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
- -----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
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
============= =============
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
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
============= =============
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
- -----------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
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
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
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
========== ========== ==========
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
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings(a) Total
Stock Paid In (Note 1)
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
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
========= ========= ========== ===========
(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.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13.3
<SEQUENCE>4
<DESCRIPTION>ANNUAL REPORT OF WMECO
<TEXT>
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
- ----------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
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
============= ============
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------
At December 31, 1997 1996
(Restated) (Restated)
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
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
============= ============
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
- ---------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996
(Restated) (Restated) 1995
- ---------------------------------------------------------------------------------
(Thousands of Dollars)
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
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1997 1996 1995
(Restated) (Restated)
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
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
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings(a)
Stock Paid In (Note 1) Total
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
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
======== ========= ========= =========
(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.