nuclear generating units and
securitization of approximately $1.15 billion of PSNH's stranded costs.
See the "Notes to Financial Statements," Note 11A, for the potential accounting
impacts of restructuring.
RATE MATTERS
PSNH's Rate Agreement provided for seven base rate increases and a comprehensive
fuel and purchased power adjustment clause (FPPAC). In June 1996, the final
base rate increase of 5.5 percent went into effect. Although the FPPAC
continues for an additional four years beyond the end of the fixed rate period,
there is uncertainty regarding how it will continue to function. The costs
associated with purchases by PSNH from certain non-utility generators (NUGs) at
prices above the level assumed in rates are deferred and recovered through the
FPPAC. At December 31, 1997, NUG deferrals totaled approximately $173 million.
On May 2, 1997, PSNH made a rate filing with the NHPUC requesting base rates to
remain at their current level after May 31, 1997. By order dated November 6,
1997, the NHPUC ordered a temporary rate reduction for PSNH at a revenue level
6.87 percent lower than current rates. The NHPUC also set an interim return on
equity of 11 percent. The temporary rates became effective December 1, 1997. A
final decision, which will be reconciled to July 1, 1997, is not expected to be
issued until September, 1998. A portion of this reduction was offset by an
increase to rates through the FPPAC.
On February 10, 1998, the NHPUC ordered an FPPAC rate for the period December 1,
1997 through May 31, 1998, which increased customer bills by approximately 6
percent. Prior to this increase, the FPPAC rate had been a credit to reflect a
customer refund ordered by the NHPUC beginning in June 1996. This rate
continues to defer recovery of a substantial portion of costs for the future.
In addition, recovery of the Seabrook deferred return (approximately $127
million annually) is scheduled to begin in June 1998. On March 19, 1998, PSNH
filed a proposed change to its rates, effective June 1, 1998. Public hearings
are scheduled to take place in May 1998.
The NHPUC also confirmed in its February 10, 1998 decision that it would
disallow approximately $3 million in replacement power costs related to outages
at Connecticut Yankee, Maine Yankee and Vermont Yankee and require PSNH to set
aside $10 million as a reserve for potential overpayments due to the fact that
PSNH has not required small power producers to reduce deliveries during so-
called "light-loading" periods, pending the NHPUC's review of this matter. The
decision also alleges various breaches of the Rate Agreement and ordered PSNH to
meet with the State to discuss these matters. Finally, the decision indicated
that the NHPUC would open a proceeding to review whether the proceeds from the
sale of steam generators (approximately $20.9 million for NAEC's share) related
to the canceled Unit II at Seabrook station should flow through rates to reduce
customer bills.
See the "Notes to Financial Statements," Note 2K, for further information on the
FPPAC.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $44 million in 1997,
compared to 1996, primarily due to lower recoveries through the FPPAC as a
result of a customer refund ordered by the NHPUC and higher costs due to the
Seabrook outage that are not being recovered currently, partially offset by
higher working capital. Cash used for financing activities decreased
approximately $116 million in 1997, compared to 1996, due primarily to the
repayment of long-term debt in 1996, partially offset by the higher payment of
cash dividends on common stock and the repayment of preferred stock in 1997.
Cash used for investments decreased approximately $21 million in 1997, compared
to 1996, primarily due to a decrease in investments in the NU system Money Pool.
PSNH has a $125 million revolving credit agreement that will expire in April
1999. At December 31, 1997 there were no borrowings under the facility.
PSNH has a first mortgage bond maturity of $170 million, plus accrued interest,
on May 14, 1998. PSNH expects to meet that maturity with cash on hand and
borrowing under the revolving credit agreement.
Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has
any financing agreements containing cross defaults based on financial defaults
by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing
agreements containing cross defaults based on financial defaults by NU, CL&P or
WMECO. Nevertheless, it is possible that investors will take negative operating
results or regulatory developments at one company in the NU system into account
when evaluating other companies in the NU system. That could, as a practical
matter and despite the contractual and legal separations among the NU companies,
negatively affect each company's access to financial markets.
NUCLEAR PERFORMANCE
MILLSTONE 3
PSNH has a 2.85 percent joint ownership interest in Millstone 3. Millstone 3 has
been out of service since March 30, 1996.
Subsequent to its January 31, 1996, announcement that Millstone had been placed
on its watch list, the NRC has stated that the unit cannot return to service
until independent, third party verification teams have reviewed the actions
taken to improve the design, configuration and employee concerns issues that
prompted the NRC to place the unit on its watch list. The actual date of the
return to service for the unit is dependent upon the completion of independent
inspections, reviews by the NRC and a vote by the NRC commissioners.
In January 1998, NU declared Millstone 3 physically ready for restart, which
meant that almost all of the restart-required physical work had been completed
in the plant. The NRC currently is conducting a series of inspections to
determine, among other things, whether the plant has effective leadership and
corrective action and employee concerns programs. The Independent Corrective
Action Verification Program, an NRC-ordered independent review of the plant's
design and licensing bases, is expected to be completed in March 1998.
To date, PSNH's costs related to the Millstone 3 outage have not had a material
impact on the company's financial position or results of operations. Management
expects that, under its current planning assumptions, Millstone 3's outage-
related costs will continue to be immaterial to the company's results of
operations.
SEABROOK
PSNH is obligated to purchase North Atlantic Energy Corporation's (NAEC) 35.98-
percent share of the capacity and output generated by Seabrook 1(Seabrook) under
the Seabrook Power Contract for a period equal to the length of the NRC full-
power operating license for Seabrook (through 2026) whether or not Seabrook is
operating and without regard to the cost of alternative sources of power. North
Atlantic Energy Service Corporation is the managing agent and operates Seabrook.
Seabrook operated at a capacity factor of 78.3 percent through December 1997,
compared to 96.8 percent for the same period in 1996. The lower 1997 capacity
factor is due primarily to the 50-day scheduled refueling and maintenance outage
which began on May 10, 1997, and an unplanned outage that began on December 5,
1997. The unplanned outage occurred when the unit was shut down to repair leaks
in a three inch stainless steel pipe in the residual heat removal system. The
pipe was replaced, but problems were subsequently discovered in the control
building air conditioning system. Design changes were implemented and the plant
returned to service on January 16, 1998.
DECOMMISSIONING
CONNECTICUT YANKEE
PSNH has a 5 percent ownership interest in the Connecticut Yankee nuclear
generating facility (CY or the plant). On December 4, 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease
permanently the production of power at the plant. The decision to retire CY from
commercial operation was based on an economic analysis of the costs of operating
it compared to the costs of closing it and incurring replacement power costs
over the remaining period of the plant's operating license, which would have
expired in 2007. The economic analysis showed that closing the plant and
incurring replacement power costs produced substantial savings.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December 1996, CY filed an amendment to its power
contracts with the FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1997, PSNH's
share of these obligations was approximately $31 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that
PSNH will continue to be allowed to recover such FERC approved costs from their
customers. Accordingly, PSNH has recognized its share of the estimated costs as
a regulatory asset, with a corresponding obligation, on its balance sheets.
MAINE YANKEE
PSNH has a 5 percent ownership interest in the Maine Yankee (MY) nuclear
generating facility. On August 6, 1997, the Board of Directors of Maine Yankee
Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14,
1998, FERC released a draft order on the MYAPC application to amend its power
contracts with the owner/purchasers and revise its decommissioning and other
charges. FERC has accepted the proposed application for filing and made the
amendments and the proposed charges under the contracts effective on January
15, 1998, subject to refund after hearings. At December 31, 1997, PSNH's
share of the estimated remaining obligation, including decommissioning amounted
to approximately $43 million. Under the terms of the contracts with MYAPC, the
shareholders' sponsor companies, including PSNH, are responsible for their
proportionate share of the costs of the unit, including decommissioning.
Management expects that PSNH will be allowed to recover these costs from its
customers. Accordingly, PSNH has recognized these costs as a regulatory asset,
with a corresponding obligation on its balance sheet.
MILLSTONE AND SEABROOK
PSNH's estimated cost to decommission its 2.85 percent share of Millstone 3 and
NAEC's 35.98 share of Seabrook is approximately $16 million and $170 million,
respectively, in year end 1997 dollars. These costs are being recognized over
the lives of the respective units with a portion currently being recovered
through rates. Under the terms of the Rate Agreement, the company is obligated
to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is
shut down prior to the expiration of its operating license. As of December 31,
1997, the market value of the contributions already made to the Millstone 3 and
Seabrook decommissioning trusts, including their investment returns, was
approximately $4 million and $26 million, respectively.
See the "Notes to Financial Statements," Note 5, for further information on
nuclear decommissioning, including PSNH's share of costs to decommission the
other regional nuclear generating units.
ENVIRONMENTAL MATTERS
PSNH is potentially liable for environmental cleanup costs at a number of sites
inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of PSNH. At December 31, 1997, PSNH had recorded
an environmental reserve of approximately $5.6 million. See the "Notes to
Financial Statements" Note 11C, for further information on environmental
matters.
YEAR 2000 ISSUE
The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU systems to process critical financial and operational
information incorrectly. The company has assessed and continues to assess the
impact of the Year 2000 issue on its operating and reporting systems. The
assessment of the nuclear operating systems is continuing and is expected to be
completed in the summer of 1998.
The NU system will utilize both internal and external resources to reprogram or
replace, and test the software for Year 2000 modifications. The total estimated
remaining cost of the Year 2000 project is $37 million and is being funded
through operating cash flows. This estimate does not include any costs for the
replacement or repair of equipment or devices that may be identified during the
assessment process. The majority of these costs will be expensed as incurred
over the next two years. To date, the NU system has incurred and expensed
approximately $4 million related to the assessment of, and preliminary efforts
in connection with, its Year 2000 project.
The costs of the project and the date on which the company plans to complete the
Year 2000 modifications are based on management's best estimates, which were
derived utilizing numerous assumptions of future events including the continued
availability of certain resources, third party modification plans and other
factors. However, there can be no guarantee that these estimates will be
achieved, and actual results could differ materially from those plans. If the
NU system's remediation plan is not successful, there could be a significant
disruption of the NU system's operations.
RESULTS OF OPERATIONS
Income Statement Variances
Increase/(Decrease)
Millions of Dollars
1997 over/(under) 1996 1996 over/(under) 1995
Amount Percent Amount Percent
Operating revenues $(2) - % $130 13%
Fuel, purchased and net
interchange power (30) (8) 100 39
Other operation 42 13 13 4
Maintenance (7) (16) 3 8
Other, net (7) (92) 5 (a)
Interest on long-term debt (6) (11) (19) (25)
Other interest expense (3) (91) 3 (a)
Net income (5) (5) 14 17
(a) Percent greater than 100
OPERATING REVENUES
Total operating revenues decreased in 1997 primarily due to lower fuel
recoveries, partially offset by higher retail revenues. Fuel recoveries
decreased approximately $12 million, primarily due to the customer refund
ordered by the NHPUC. Retail revenues increased approximately $9 million,
primarily due to the June 1996 rate increase, partially offset by the December
1997 rate decrease and higher price discounts to retain customers. Retail sales
were essentially unchanged.
Total operating revenues increased in 1996, primarily due to higher fuel
recoveries, regulatory decisions, and other retail revenues. Fuel recoveries
increased $112 million, primarily due to revenues resulting from the
intercompany allocation of energy costs to NU affiliated companies ($125
million) and higher base fuel revenues primarily as a result of the June 1996
and 1995 retail-rate increases, partially offset by lower FPPAC revenues as a
result of a customer refund ordered by the NHPUC. Revenues related to regulatory
decisions increased $8 million, primarily due to the retail-rate increases.
Other retail revenues increased $10 million primarily due to sales growth and
other revenue sources. Retail sales increased 0.4 percent ($2 million),
primarily due to economic growth in 1996, partially offset by milder weather in
1996.
FUEL EXPENSE
Fuel, purchased and net interchange power expense decreased in 1997, primarily
due to the timing in the recognition of fuel expenses under the FPPAC, partially
offset by higher purchased power costs.
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to higher purchased power costs and the timing in the recognition of fuel
expenses under the FPPAC.
OTHER OPERATION AND MAINTENANCE EXPENSE
Other operation and maintenance expense increased in 1997 primarily due to
higher capacity charges under the Seabrook Power Contract as a result of the
scheduled May 1997 refueling and maintenance outage and the unplanned December
1997 outage ($23 million), higher capacity purchases from NHEC ($11 million),
higher capacity charges from MY ($4 million) and higher costs for PSNH's share
of Millstone 3 ($3 million), partially offset by lower fossil costs ($4 million)
and lower administration and sales costs ($3 million).
Other operation and maintenance expenses increased in 1996, primarily due to
higher storm costs, higher employee benefit costs, higher capacity charges under
the Seabrook Power Contracts and higher marketing costs.
OTHER, NET
Other, net decreased in 1997 and increased in 1996, primarily due to the
deferral in 1996 of interest expense ($5 million) associated with the FPPAC
refund.
INTEREST ON LONG-TERM DEBT
Interest on long-term debt decreased in 1997 and 1996, primarily due to the
repayment of the $172.5 million Series A first-mortgage bond in May 1996.
OTHER INTEREST EXPENSE
Other interest expense decreased in 1997 and increased in 1996, primarily due to
1996 interest expense ($5 million) associated with the FPPAC refund.
SELECTED FINANCIAL DATA (a)
For the Years Ended Dec.31, 1997 Dec. 31, 1996 Dec. 31, 1995
(Restated) (Restated)
(Thousands of Dollars)
Operating Revenues... $1,108,459 $1,110,169 $ 979,971
Operating Income..... 144,024 155,758 155,628
Net Income .......... 92,172 97,465 83,255
Cash Dividends on
Common Stock....... 85,000 52,000 52,000
At Dec.31, 1997 Dec. 31, 1996 Dec. 31, 1995
Total Assets......... $2,837,159 $2,851,212 $2,920,487
Long-Term Debt (b)... 686,485 686,485 858,985
Preferred Stock
Subject to Mandatory
Redemption(b)...... 100,000 125,000 125,000
Obligations Under
Seabrook Power
Contracts and Other
Capital Leases(b).. 921,813 914,617 915,288
(a) Reclassifications of prior data have been made to conform with
the current presentation.
(b) Includes portions due within one year.
Dec. 31, 1994 Dec. 31, 1993
(Thousands of Dollars)
$922,039 $864,415
152,086 124,710
77,444 52,237
- -
Dec. 31,1994 Dec. 31, 1993
$2,845,967 $2,774,511
999,985 1,093,895
125,000 125,000
887,967 856,559
STATISTICS
Average
Gross Electric Annual
Utility Plant Use Per
December 31, kWh Residential Electric
(Thousands of Sales Customer Customers Employees
Dollars)(a) (Millions) (kWh) (Average) (December 31)
1997 $2,312,628 13,340 6,528 407,642 1,254
1996 2,382,009 13,601 6,567 407,082 1,279
1995 2,469,474 11,001 6,524(b) 406,077 1,325
1994 2,521,960 11,008 6,768 400,775 1,374
1993 2,590,644 11,146 6,817 397,277 1,426
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated)
Quarter Ended (c)
1997 March 31 June 30 Sept.30 Dec. 31
Operating Revenues... $278,321 $257,098 $285,390 $287,650
Operating Income..... $ 44,776 $ 34,190 $ 32,166 $ 32,892
Net Income........... $ 32,295 $ 21,289 $ 18,900 $ 19,688
1996 March 31 June 30 Sept.30 Dec. 31
Operating Revenues... $269,540 $261,897 $296,719 $282,013
Operating Income..... $ 44,865 $ 42,220 $ 46,864 $ 21,809
Net Income........... $ 28,742 $ 24,050 $ 30,576 $ 14,097
(a) Includes reclassification of the unamortized acquisition costs to gross
utility plant.
(b) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.
(c) Reclassifications of prior data have been made to conform with
the current presentation.
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