1997 Annual Report
The Connecticut Light and Power Company and Subsidiaries
Index
Contents Page
Consolidated Balance Sheets....................................... 2-3
Consolidated Statements of Income................................. 4
Consolidated Statements of Cash Flows............................. 5
Consolidated Statements of Common Stockholder's Equity............ 6
Notes to Consolidated Financial Statements........................ 7
Report of Independent Public Accountants.......................... 41
Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 42
Selected Financial Data........................................... 54
Statements of Quarterly Financial Data............................ 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
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Utility Plant, at original cost:
Electric (Note 1H)....................................... $ 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 (Note 10)............ 205,625 -
Receivables, less accumulated provision for
uncollectible accounts of $300,000 in 1997
and of $13,240,000 in 1996 (Note 10)................... 50,671 226,112
Accounts receivable from affiliated companies............ 3,150 3,481
Taxes receivable......................................... 70,311 40,134
Accrued utility revenues (Note 10)....................... - 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 (Note 1H).............................. 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
- ----------------------------------------------------------------------------------------
(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....................................... 385,823 551,410
------------- -------------
Total common stockholder's equity.............. 1,149,385 1,313,296
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........................... 3,440,151 3,418,901
------------- -------------
Minority Interest in Consolidated Subsidiary (Note 13).... 100,000 100,000
------------- -------------
Obligations Under Capital Leases (Note 2)................. 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
Nuclear compliance (Note 11B)........................... 58,700 50,500
Other................................................... 23,495 34,433
------------- -------------
607,389 601,056
------------- -------------
Deferred Credits:
Accumulated deferred income taxes....................... 1,324,066 1,365,641
Accumulated deferred investment tax credits............. 127,713 135,080
Deferred contractual obligations (Note 3)............... 348,406 305,627
Other................................................... 115,456 174,384
------------- -------------
1,915,641 1,980,732
------------- -------------
Commitments and Contingencies (Note 11)
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
- -----------------------------------------------------------------------------------------
(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........................................... 734,620 778,174 614,382
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 (Note 8)............ (62,856) (20,174) 178,346
Taxes other than income taxes...................... 172,592 174,062 172,395
----------- ----------- -----------
Total operating expenses..................... 2,477,986 2,367,687 2,063,043
----------- ----------- -----------
Operating (Loss)/Income.............................. (12,399) 29,773 324,026
----------- ----------- -----------
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 (Note 13) (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........ (10,310) 47,962 333,446
----------- ----------- -----------
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.................................... $ (144,377) $ (80,237) $ 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
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net(Loss)/Income............................................ $(144,377) $ (80,237) $ 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..... (13,821) (60,773) 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........................................ (50,136) (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 (Note 10) 70,000 - -
Investment in securitizable assets (Note 10)............. (205,625) - -
Nuclear compliance, net (Note 11B)........................ 8,200 50,500 -
Other working capital (excludes cash)..................... (74,266) (5,385) (1,869)
---------- ---------- ----------
Net cash flows from operating activities...................... 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
Stock Paid In (a) Total
- ------------------------------------------------------------------------------------
(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............... (80,237) (80,237)
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........ 122,229 639,657 551,410 1,313,296
Net loss for 1997............... (144,377) (144,377)
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........ $122,229 $641,333 $ 385,823 $1,149,385
========= ========= ========== ===========
(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 STAATEMENTS
1. 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), Western Massachusetts Electric Company (WMECO), Holyoke Water
Power Company (HWP), Public Service Company of New Hampshire (PSNH) and
North Atlantic Energy Corporation (NAEC) are the operating subsidiaries
comprising the Northeast Utilities system (the NU system) and are
wholly owned by Northeast Utilities (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 10,
"Sale of Customer Receivables and Accrued Utility Revenues," and Note
13, "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 1H, "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 10, "Sale of Customer Receivables and Accrued Utility
Revenues," and Note 11C, "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 3,
"Nuclear Decommissioning," and Note 11F, "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 3, "Nuclear
Decommissioning," and Note 11B, "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 3, "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 11A, "Commitments and
Contingencies - Restructuring and Rate Matters" and the MD&A.
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," requires the evaluation of long-
lived assets, including regulatory assets, for impairment when certain
events occur or when conditions exist that indicate the carrying
amounts of assets may not be recoverable. SFAS 121 requires that any
long-lived assets which are no longer probable of recovery through
future revenues be revalued based on estimated future cash flows.
If this revaluation is less than the book value of the asset, an
impairment loss would be charged to earnings.
Management continues to believe that it is probable that 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 1I) ................ $709,896 $ 753,390
Recoverable energy costs,
net (Note 1J) ............................ 104,796 97,900
Deferred demand-side management
costs (Note 1K) .......................... 52,100 90,129
Cogeneration costs (Note 1L) ............... 33,505 66,205
Unrecovered contractual
obligations (Note 3) ..................... 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 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
(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 ...................................... (29,230) 19,364
$1,324,066 $1,365,641
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
with the renegotiation of a certain contract with a cogeneration
facility to the deferred balance. Under current expectations, CL&P
expects complete amortization of the deferred balance by December 31,
1998. At December 31, 1997, CL&P's deferred cogeneration costs balance
was approximately $33.5 million.
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 12, "Market Risk Management."
2. 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 Reality 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.
3. 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.
4. 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.
5. 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 996 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.
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)
7.23% 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.
7. 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 1M)......... 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.
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
(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............................... 5,862 (38,680) 52,075
State................................. (12,316) (14,726) 5,085
Total deferred...................... (6,454) (53,406) 57,160
Investment tax credits, net............. (7,366) (7,367) (7,640)
Total income tax
(credit)/expense.................... $(70,429) $(20,334) $181,324
The components of total income tax expense are classified as
follows:
Income taxes charged to
operating expenses.................... $(62,856) $(20,174) $178,346
Other income taxes...................... (7,573) (160) 2,978
Total income tax
(credit)/expense........................ $(70,429) $(20,334) $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
(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)
Nuclear compliance reserves............. (4,759) (21,131) -
Pension accruals........................ 6,524 2,944 5,382
State net operating loss
carryforwards......................... (7,670) - -
Other................................... (515) (2,310) 2,694
Deferred income taxes, net.............. $ (6,454) $(53,406) $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
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income........... $(75,182) $(35,931) $135,289
Tax effect of differences:
State income taxes, net of
federal benefit..................... (9,516) (3,209) 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..................... $(70,429) $(20,334) $181,324
9. 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.
10. 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.
11. 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 1H, "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 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.
In 1997, CL&P's share of nonfuel O&M costs expensed for Millstone
totaled $455 million, including $59 million reserved for future restart
costs.
Budgeted nuclear spending levels at Millstone for 1998 will be reduced
from 1997 levels, although they will be considerably higher than before
the station was placed on the NRC's watch list. The actual level of
1998 spending will depend on when the units return to operation and the
cost of restoring them to service. The total cost to restart the units
cannot be precisely estimated at this time. Management will continue
to evaluate the costs to be incurred in 1998 to determine whether
adjustments to the existing reserves are required.
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 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 2, "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 1E, "Summary of Significant
Accounting Policies - Investments and Jointly Owned Electric Utility
Plant," for further information on the Yankee companies, and Note 3,
"Nuclear Decommissioning," regarding the related decommissioning
obligations.
Nonutility Generators: CL&P 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 1J, "Summary of Significant Accounting Policies - Recoverable
Energy Costs."
12. 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.
13. 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.
14. 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.
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets 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 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.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 20, 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 $144 million in 1997, compared to a net
loss of approximately $80 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 $133 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. Tight cost controls will continue to be
essential in 1998 to CL&P's efforts to meet the financial covenants contained in
the $313.75 million revolving credit arrangement available to CL&P and Western
Massachusetts Electric Company (WMECO).
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 totaled
approximately $455 million, including $59 million reserved for future restart
costs. The 1997 costs are net of $50 million of costs which were reserved in
1996. In 1996, the CL&P's share of nonfuel O&M costs expensed for Millstone
totaled approximately $322 million, including $50 million reserved for future
restart costs. Management will continue to evaluate the costs to be incurred in
1998 to determine whether adjustments to the existing reserves are required.
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 11B, 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 of adequate generating capacity in Connecticut, of
which $35 million was expensed. 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
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
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 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 costs 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 had exposure to strandable costs for its 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 its strandable costs. The company's strategy to recover strandable costs
includes efforts to promote state legislation that will authorize the issuance
of rate reduction bonds that would refinance these investments and which would
be repaid through non-bypassable charges to customers. Management is unable
to predict the ultimate outcome of these initiatives which will be subject to
regulatory and legislative approvals. Management believes it is entitled to
full recovery of its prudently incurred costs, including regulatory assets and
other strandable costs. See the "Notes to Consolidated Financial Statements,"
Note 1H, 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 includes the $44 million from the 1996 Settlement.
The interim rate reduction became effective on March 1, 1998.
CL&P also was directed to file a full rate case on June 1, 1998, to address
potential overearnings amounting to an additional $150 million in 1998. The
effective date of any rate order will be September 28, 1998. In addition, the
DPUC has scheduled 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 3, 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 11C, for further information on
environmental matters.
YEAR 2000 ISSUE
The Year 2000 issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the change of the
century occurs, date-sensitive systems may recognize the year 2000 as 1900, or
not recognize it at all. This inability to recognize or properly treat the year
2000 may cause NU'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," Notes 12.
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 on the spot market. This
assumption is subject to change as the uncovered volume of fuel likely will
change during the next year. Other assumptions used in this analysis,
projections of the fuel mix, the amount of long-term sales contracts or
the projected Millstone restart dates, also are subject to change.
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 (44) (6) 164 27
Maintenance 56 19 107 56
Amortization of regulatory
assets, net 4 7 3 6
Federal and state income
taxes (50) (a) (202) (a)
Other income, net (23) (a) 6 42
Net income (64) (80) (285) (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 ($133 million,
including a net increase of $9 million in reserves for future costs) and 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 ($143 million,
including $50 million of reserves for future costs) and 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 costs associated with the
accounts receivable facility, nonutility marketing and advertising costs and
lower miscellaneous income.
Other income, net increased in 1996, primarily due to higher income on temporary
cash investments in 1996.
SELECTED FINANCIAL DATA(a)
1997 1996 1995 1994 1993
(Thousands of Dollars)
Operating Revenues.$2,465,587 $2,397,460 $2,387,069 $2,328,052 $2,366,050
Operating (Loss)
/Income.......... (12,399) 29,773 324,026 286,948 241,655
Net(Loss)/Income... (144,377) (80,237) 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
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
Quarter Ended(a)
1997 March 31 June 30 September 30 December 31
(Thousands of Dollars)
Operating Revenues $624,908 $ 574,841 $ 627,712 $ 638,126
Operating Income/
(Loss) $ 23,148 $ (33,587) $ (15,552) $ 13,592
Net Loss $ (6,431) $ (64,089) $ (50,077) $ (23,780)
1996
Operating Revenues $659,355 $ 542,999 $ 599,505 $ 595,601
Operating Income/
(Loss) $ 59,977 $ 15,197 $ 593 $ (45,994)
Net Income/(Loss) $ 32,851 $(10,700) $ (26,938) $ (75,450)
(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.
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.