EXHIBIT 13.2
1995 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.................... 28
Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 29
Selected Financial Data..................................... 35
Statements of Quarterly Financial Data...................... 35
Statistics.................................................. 36
Preferred Stockholder and Bondholder Information............ Back Cover
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------
At December 31, 1995 1994
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................ $6,147,961 $6,063,179
Less: Accumulated provision for depreciation......... 2,418,557 2,194,314
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3,729,404 3,868,865
Construction work in progress........................... 103,026 99,993
Nuclear fuel, net....................................... 138,203 164,795
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Total net utility plant............................. 3,970,633 4,133,653
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Other Property and Investments:
Nuclear decommissioning trusts, at market............... 238,023 171,950
Investments in regional nuclear generating
companies, at equity................................... 54,624 54,952
Other, at cost.......................................... 14,821 14,742
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307,468 241,644
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Current Assets:
Cash and special deposits (Note 1N)<F1N>................ 1,757 2,017
Receivables, less accumulated provision for
uncollectible accounts of $10,567,000 in 1995
and $12,778,000 in 1994................................ 231,574 192,926
Accounts receivable from affiliated companies........... 3,069 9,367
Accrued utility revenues................................ 91,157 90,475
Fuel, materials, and supplies, at average cost.......... 68,482 64,003
Recoverable energy costs, net--current portion.......... 78,108 10,561
Prepayments and other................................... 42,894 43,654
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517,041 413,003
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Deferred Charges:
Regulatory assets (Note 1G)<F1G>........................ 1,210,384 1,410,334
Unamortized debt expense................................ 14,977 8,396
Other................................................... 10,232 10,427
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1,235,593 1,429,157
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Total Assets........................................ $6,030,735 $6,217,457
=========== ===========
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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At December 31, 1995 1994
- ----------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$10 par value--authorized
24,500,000 shares; outstanding 12,222,930
shares in 1995 and 1994.............................. $ 122,229 $ 122,229
Capital surplus, paid in.............................. 637,981 632,117
Retained earnings..................................... 785,476 765,724
----------- -----------
Total common stockholder's equity............ 1,545,686 1,520,070
Cumulative preferred stock--
$50 par value - authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1995 and 1994
$25 par value - authorized 8,000,000 shares;
outstanding no shares in 1995 and
5,000,000 shares in 1994
Not subject to mandatory redemption................. 116,200 166,200
Subject to mandatory redemption..................... 155,000 226,250
Long-term debt........................................ 1,812,646 1,815,579
----------- -----------
Total capitalization......................... 3,629,532 3,728,099
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Minority Interest in Consolidated
Subsidiary (Note 13)<F13>............................. 100,000 -
----------- -----------
Obligations Under Capital Leases........................ 108,408 120,268
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Current Liabilities:
Notes payable to banks................................ 41,500 76,000
Notes payable to affiliated company................... 10,250 92,750
Commercial paper...................................... - 10,000
Long-term debt and preferred stock--current
portion.............................................. 9,372 11,861
Obligations under capital leases--current
portion.............................................. 63,856 55,701
Accounts payable...................................... 110,798 102,837
Accounts payable to affiliated companies.............. 44,677 43,033
Accrued taxes......................................... 52,268 26,413
Accrued interest...................................... 30,854 30,682
Other................................................. 20,027 22,828
----------- -----------
383,602 472,105
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Deferred Credits:
Accumulated deferred income taxes (Note 1H)<F1H>...... 1,486,873 1,544,021
Accumulated deferred investment tax credits........... 142,447 150,087
Deferred contractual obligation....................... 65,847 100,003
Other................................................. 114,026 102,874
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1,809,193 1,896,985
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Commitments and Contingencies (Note 10)<F10>
Total Capitalization and Liabilities......... $6,030,735 $6,217,457
=========== ===========
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
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For the Years Ended December 31, 1995 1994 1993
- -------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues................................ $2,386,107 $2,328,052 $2,366,050
----------- ----------- ----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power.... 608,600 568,394 657,121
Other........................................ 613,420 593,851 641,402
Maintenance..................................... 192,607 207,003 180,403
Depreciation.................................... 242,496 231,155 219,776
Amortization of regulatory assets, net.......... 54,217 77,384 112,353
Federal and state income taxes (Note 8)<F8>..... 178,346 190,249 142,987
Taxes other than income taxes................... 172,395 173,068 170,353
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Total operating expenses.................. 2,062,081 2,041,104 2,124,395
----------- ----------- ----------
Operating Income.................................. 324,026 286,948 241,655
----------- ----------- ----------
Other Income:
Deferred nuclear plants return--other funds..... 4,683 13,373 23,537
Equity in earnings of regional nuclear
generating companies.......................... 6,545 7,453 6,193
Other, net...................................... 1,170 5,136 (1,044)
Income taxes.................................... (2,978) 4,248 3,299
----------- ----------- ----------
Other income, net......................... 9,420 30,210 31,985
----------- ----------- ----------
Income before interest charges............ 333,446 317,158 273,640
----------- ----------- ----------
Interest Charges:
Interest on long-term debt...................... 124,350 119,927 134,263
Other interest.................................. 5,596 6,378 9,654
Deferred nuclear plants return--borrowed funds.. (1,716) (7,435) (13,979)
----------- ----------- ----------
Interest charges, net..................... 128,230 118,870 129,938
----------- ----------- ----------
Income before cumulative effect of
accounting change............................... 205,216 198,288 143,702
Cumulative effect of accounting change
(Note 1A)<F1A>.................................. - - 47,747
----------- ----------- ----------
Net Income........................................ $ 205,216 $ 198,288 $ 191,449
=========== =========== ==========
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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For the Years Ended December 31, 1995 1994 1993
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net Income.................................................. $ 205,216 $ 198,288 $ 191,449
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 242,496 231,155 219,776
Deferred income taxes and investment tax credits, net..... 49,520 37,664 (20,188)
Deferred nuclear plants return............................ (6,399) (20,808) (37,516)
Amortization of deferred nuclear plants return............ 101,958 103,459 96,256
Recoverable energy costs, net of amortization............. (33,769) 3,975 125,579
Deferred cogeneration costs............................... (55,341) (36,821) -
Other sources of cash..................................... 65,597 43,138 80,831
Other uses of cash........................................ (36,435) (9,388) (47,499)
Changes in working capital:
Receivables and accrued utility revenues.................. (33,032) 45,386 (9,370)
Fuel, materials, and supplies............................. (4,479) (3,756) 11,951
Accounts payable.......................................... 9,605 (24,167) 5,433
Accrued taxes............................................. 25,855 (9,726) (82,018)
Other working capital (excludes cash)..................... (1,869) (18,403) 9,754
----------- ----------- -----------
Net cash flows from operating activities...................... 528,923 539,996 544,438
----------- ----------- -----------
Financing Activities:
Issuance of long-term debt.................................. - 535,000 740,500
Issuance of preferred stock................................. - - 80,000
Issuance of Monthly Income
Preferred Securities (Note 13)<F13>........................ 100,000 - -
Net (decrease) increase in short-term debt.................. (127,000) 82,500 (109,490)
Reacquisitions and retirements of long-term debt............ (10,866) (774,020) (771,973)
Reacquisitions and retirements of preferred stock........... (125,000) - (114,996)
Cash dividends on preferred stock........................... (21,185) (23,895) (29,182)
Cash dividends on common stock.............................. (164,154) (159,388) (160,365)
----------- ----------- -----------
Net cash flows used for financing activities.................. (348,205) (339,803) (365,506)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (131,858) (149,889) (149,308)
Nuclear fuel.............................................. (1,543) (20,905) (13,658)
----------- ----------- -----------
Net cash flows used for investments in plant................ (133,401) (170,794) (162,966)
Other investment activities, net............................ (47,577) (29,722) (25,787)
----------- ----------- -----------
Net cash flows used for investments........................... (180,978) (200,516) (188,753)
----------- ----------- -----------
Net Decrease In Cash For The Period........................... (260) (323) (9,821)
Cash and special deposits - beginning of period............... 2,017 2,340 12,161
----------- ----------- -----------
Cash and special deposits - end of period..................... $ 1,757 $ 2,017 $ 2,340
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized........................ $ 117,074 $ 115,120 $ 130,592
=========== =========== ===========
Income taxes................................................ $ 137,706 $ 161,513 $ 149,056
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust...................................... $ 33,537 $ 52,353 $ 40,140
=========== =========== ===========
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
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Capital Retained
Common Surplus, Earnings
Stock Paid In (a) Total
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 1993.......... $122,229 $634,851 $ 748,817 $1,505,897
Net income for 1993............. 191,449 191,449
Cash dividends on preferred
stock......................... (29,182) (29,182)
Cash dividends on common stock.. (160,365) (160,365)
Capital stock expenses, net..... (4,580) (4,580)
--------- --------- ---------- -----------
Balance at December 31, 1993........ 122,229 630,271 750,719 1,503,219
Net income for 1994............. 198,288 198,288
Cash dividends on preferred
stock......................... (23,895) (23,895)
Cash dividends on common stock.. (159,388) (159,388)
Capital stock expenses, net..... 1,846 1,846
--------- --------- ---------- -----------
Balance at December 31, 1994........ 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
========= ========= ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt
agreements.
At December 31, 1995, these restrictions totaled approximately $540 million.
The accompanying notes are an integral part of these financial statements.
The Connecticut Light and Power Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRESENTATION
The consolidated financial statements of The Connecticut Light and Power
Company and Subsidiaries (the company or CL&P) include the accounts of
all wholly owned subsidiaries. Significant intercompany transactions
have been eliminated in consolidation.
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 system) and are wholly
owned by Northeast Utilities (NU).
The system furnishes retail electric service in Connecticut, New
Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP.
A fifth subsidiary, NAEC, sells all of its capacity to PSNH. In
addition to its retail service, the system furnishes firm and other
wholesale electric services to various municipalities and other
utilities. The system serves about 30 percent of New England's electric
needs and is one of the 20 largest electric utility systems in the
country as measured by revenues.
Other wholly owned subsidiaries of NU provide substantial support
services to the system. Northeast Utilities Service Company (NUSCO)
supplies centralized accounting, administrative, data processing,
engineering, financial, legal, operational, planning, purchasing, and
other services to the system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for system companies in operating the
Millstone nuclear generating facilities. North Atlantic Energy Service
Corporation (NAESCO) acts as agent for CL&P and NAEC in operating the
Seabrook 1 nuclear facility.
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.
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.
Property Taxes: CL&P changed its method of accounting for municipal
property tax expense for its respective Connecticut properties during
1993. This one-time change increased 1993 net income by approximately
$47.7 million.
B. FUTURE ACCOUNTING STANDARD
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) 121, Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, in
March 1995. SFAS 121 became effective January 1, 1996, and establishes
accounting standards for evaluating and recording asset impairment.
SFAS 121 requires the evaluation of long-lived assets for impairment
when certain events occur or conditions exist that indicate the carrying
amounts of assets may not be recoverable. Refer to Note 1G,
"Regulatory Accounting," for further information on the regulatory
impacts of the company's adoption of SFAS 121.
C. 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 the company's ownership interests, are:
Connecticut Yankee Atomic Power Company (CY) ...... 34.5%
Yankee Atomic Electric Company (YAEC) ............. 24.5
Maine Yankee Atomic Power Company (MY) ............ 12.0
Vermont Yankee Nuclear Power Corporation (VY) ..... 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. The electricity
produced by the facilities that are operating is committed substantially
on the basis of ownership interests and is billed pursuant to
contractual agreements. 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 these
agreements, see Note 10E, "Commitments and Contingencies - Long-Term
Contractual Arrangements."
YAEC's nuclear power plant was shut down permanently on February 26,
1992. For more information on the Yankee companies, see Note 3,
``Nuclear Decommissioning.''
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, 1995 and 1994, plant-in-service included approximately
$372.6 million and $370.9 million, respectively, and the accumulated
provision for depreciation included approximately $148.4 million and
$135.0 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, 1995
and 1994, plant-in-service included approximately $684.5 million and
$680.5 million, respectively, and the accumulated provision for
depreciation included approximately $198.5 million and $175.2 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,
1995 and 1994, plant-in-service included approximately $1.9 billion, and
the accumulated provision for depreciation included approximately $455.1
million and $418.5 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.
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, 1995
and 1994, plant-in-service included approximately $173.3 million and
$173.2 million, respectively, and the accumulated provision for
depreciation included approximately $24.8 million and $20.1 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.
D. 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 factors 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 4.0 percent in 1995, 3.9 percent in 1994, and 3.8
percent in 1993. See Note 3, ``Nuclear Decommissioning,'' for
information on nuclear plant decommissioning.
E. 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), and it and its subsidiaries, including the company, are
subject to the provisions of the 1935 Act. Arrangements among the
system companies, outside agencies, and other utilities covering
interconnections, interchange of electric power, and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The company is subject to further
regulation for rates, accounting, and other matters by the FERC and/or
the Connecticut Department of Public Utility Control (DPUC).
F. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, industrial, and commercial customers, utility revenues are
based on authorized rates applied to each customer's use of electricity.
In general, rates can be changed only through a formal proceeding
before the appropriate regulatory commission. At the end of each
accounting period, CL&P accrues an estimate for the amount of energy
delivered but unbilled.
G. REGULATORY ACCOUNTING
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 in future
revenues. Through their actions, regulators may also reduce or
eliminate the value of an asset, or create a liability. If any portion
of the company'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, the company would be required
to write off related regulatory assets and liabilities. The company
would also be required to determine any impairment to other assets, and
write down these assets to fair value. Based on current regulation and
recent regulatory decisions, and initiatives relating to competition in
the system's markets, the company believes that its use of regulatory
accounting remains appropriate.
SFAS 121 requires that any assets, including regulatory assets, which
are no longer probable of recovery through future revenues, be revalued
based on estimated future cash flows. If the revaluation is less than
the book value of the asset, an impairment loss would be charged to
earnings. As noted above, based on the current regulatory environment
in the company's service area, it is not expected that SFAS 121 will
have a material impact on the company's financial position or results of
operations upon adoption. This conclusion may change in the future as
competitive factors influence wholesale and retail pricing in the
electric utility industry or if the cost-of-service based regulatory
structure were to change. For further information on the company's
regulatory environment, refer to Management's Discussion and Analysis of
Financial Condition and Results of Operations (MD&A).
The components of regulatory assets are as follows:
At December 31, 1995 1994
----------------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1H) ........... $ 863,521 $ 949,134
Deferred demand-side management costs (Note 1I) 117,070 116,133
Cogeneration costs (Note 1J) .......... 92,162 36,821
Unrecovered contractual obligation (Note 3) 65,847 100,003
Recoverable energy costs, net (Note 1K) 27,262 61,040
Deferred costs-nuclear plants ........ 6,170 101,632
Other ................................. 38,352 45,571
-----------------------
$1,210,384 $1,410,334
=======================
H. 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 income subject to tax)
is accounted for in accordance with the ratemaking treatment of the
applicable regulatory commissions. The adoption of SFAS 109, Accounting
for Income Taxes, in 1993 increased the company's net deferred tax
obligation. As it is probable that the increase in deferred tax
liabilities will be recovered from customers through rates, CL&P
established a regulatory asset. 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, 1995 1994
--------------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ............ $1,074,242 $1,063,823
Regulatory assets - income tax gross up 347,673 402,685
Other .................................. 64,958 77,513
------------- -----------
$1,486,873 $1,544,021
========== ==========
I. DEMAND-SIDE MANAGEMENT (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). As of December 31, 1995, these costs will
be recovered by 2000. During October 1995, CL&P filed its 1996 DSM
program and forecasted CAM for 1996 with the DPUC. The filing proposes
expenditures of $37.1 million in 1996, with recovery over 2.4 years and
a zero CAM rate.
J. COGENERATION COSTS
In accordance with its three-year rate plan that began in July 1993,
CL&P was required to defer approximately $72 million and $36 million of
cogeneration expense in years two and three, respectively, of the rate
plan. CL&P is allowed to defer these costs with carrying charges, and
will begin amortization of these costs over a five-year period beginning
July 1, 1996.
On June 30, 1995, CL&P terminated its existing agreement to purchase
power from the O'Brien EPA cogeneration facility and entered into an
agreement to purchase an equivalent amount of power from Citizens Lehman
Power LP, at a cost below the O'Brien EPA rates. CL&P has applied the
resulting savings to the amortization of the cogeneration deferral.
K. 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, 1995, the company's total D&D deferrals were approximately $48.8
million.
Retail electric rates include a fuel adjustment clause (FAC) under which
fossil-fuel prices above or below base-rate levels are charged or
credited to customers. Monthly FAC rates are also subject to quarterly
retroactive regulatory review and appropriate adjustments. CL&P also
utilizes a generation utilization adjustment clause (GUAC), which defers
the effect on fuel costs caused by variations from a specified composite
nuclear generation capacity factor embedded in base rates.
The company is currently recovering $80 million of its GUAC balance over
18 months. The company set aside $19 million of its 1994-1995 GUAC year
request pending the resolution of the company's appeals associated with
the two prior GUAC periods.
At December 31, 1995, CL&P's net recoverable energy costs, excluding
current recoverable energy costs, were approximately $27.3 million.
For additional information, see Note 10B, "Commitments and Contingencies
- Nuclear Performance."
L. 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. 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 may be made anytime
prior to the first delivery of spent fuel to the DOE, which may be as
early as 1998. Until such payment is made, the outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield Rate.
At December 31, 1995, fees due to the DOE for the disposal of prior-
period fuel were approximately $150.0 million, including interest costs
of $83.5 million. As of December 31, 1995, all fees have been collected
through rates.
M. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes interest-rate caps and fuel swaps to manage well-
defined interest-rate and fuel-price risks. Premiums paid for purchased
interest-rate cap agreements are amortized to interest expense over the
terms of the caps. Unamortized premiums are included in deferred
charges. Amounts receivable under cap agreements are accrued and offset
against interest expense. Amounts receivable or payable under fuel-swap
agreements are recognized in income when realized. Any material
unrealized gains or losses on fuel swaps and interest-rate caps will be
deferred until realized. For further information on derivatives, see
Note 11, ``Derivative Financial Instruments.''
N. CASH AND SPECIAL DEPOSITS
Cash and special deposits at December 31, 1995, include $1.4 million of
special deposits. These funds, which are held by a trustee, represent
the proceeds from the sale of the company's land or property, which was
subject to the lien of its First Mortgage Bond indenture. The proceeds
are held in trust pursuant to the terms of the company's First Mortgage
Bond indentures.
2. LEASES
CL&P and WMECO finance up to $475 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. 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,
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 operating expense:
Year Capital Leases Operating Leases
---- -------------- ----------------
1995...................... $56,307,000 $23,793,000
1994...................... 60,975,000 24,192,000
1993...................... 76,606,000 24,355,000
Interest included in capital lease rental payments was $10,587,000 in 1995,
$10,228,000 in 1994, and $11,298,000 in 1993.
Substantially all of the capital lease rental payments were made pursuant
to the nuclear fuel lease agreement. Future minimum lease payments under
the nuclear fuel capital lease cannot be reasonably estimated on an annual
basis due to variations in the usage of nuclear fuel.
Future minimum rental payments, excluding annual nuclear fuel lease
payments and executory costs, such as property taxes, state use taxes,
insurance, and maintenance, under long-term noncancelable leases, as of
December 31, 1995 are:
Year Capital Leases Operating Leases
---- -------------- ----------------
(Thousands of Dollars)
1996...................... $ 2,800 $ 19,000
1997...................... 2,700 17,500
1998...................... 2,700 12,600
1999...................... 2,700 10,900
2000...................... 2,500 9,900
After 2000................ 39,600 53,700
-------- ----------
Future minimum lease payments 53,000 $123,600
========
Less amount representing interest 33,600
--------
Present value of future minimum lease
payments for other than nuclear fuel 19,400
Present value of future nuclear fuel
lease payments............ 152,900
--------
Total..................... $172,300
========
3. NUCLEAR DECOMMISSIONING
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. The company's 1992 decommissioning study concluded that
complete and immediate dismantlement at retirement continues to be the most
viable and economic method of decommissioning the three Millstone units. A
1994 Seabrook decommissioning study also confirmed that complete and
immediate dismantlement at retirement is the most viable and economic
method of decommissioning 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 1995 dollars, is $300.3 million and $265.8 million,
respectively. CL&P's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 in year-end 1995 dollars, is
$232.1 million and $17.2 million, respectively. These estimated costs
assume levelized collections for the Millstone units and escalated
collections for Seabrook, and after-tax earnings on the Millstone and
Seabrook decommissioning funds of 6.5 percent and 6.1 percent,
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 $30.5
million in 1995, $25.6 million in 1994, and $21.9 million in 1993. Nuclear
decommissioning, as a cost of removal, is included in the accumulated
provision for depreciation on the Consolidated Balance Sheets. At December
31, 1995, the balance in the accumulated reserve for decommissioning
amounted to $270.0 million. See `Nuclear Decommissioning'' in the MD&A
for a discussion of changes being considered by the FASB related to
accounting for closure and removal of long-lived assets (including nuclear
decommissioning).
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.
As of December 31, 1995, CL&P has collected, through rates, $203.5 million,
toward the future decommissioning costs of its share of the Millstone
units, of which $171.8 million has been transferred to external
decommissioning trusts. As of December 31, 1995, CL&P has paid
approximately $1.9 million into Seabrook 1's decommissioning financing
fund. Earnings on the decommissioning trusts and financing fund increase
the decommissioning trust balance and the accumulated reserve for
decommissioning. Unrealized gains and losses associated with the
decommissioning trusts and financing fund also impact the balance of the
trusts and financing fund and the accumulated reserve for decommissioning.
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 the 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.
CL&P, along with other New England utilities, has equity investments in the
four Yankee companies. Each Yankee company owns a single nuclear
generating unit with service lives that are expected to end during the
years 2007 through 2012. The estimated cost, in year-end 1995 dollars, of
decommissioning CL&P's ownership share of units owned and operated by CY,
MY, and VY is $133.0 million, $42.4 million, and $33.0 million,
respectively. Under the terms of the contracts with the Yankee companies,
the shareholders-sponsors are responsible for their proportionate share of
the operating costs of each unit, including decommissioning. The nuclear
decommissioning costs of the Yankee companies are included as part of the
cost of power purchased by CL&P.
YAEC is in the process of dismantling its nuclear facility. Accelerated
decommissioning of that unit has been delayed because of litigation over
the Nuclear Regulatory Commission's (NRC) approval of YAEC's
decommissioning plan. Effective November 1995, YAEC began billing its
sponsors, including CL&P, amounts based on a revised estimate approved by
the FERC that assumes decommissioning of the plant by the year 2000. This
revised decommissioning estimate was based on access to the Barnwell, South
Carolina low-level radioactive waste facility, changes in assumptions about
earnings in decommissioning trust investments, and changes in other
decommissioning cost assumptions. At December 31, 1995, the estimated
remaining costs, including decommissioning, amounted to $268.8 million of
which CL&P's share was approximately $65.8 million. Management expects
that CL&P will continue to be allowed to recover such FERC-approved costs
from its customers. Accordingly, CL&P has recognized these costs as a
regulatory asset, with the corresponding obligation, on its Consolidated
Balance Sheets.
4. SHORT-TERM DEBT
NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company (RRR) have
established a revolving-credit facility with a group of 15 banks. Under
this facility, the participating companies may borrow up to an aggregate of
$343 million. Individual borrowing limits as of January 1, 1996 were $150
million for NU parent, $325 million for CL&P, $60 million for WMECO, $5
million for HWP, $50 million for NNECO, and $22 million for RRR. The
system companies may borrow funds on a short-term revolving basis using
either fixed-rate loans or standby loans. Fixed rates are set using
competitive bidding. Standby-loan rates are based upon several alternative
variable rates. The system companies are obligated to pay a facility fee
of 0.15 percent per annum of each bank's total commitment under the three-
year portion of the facility, representing 75 percent of the total
facility, plus 0.10 percent per annum of each bank's total commitment under
the 364-day portion of the facility, representing 25 percent of the total
facility. At December 31, 1995 and 1994, there were $42.5 million and $30
million of borrowings, respectively, under the facility. At December 31,
1995, CL&P had $10 million in borrowings outstanding under the facility.
The weighted average interest rate on notes payable to banks outstanding at
December 31, 1995 was 6.0 percent. The weighted average interest rates on
notes payable to banks and commercial paper outstanding at December 31,
1994 were 6.2 percent and 6.4 percent, respectively.
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. However, borrowings based on loans from
NU parent bear interest at NU parent's cost and must be repaid based upon
the terms of NU parent's original borrowing. At December 31, 1995 and
1994, CL&P had $10.3 million and $92.8 million, respectively, of borrowings
outstanding from the Pool. The interest rates on borrowings from the Pool
at December 31, 1995 and 1994 were 4.7 percent and 4.9 percent,
respectively.
Maturities of CL&P's short-term debt obligations are for periods of three
months or less.
The amount of short-term borrowings that may be incurred by CL&P is subject
to periodic approval by the SEC under the 1935 Act. In addition, the
charter of CL&P contains provisions restricting the amount of short-term
borrowings. Under the SEC and/or charter restrictions, the company was
authorized, as of January 1, 1995, to incur short-term borrowings up to a
maximum of $325 million.
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1995 Outstanding
Redemption December 31, December 31,
-------------------------
Description Price 1995 1995 1994 1993
- ----------------------------------------------------------------------------
(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
1989 Adjustable Rate DARTS - - - 50,000 50,000
------- -------- --------
Total preferred stock not subject
to mandatory redemption $116,200 $166,200 $166,200
=============================
All or any part of each outstanding series of such preferred stock may be
redeemed by the company at any time at established redemption prices plus
accrued dividend to the date of redemption.
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1995 Outstanding
Redemption December 31, December 31,
---------------------------
Description Price* 1995 1995 1994 1993
- ----------------------------------------------------------------------------
(Thousands of Dollars)
9.00% Series of 1989 - - $ - $ 75,000 $ 75,000
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
--------- --------- --------
155,000 230,000 230,000
Less preferred stock to be redeemed
within one year.... - 3,750 -
--------- --------- --------
Total preferred stock subject to
mandatory redemption $ 155,000 $ 226,250 $ 230,000
========= ========= =========
*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 1995 1994 1993
-------------------------------------------------------------------
(Thousands of Dollars)
9.10% Series of 1987 $ - - - 2,000,000
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 1996 through 2000, aggregate approximately $0 in
1996 and 1997, $3.8 million in 1998, and $19.8 million in 1999 and 2000.
In case of default on sinking-fund payments or the payment of dividends, no
payments may be made on any junior stock by way of dividends or otherwise
(other than in shares of junior stock) so long as the default continues.
If the company is in arrears in the payment of dividends on any outstanding
shares of preferred stock, the company would be prohibited from redemption
or purchase of less than all of the preferred stock outstanding. All or
part of each of the series named above may be redeemed by the company 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,
----------------------
1995 1994
-------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
7 5/8% Series UU ............due 1997 $ 197,245 $ 200,000
6 1/2% Series T .............due 1998 20,000 20,000
7 1/4% Series VV ............due 1999 100,000 100,000
5 1/2% Series A .............due 1999 140,000 140,000
5 3/4% Series XX ............due 2000 200,000 200,000
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 ........ 1,297,245 1,300,000
Pollution Control Notes:
Variable rate, due 2016-2022.......... 46,400 46,400
Tax exempt, due 2028.................. 315,500 315,500
Fees and interest due for spent fuel
disposal costs (Note 1L) .... 149,978 141,694
Other................................. 20,286 28,398
Less amounts due within one year...... 9,372 8,111
Unamortized premium and discount, net. (7,391) (8,302)
----------- ----------
Long-term debt, net.................. $1,812,646 $1,815,579
=========== ==========
Long-term debt and cash sinking-fund requirements on debt outstanding at
December 31, 1995 for the years 1996 through 2000 are approximately $9.4
million, $208.1 million, $20.0 million, $240.0 million, and $200.0 million,
respectively. In addition, there are annual one-percent sinking- and
improvement-fund requirements, currently amounting to $13.0 million for
1996 and 1997, $11.0 million for 1998, $10.8 million for 1999, and $8.4
million for 2000. Such sinking- and improvement-fund requirements may be
satisfied by the deposit of cash or bonds or by certification of property
additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company 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 the company's utility plant is subject to the lien of
its first mortgage bond indenture. As of December 31, 1995 and 1994, the
company 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 3.8 percent to 4.0 percent for 1995 and
from 2.7 percent to 3.3 percent for 1994.
8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
For the Years Ended December 31, 1995 1994 1993
-------------------------------------------------------------------------
(Thousands of Dollars)
Current income taxes:
Federal..................... $ 93,906 $108,371 $115,403
State....................... 37,898 39,966 44,473
--------- -------- --------
Total current............. 131,804 148,337 159,876
--------- -------- --------
Deferred income taxes, net:
Federal..................... 52,075 44,180 3,808
State...................... 5,085 842 (12,987)
--------- -------- ---------
Total deferred............ 57,160 45,022 ( 9,179)
Investment tax credits ....... (7,640) (7,358) (11,009)
--------- -------- ---------
Total income tax expense.. $181,324 $186,001 $139,688
======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses $178,346 $190,249 $142,987
Other income taxes............ 2,978 (4,248) (3,299)
-------- --------- ----------
Total income tax expense...... $181,324 $186,001 $139,688
======== ======== ========
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1995 1994 1993
- --------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits,and disposal costs $44,278 $ 38,874 $ 43,663
Energy adjustment clauses............ 23,302 14,465 (52,189)
Demand-side management............... 1,310 203 9,156
Nuclear plant deferrals.............. (8,055) (20,452) (13,979)
Bond redemptions..................... (2,255) 6,826 6,935
Contractual settlements.............. (9,496) 109 (308)
Other................................ 8,076 4,997 (2,457)
-------- --------- ---------
Deferred income taxes, net........... $57,160 $ 45,022 $ (9,179)
======== ========= =========
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, 1995 1994 1993
- --------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income........ $135,289 $134,501 $115,898
Tax effect of differences:
State income taxes, net of federal
benefit 27,939 26,526 20,466
Depreciation....................... 23,517 18,602 19,264
Deferred nuclear plants return..... (1,639) (4,681) (8,294)
Amortization of deferred nuclear
plants return 20,218 19,755 18,648
Property tax....................... (159) 5,286 (12,320)
Investment tax credit amortization. (7,640) (7,358) (11,009)
Adjustment for prior years' taxes.. (10,442) (2,706) (2,330)
Other, net......................... (5,759) (3,924) (635)
--------- --------- ---------
Total income tax expense............. $181,324 $186,001 $139,688
========= ========= =========
9. EMPLOYEE BENEFITS
A. PENSION BENEFITS
The company participates in a uniform noncontributory-defined benefit
retirement plan covering all regular system employees. Benefits are
based on years of service and employees' highest eligible compensation
during five consecutive years of employment. The company's direct
portion of the system's pension (income)/cost, part of which was
(credited)/charged to utility plant, approximated $(10.4) million in
1995, $(2.3) million in 1994, and $7.6 million in 1993. The company's
pension costs for 1995, 1994, and 1993 include approximately $0.1
million, $4.8 million, and $13.1 million, respectively, related to
workforce-reduction programs.
Currently, the company funds annually an amount at least equal to that
which will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are
determined using market-related values of pension assets. Pension
assets are invested primarily in domestic and international equity
securities and bonds.
The components of net pension cost for CL&P are:
For the Years Ended December 31, 1995 1994 1993
------------------------------------------------------------------
(Thousands of Dollars)
Service cost.................. $ 7,543 $ 13,072 $ 21,907
Interest cost................. 37,110 36,103 35,055
Return on plan assets......... (138,582) 1,020 (80,615)
Net amortization.............. 83,516 (52,536) 31,254
---------- --------- ---------
Net pension (income)/cost..... $(10,413) $ (2,341) $ 7,601
========== ========= =========
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1995 1994 1993
-------------------------------------------------------------------
Discount rate................. 8.25% 7.75% 8.00%
Expected long-term rate of return 8.50 8.50 8.50
Compensation/progression rate. 5.00 4.75 5.00
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
At December 31, 1995 1994
-----------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation, including
vested benefits at December 31, 1995 and
1994 of $404,540,000 and $374,109,000,
respectively $432,987 $401,889
======== ========
Projected benefit obligation............. $515,121 $471,079
Market value of plan assets.............. 668,929 568,294
--------- --------
Market value in excess of projected benefit
obligation 153,808 97,215
Unrecognized transition amount........... (8,285) (9,204)
Unrecognized prior service costs......... 1,293 1,420
Unrecognized net gain.................... (135,817) (88,845)
--------- ---------
Prepaid pension asset.................... $ 10,999 $ 586
========== =========
------------------------------------------------------------------
The following actuarial assumptions were used in calculating the
plan's year-end funded status:
At December 31, 1995 1994
------------------------------------------------------------------
Discount rate............................ 7.50% 8.25%
Compensation/progression rate............ 4.75 5.00
B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The company provides certain health care benefits, primarily medical and
dental, and life insurance benefits through a benefit plan to retired
employees (referred to as SFAS 106 benefits). These benefits are
available for employees retiring from the company who have met specified
service requirements. For current employees and certain retirees, the
total SFAS 106 benefit is limited to two times the 1993 per-retiree
health care costs. The SFAS 106 obligation has been calculated based on
this assumption. CL&P's direct portion of SFAS 106 health care and life
insurance costs, part of which were deferred or charged to utility
plant, approximated $20.7 million in 1995, $22.3 million in 1994, and
$23.2 million in 1993.
During 1995 and 1994, the company funded SFAS 106 postretirement costs
through external trusts. During 1993, the company did not fund SFAS 106
postretirement costs through external trusts. The company 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, 1995 1994 1993
-------------------------------------------------------------------------
(Thousands of Dollars)
Service cost .................... $ 2,248 $ 2,371 $ 3,397
Interest cost ................... 11,510 12,157 12,091
Return on plan assets ........... (1,015) 2 -
Amortization of unrecognized transition
obligation 7,344 7,344 7,682
Other amortization, net ......... 602 430 -
-------- -------- -------
Net health care and life insurance costs $20,689 $22,304 $23,170
======= ======= =======
-------------------------------------------------------------------------
For calculating SFAS 106 benefits cost, the following assumptions were
used:
For the Years Ended December 31, 1995 1994 1993
-------------------------------------------------------------------------
Discount rate ................... 8.00% 7.75% 7.75%
Long-term rate of return:
Health assets, net of tax ..... 5.00 5.00 5.00
Life assets ................... 8.50 8.50 8.50
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
At December 31, 1995 1994
---------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement benefit obligation of:
Retirees .................................. $126,624 $129,111
Fully eligible active employees ........... 198 241
Active employees not eligible to retire ... 29,798 25,203
-------- --------
Total accumulated postretirement benefit obligation 156,620 154,555
Market value of plan assets ................ 11,378 167
-------- --------
Accumulated postretirement benefit obligation
in excess of plan assets ................. (145,242) (154,388)
Unrecognized transition amount ............. 124,850 132,194
Unrecognized net loss ...................... 1,260 192
-------- --------
Accrued postretirement benefit liability ... $(19,132) $(22,002)
======== =========
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
At December 31, 1995 1994
--------------------------------------------------------------------
Discount rate .............................. 7.50% 8.00%
Health care cost trend rate (a) ............ 8.40 10.20
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 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, 1995 by $8.5
million and the aggregate of the service and interest cost components of
net periodic postretirement benefit cost for the year then ended by $0.7
million. The trust holding the plan assets is subject to federal income
taxes at a 35 percent tax rate.
CL&P is currently recovering SFAS 106 costs, including amounts
previously deferred.
10.COMMITMENTS AND CONTINGENCIES
A. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision.
CL&P currently forecasts construction expenditures of approximately
$776.3 million for the years 1996-2000, including $154.6 million for
1996. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $240.4 million for the years 1996-2000, including $35.1
million for 1996. See Note 2, ``Leases,'' for additional information
about the financing of nuclear fuel.
B. NUCLEAR PERFORMANCE
Outages that occurred over the period October 1990 through February 1992
at the Millstone nuclear units have been the subject of five ongoing
prudence reviews in Connecticut. CL&P has received final decisions on
each of the reviews. Three of these prudence reviews are either on
appeal or still pending at the DPUC. The exposure under these three
dockets is approximately $92 million.
On April 10, 1995, the DPUC initiated a proceeding to investigate the
prudence of a Millstone 2 extended outage, which ended June 1994.
Approximately $13 million of costs are at issue.
In October 1994, Millstone 2 began a planned refueling and maintenance
outage that was originally scheduled for 63 days. The outage
encountered several unexpected difficulties which extended the duration
of the outage until August 4, 1995. Total replacement power costs
attributable to the extension of the outage for CL&P were approximately
$69 million. Operation and maintenance (O&M) costs incurred during the
outage were approximately $57 million, an increase of $30 million as a
result of the outage extension. O&M costs associated with the refueling
outage are deferred and amortized through rates. The recovery of
replacement power and O&M costs is subject to refund pending a prudence
review in Connecticut.
Management does not believe the outcome of the prudence reviews
discussed above will have a material adverse impact on the company's
financial position and results of operations.
In November 1995, Millstone 1 began a planned refueling and maintenance
outage that was originally scheduled for 49 days. The outage has
encountered several unexpected difficulties which has lengthened the
duration of the outage. The impact of the outage extension is currently
under review, but the unit is not expected to return to service until
the mid-to-late part of the second quarter of 1996. The estimated costs
attributable to this outage extension are replacement-power costs of
$5.2 million per month and O&M costs of approximately $16.2 million.
Recovery of the costs related to this outage is subject to prudence
reviews by the DPUC.
On January 31, 1996, the NRC announced that the three Millstone nuclear
power plants operated by NNECO have been placed on its "watch list"
because of long standing performance concerns. The NRC cited a number
of operational problems which have arisen since 1990 at the Millstone
plants.
The NRC recognized that there are significant current variations in the
performance of the three units. The performance concerns cited by the
NRC, combined with NU's failure to maintain previous performance
improvements, have resulted in the NRC requiring close monitoring of
Millstone unit operations and the implementation of a corrective action
program. While the NRC has not specifically restricted operations at
the Millstone site, the company expects that there will be costs
associated with the NRC's actions that cannot be accurately estimated at
this time.
C. ENVIRONMENTAL MATTERS
CL&P is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the disposal of toxic
substances and hazardous and solid wastes, and the handling and use of
chemical products. CL&P has an active environmental auditing and
training program and believes that it is in substantial compliance with
current environmental laws and regulations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations, and
other facilities. The cumulative long-term, cost impact of increasingly
stringent environmental requirements cannot accurately be estimated.
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 by-
products and wastes. CL&P may also encounter significantly increased
costs to remedy the environmental effects of prior waste handling
activities.
CL&P has recorded a liability for what it believes, based upon
information currently available, are its estimated environmental
remediation costs 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, 1995, 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 $7.4 million, which management has determined to be the
most probable amount within the range of $7.4 million to $9.8 million.
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 covered by the federal government's third-
party liability indemnification program, the company could be assessed
in proportion to its ownership interest in each nuclear unit up to $75.5
million not to exceed $10 million per nuclear unit in any one year. The
maximum assessment is to be adjusted at least every five years for
inflationary changes. Based on the ownership interest in Millstone 1,
2, and 3 and in Seabrook 1, CL&P's maximum liability, including any
additional potential assessments, would be $173.6 million per incident.
In addition, through power purchase contracts with the three operating
Yankee regional nuclear generating companies, CL&P would be responsible
for up to an additional $44.4 million per incident. Payments for CL&P's
ownership interest in nuclear generating facilities would be limited to
a maximum of $27.5 million per incident 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 $12.2 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 the company with respect to losses arising during
current policy years are approximately $8.6 million under the
replacement power policies and $31.6 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 a industry
basis for coverage of worker claims. All participating reactor
operators insured under this coverage are subject to retrospective
assessments of $3.0 million per reactor. The maximum potential
assessment against CL&P with respect to losses arising during the
current policy period is approximately $9.1 million.
E. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: CL&P, along with PSNH and WMECO, purchased
approximately 6.7 percent of their electricity requirements pursuant to
long-term contracts with the Yankee companies. Under the terms of their
agreements, the companies pay their ownership (or entitlement) shares of
generating 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 recovered
through the companies' rates. CL&P's total cost of purchases under
these contracts for the units that are operating amounted to $105.8
million in 1995, $102.1 million in 1994, and $112.3 million in 1993.
See Note 1C, ``Summary of Significant Accounting Policies-Investments
and Jointly Owned Electric Utility Plant,'' and Note 3, ``Nuclear
Decommissioning,'' for more information on the Yankee companies.
Nonutility Generators: CL&P has entered into various arrangements for
the purchase of capacity and energy from nonutility generators. These
arrangements have terms from 10 to 30 years, currently expiring in the
years 2001 through 2026, and requires the company to purchase the energy
at specified prices or formula rates. For the twelve months ended
December 31, 1995, approximately 13 percent of system electricity
requirements was met by nonutility generators. CL&P's total cost of
purchases under these arrangements amounted to $282.2 million in 1995,
$277.4 million in 1994, and $279.8 million in 1993. These costs are
eventually recovered through the company's rates.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH,
WMECO, and HWP 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.
The estimated annual costs of CL&P's significant long-term contractual
arrangements are as follows:
1996 1997 1998 1999 2000
----------------------------------------------------------------------
(Millions of Dollars)
Yankee companies $105.8 $103.1 $111.0 $112.9 $120.5
Nonutility generators 269.0 273.5 280.1 290.1 290.9
Hydro-Quebec .. 20.3 19.4 18.7 18.3 18.0
11. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-
defined interest-rate and fuel-price risks. The company does not use
them for trading purposes.
Interest-Rate Cap Contracts: CL&P has entered into interest-rate cap
contracts with financial institutions in order to reduce a portion of
the interest-rate risk associated with certain variable-rate tax-exempt
pollution control revenue bonds. During 1995, there was one outstanding
contract held by CL&P covering $340 million of variable-rate debt, which
expired in January 1996. The contract entitled CL&P to receive from a
counterparty the amounts, if any, by which the interest payments on a
portion of its variable-rate tax-exempt pollution control revenue bonds
exceed the J. J. Kenny High Grade Index. Due to its upcoming
expiration, as of December 31, 1995, the total fair market value of the
cap was $0.
Fuel Swaps: CL&P also uses fuel-swap agreements with financial
institutions to hedge against fuel-price risk created by long-term
negotiated energy contracts. These fuel swaps minimize exposure
associated with rising fuel prices, and effectively fix CL&P's cost of
fuel for these negotiated energy contracts. Under the swap agreements,
CL&P exchanges monthly payments based on the differential between a
fixed and variable price for the associated fuel. As of December 31,
1995, CL&P had outstanding agreements with a total notional value of
approximately $249 million, and a negative mark-to-market position of
approximately $19 million. When the mark-to-market position for the
swap agreements is negative, the profitability of the long-term
negotiated energy contracts whose fuel exposure has been hedged
increases by a corresponding amount.
These swap agreements have been made with various financial
institutions, each of which are rated "A" or better by Standard & Poor's
rating group. CL&P is exposed to credit risk on the fuel swaps if the
counterparties fail to perform their obligations. However, CL&P
anticipates that the counterparties will be able to fully satisfy their
obligations under the contracts.
12.FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash, special deposits, and nuclear decommissioning trusts: The carrying
amounts approximate fair value.
SFAS 115, Accounting for Certain Investments in Debt and Equity Security,
requires investments in debt and equity securities to be presented at fair
value and was adopted by the company on a prospective basis as of January 1,
1994. During 1995, the investments held in the company's nuclear
decommissioning trusts increased by $14.4 million as of December 31, 1995
and decreased by approximately $3.8 million as of December 31, 1994, with a
corresponding offset to the accumulated provision for depreciation. The
$14.4 million increase in 1995 represents cumulative gross unrealized
holding gains. The cumulative gross unrealized holding losses were
immaterial for 1995. The $3.8 million decrease in 1994 represents
cumulative gross unrealized holding gains of $1.6 million, offset by
cumulative gross unrealized holding losses of $5.4 million. There was no
change in funding requirements of the trusts nor any impact on earnings as a
result of the adoption of SFAS 115.
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, 1995 Amount Value
--------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to mandatory redemption $ 116,200 $ 82,448
Preferred stock subject to mandatory redemption 155,000 157,575
Long-term debt - First Mortgage Bonds .... 1,297,245 1,329,549
Other long-term debt ..................... 532,164 532,164
Monthly Income Preferred Securities ...... 100,000 108,520
--------------------------------------------------------------------------
Carrying Fair
At December 31, 1994 Amount Value
--------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to mandatory redemption $ 166,200 $ 113,825
Preferred stock subject to mandatory redemption 230,000 218,075
Long-term debt - First Mortgage Bonds .... 1,300,000 1,182,894
Other long-term debt ..................... 531,992 531,992
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.
13.MONTHLY INCOME PREFERRED SECURITIES OF SUBSIDIARY
In January 1995, CL&P Capital, LP (CL&P LP) 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 a minority interest.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------------------------------------
To the Board of Directors
of The Connecticut Light and Power Company and Subsidiaries:
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, 1995 and 1994, 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, 1995. 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 of disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of The
Connecticut Light and Power Company and Subsidiaries as of December 31,
1995 and 1994, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
As discussed in Note 1A to the Financial Statements, effective January
1, 1993, The Connecticut Light and Power Company and Subsidiaries changed
its method of accounting for property taxes.
/s/ Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 16, 1996
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
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
financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
Net income was approximately $205 million in 1995, an increase of approximately
$7 million, from approximately $198 million in 1994. The 1995 net income was
higher primarily due to higher revenues from the final step of the company's
three-year rate plan, lower income tax expenses, higher 1995 cogeneration
deferrals, and a reduction in maintenance costs. These increases were partially
offset by lower wholesale revenues, higher operation costs, and higher fuel and
purchased-power costs.
Retail kilowatt-hour sales fell by 0.3 percent in 1995, as a result of a flat
economy in southern New England and mild weather in the first quarter of 1995.
With the southern New England economy not forecasted to grow substantially
during 1996, sales levels are expected to remain flat.
CL&P acts as both a buyer and a seller of electricity in the highly competitive
wholesale electricity market in the Northeast. Increased competition has made
the renegotiation of expiring wholesale contracts, as well as the signing of new
contracts, financially challenging. As a result, wholesale power revenues fell
to approximately $188 million in 1995, from approximately $215 million in 1994.
CL&P's efforts to enhance its wholesale revenues resulted in several new
contracts in 1995.
During 1995, the Federal Energy Regulatory Commission issued a proposal for
restructuring the electric-power industry, which calls for open access to
transmission facilities, a standard formula for calculating rates, and full
recovery of stranded investments. The impact on CL&P of this proposal, which is
expected to be finalized in 1996, is not known at this time.
During 1995, the Coalition of Northeastern Governors released its report
addressing the restructuring of the electric-power industry and its resulting
impact on customers and states. The report presented the future as one in which
there would be some form of continued regulation for transmission and
distribution with fully competitive generation.
Also in 1995, the Department of Public Utility Control (DPUC) concluded that
while increased competition is in the public interest, electric utilities should
have the opportunity to recover "net, nonmitigatable stranded costs" during a
transition period to full competition. While such a conclusion is encouraging
there is uncertainty with regard to the final regulatory and legislative
definitions of terms such as "net, nonmitigatable" and "stranded costs."
CL&P is taking a proactive role in the electric-power industry's movement toward
competition. In its "Path To A Competitive Future" (the plan), CL&P outlined a
comprehensive approach to enhancing customer satisfaction and market efficiency
while moving toward full competition in the electricity marketplace. The plan
also calls for several significant changes in electricity pricing, the ability
to introduce new products and services, the method of rate-setting, and the
operation of the New England Power Pool. The plan also calls for the phase-in of
supplier choices through the use of pilot programs. Management believes that a
fully competitive market for electricity should begin once all issues relating
to the transition from traditional utility regulation have been thoroughly
addressed.
In addition to the formulation of this plan and ongoing meetings with
legislators, regulators, and others in the industry, CL&P is moving ahead in
other areas, including revenue enhancement initiatives and cost reductions, to
better position itself for an increasingly competitive environment.
A comprehensive companywide effort, which started in 1994, to reengineer CL&P's
business and operating processes continued throughout 1995. CL&P expects that
this effort will have significant positive effects on operating costs and
customer service. Many of the organizational changes in the operating and
service functions announced in 1995 and early 1996 are consistent with the
initial recommendations of the reengineering teams. While CL&P's reengineering
efforts will be reduced in 1996, implementation costs relating to the previous
reengineering efforts are expected to increase.
With retail electric revenues accounting for approximately 90 percent of its
1995 revenues, CL&P has continued to develop a number of initiatives to retain
and serve its existing customers and to expand its retail customer base. The
most visible result of these efforts is the expansion of the Retail Marketing
organization. Retail Marketing's mission is to better understand the needs and
concerns of CL&P's retail customer and to develop innovative approaches to
addressing these issues. These initiatives include providing discounts to
certain customers for signing economic development and competitive generation-
based contracts, offering demand-side-management services, and providing
additional products and services.
WORKFORCE REDUCTIONS
In January 1996, NU completed its nuclear workforce reduction plan.
Approximately 220 positions were eliminated through a combination of early
retirements, attrition, and layoffs. The total pretax cost of the workforce
reduction to the NU system, which was recognized in 1995, was approximately $9
million.
RATE MATTERS
CL&P follows accounting principles in accordance with Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation" that allows the economic effects of rate regulation to be
reflected. Under these principles, regulators may permit incurred costs for
certain events or transactions, which would be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date.
The creation of these regulatory assets has kept down electric rates in past
years, at the expense of having higher rates in the future. At December 31,
1995, CL&P's regulatory assets totaled approximately $1.2 billion. The largest
regulatory asset, nearly $864 million, is related to the future recovery of
income taxes. The substantial costs of amortizing these regulatory assets would
hinder CL&P from competing effectively in an openly competitive electric market
if customers are not required to pay such costs. Given the increasingly
competitive nature of the industry and increased activity in the regulatory
environment, CL&P has made the recovery of regulatory assets one of its central
financial strategies, while balancing the customer's pricing needs with NU's
shareholder's earnings requirements. Under its existing rate agreement, CL&P is
allowed to recover a significant portion of its regulatory assets during the
next five years. However, maintaining or increasing the present recovery level
is dependent upon the outcome of negotiations between CL&P and the DPUC when its
current rate agreement expires.
Given that CL&P's current rate agreement expires during 1996, CL&P will actively
pursue early negotiations with the DPUC to determine whether, or to what extent,
rates should be adjusted going forward. CL&P's strategy during these
negotiations will be to maintain stable rates, applying any available earnings
that may result to reduce the balance of its regulatory assets. Management is
unable to predict the ultimate outcome of these negotiations, which will be
subject to DPUC approval.
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed of." SFAS 121, which was effective January 1, 1996, requires
assets, including regulatory assets, that are no longer probable of recovery
through future revenues be charged to earnings.
If future competition or regulatory actions cause any portion of its operations
to no longer be subject to SFAS 71, CL&P would be required to determine the fair
value of the related regulatory assets and liabilities and record any necessary
write-downs. Additionally, if events create uncertainty about the
recoverability of any of CL&P's remaining long-lived assets, a similar analysis
would be required for those assets in accordance with SFAS 121. Under its
current regulatory environment, CL&P believes that its use of SFAS 71 remains
appropriate and that the adoption of SFAS 121 will not have a material impact on
its financial position or results of operations.
See the Notes to Consolidated Financial Statements," Note 1G, for further
details on regulatory accounting.
CL&P's retail rates increased by approximately $48 million, or 2.06 percent, in
July 1995, representing the final step of a three-year rate plan approved by the
DPUC. The 1993 rate decision has been appealed. If this appeal prevails there
may be revenues subject to refund, however, management believes it is unlikely
that the appeal will prevail.
CL&P recovers from, or refunds to, customers certain fuel costs if its nuclear
units do not operate at a predetermined capacity factor (currently 72 percent)
through a Generation Utilization Adjustment Clause (GUAC). CL&P is currently
recovering approximately $80 million of fuel costs for the 1994-1995 GUAC period
(net of $19 million of asserted fuel overrecoveries for the period) over 18
months. CL&P has appealed the $19 million that was set aside from its allowed
recovery and will seek to join this appeal to appeals currently pending from
previous GUAC periods.
See the "Notes to Consolidated Financial Statements," Note 10B, for further
details on outage deferrals and recoveries.
NUCLEAR PERFORMANCE
On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 1,
2, and 3 (Millstone) on its "watch list." The NRC's action was in response to
a number of performance concerns which have arisen since 1990 and a failure to
resolve employee safety concerns. The NRC's action will result in close
monitoring of programs and performance at Millstone to assure the development
and implementation of effective corrective actions.
NU's management plans to continue its extensive efforts already under way to
address these concerns. Concurrent with the NRC's action, NU provided the NRC
with the results of a comprehensive self-assessment review of the employee
concern program at Millstone. Additionally, in January 1996, NU announced a
reorganization of its nuclear operations which included the creation of a new
office of Nuclear Safety and Oversight.
Although the start-up of Millstone 1, which is currently in outage, will be
affected by its placement on the NRC's "watch list," operations at Millstone 2
and 3 have not been restricted. NU's management expects that the increased NRC
attention will inevitably have effects and costs that are not known at this
time.
In November 1995, Millstone 1 began a planned refueling and maintenance outage.
The outage has been extended to allow NU to complete reviews required by the
NRC. In response to a request by the NRC, NU is conducting a detailed review of
Millstone 1's Final Safety Analysis Report and an assessment of the plant's
readiness to ensure that the future operation of the plant will be conducted in
accordance with the terms and conditions of its operating license and the NRC's
regulations. The outage schedule is currently under review, but the unit is not
expected to return to service before the mid-to-late part of the second quarter
of 1996. Total replacement-power costs attributable to the Millstone 1 outage
extension for CL&P are expected to be approximately $6 million per month. In
addition, operation and maintenance costs to be incurred as a result of the
extension are estimated to be approximately $16 million. Outage costs are
deferred and amortized through rates. The recovery, or refund, of outage costs
is subject to prudence reviews.
The composite capacity factor of the five nuclear generating units that NU
operates-including the Connecticut Yankee nuclear unit-was 69.9 percent in 1995,
compared with 67.5 percent for 1994, and a 1995 national average of 77.6
percent. The 1995 capacity factor was impacted by an extended refueling and
maintenance outage for Millstone 2.
See the "Notes to Consolidated Financial Statements," Note 10B, for further
information on outage deferrals and recoveries.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and comply with the multitude of
environmental requirements it faces. NU has active auditing programs addressing
a variety of regulatory requirements, including an environmental auditing
program to detect and remedy noncompliance with environmental laws or
regulations.
CL&P is potentially liable for environmental cleanup costs at a number of sites
both 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, 1995, CL&P had recorded
an environmental reserve amounting to approximately $7 million, the minimum
amount required under SFAS 5, "Accounting for Contingencies." These costs
could be significantly higher if alternative remedies become necessary.
In October 1995, the Connecticut Department of Environmental Protection (CDEP)
issued a consent order to CL&P and the Long Island Lighting Company (LILCO)
requiring those companies to address leaks from the Long Island cable, which is
jointly owned by CL&P and LILCO. CL&P will incur additional costs to meet the
requirements of the order and to meet any subsequent CDEP requirements resulting
from the studies under the consent order, which cannot be estimated at this
time. Management also cannot determine at this time whether long-term future
operation of the cable will remain cost effective subsequent to any additional
CDEP requirements.
NUCLEAR DECOMMISSIONING
CL&P's estimated cost to decommission its shares of Millstone 1, 2, and 3 and
Seabrook 1 is approximately $815 million in year-end 1995 dollars. These costs
are being recognized over the lives of the respective units and a portion is
being recovered through rates.
The FASB is currently reviewing the accounting for closure and removal costs,
including decommissioning and similar costs, for long-lived assets. If current
electric-power industry accounting practices for such decommissioning costs were
changed, annual provisions for decommissioning would increase and the estimated
costs for decommissioning would be recorded as a liability rather than as a
component of accumulated depreciation.
See the "Notes to Consolidated Financial Statements," Note 3, for further
information on nuclear decommissioning, including CL&P's share of costs to
decommission the regional nuclear generating units.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $11 million in 1995, from
1994, primarily due to higher cash operating expenses, partially offset by
higher revenues from retail-rate increases and recoveries. Cash used for
financing activities increased approximately $8 million in 1995, from 1994,
primarily due to a net decrease in short-term debt, partially offset by lower
net reacquisitions and retirements of long-term debt. Cash used for investments
decreased approximately $20 million in 1995, from 1994, primarily due to lower
construction and nuclear fuel expenditures, partially offset by higher
investment in the nuclear decommissioning trusts.
In 1995, CL&P applied the bulk of its excess cash to reduce debt and preferred
stock levels. Although CL&P's long-term debt levels changed little, its short-
term debt levels fell from $179 million at the beginning of 1995 to $52 million
at the end of the year. CL&P's preferred stock levels were reduced by
approximately $121 million. CL&P has entered into interest-rate-cap and fossil-
fuel-swap contracts to reduce a portion of its interest-rate and fuel-price
risks.
See the "Notes to Consolidated Financial Statements," Note 11, for further
information on derivative financial instruments and the "Notes to Consolidated
Financial Statements," Notes 6, 7, and 10A, for further information on
construction and long-term debt funding requirements.
RESULTS OF OPERATIONS
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table below.
Change In Operating Revenues
Increase/(Decrease)
1995 vs. 1994 1994 vs. 1993
- --------------------------------------------------------------------------
(Millions of Dollars)
Regulatory decisions $61 $38
Fuel and purchased power
cost recoveries 25 (45)
Sales volume (5) 40
Wholesale revenues (16) (63)
Other revenues (7) (8)
---- -----
Total revenue change $58 $(38)
==== =====
Revenues related to regulatory decisions increased, primarily due to the effects
of the July 1994 and 1995 retail-rate increases and higher recoveries for
demand-side-management costs. Fuel and purchased-power-cost recoveries
increased primarily due to higher energy costs and the recovery of GUAC costs.
Wholesale revenues decreased primarily due to capacity sales contracts that
expired in 1994.
Operating revenues decreased approximately $38 million in 1994, from 1993.
Revenues related to regulatory decisions increased, primarily due to the effects
of the July 1993 and 1994 retail-rate increases, partially offset by lower
recoveries for demand-side-management costs. Fuel and purchased-power-cost
recoveries decreased primarily due to lower GUAC recoveries. Sales volume
increased as a result of higher retail sales from an improved economy. Retail
sales increased 3.4 percent in 1994, from 1993 sales levels. Wholesale revenues
decreased primarily due to the expiration in late 1994 and 1993 of some
significant capacity sales contracts.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased approximately $40
million in 1995, from 1994, primarily due to higher fossil generation and higher
priced outside energy purchases from other utilities in 1995.
Fuel, purchased and net interchange power decreased approximately $89 million in
1994, from 1993, primarily due to lower recognition of replacement-power fuel
costs in 1994, partially offset by a higher level of outside energy purchases
from other utilities in 1994.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses, net increased approximately $5 million
in 1995, from 1994. Operation expenses increased approximately $19 million,
primarily due to higher demand-side-management costs, higher rate recovery of
postretirement benefit costs, and higher capacity charges from regional nuclear
generating units, partially offset by higher nuclear reserves for
excess/obsolete inventory in 1994. Maintenance expenses decreased approximately
$14 million, primarily due to lower maintenance costs at the fossil units and
fossil reserves for excess/obsolete inventory in 1994.
Other operation and maintenance expenses, net decreased approximately $21
million in 1994, from 1993, primarily due to higher costs in 1993 associated
with early-retirement programs, lower 1994 payroll and benefit costs, lower
fossil-unit costs and lower capacity charges from the regional nuclear
generating units, partially offset by higher 1994 costs associated with the
operation and maintenance activities of the nuclear units and higher reserves
for excess/obsolete inventory at the nuclear and fossil units in 1994.
DEPRECIATION EXPENSES
Depreciation expenses increased approximately $11 million both in 1995, from
1994, and in 1994, from 1993, primarily as a result of higher plant balances and
higher decommissioning levels.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased approximately $23 million in
1995, from 1994, primarily due to the higher CL&P cogeneration deferrals in
1995, (approximately $18 million), and the completion, during 1994, of the
amortization of a 1993 cogeneration buyout, partially offset by higher 1995
amortization of Millstone 3 and Seabrook 1 phase-in costs.
Amortization of regulatory assets, net decreased approximately $35 million in
1994, from 1993, primarily due to the deferral of cogeneration expenses
beginning in July 1994 as allowed under the 1993 retail-rate decision and lower
1994 expenses associated with the recovery of Hydro-Quebec support payments,
partially offset by higher 1994 amortization of Millstone 3 and Seabrook 1
phase-in costs.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased approximately $5 million in 1995, from
1994, primarily due to tax benefits from a favorable tax ruling, partially
offset by higher taxable income.
Federal and state income taxes increased approximately $46 million in 1994, from
1993, primarily due to higher taxable income.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased approximately $14 million in 1995, from
1994, and approximately $17 million in 1994, from 1993, primarily because
additional Millstone 3 investments were phased into rates.
OTHER INCOME, NET
Other income, net decreased approximately $4 million in 1995, from 1994, and
increased approximately $6 million in 1994, from 1993, primarily due to the 1993
property tax accounting change as ordered in the 1993 CL&P rate decision. The
allocation of this change to customers occurred in 1994, and amortization began
in 1995.
INTEREST CHARGES
Although the change in 1995, from 1994, was not significant, interest on long-
term debt decreased approximately $14 million in 1994, from 1993, primarily due
to lower average interest rates as a result of refinancing activities and lower
1994 debt levels.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
The cumulative effect of the accounting change of approximately $48 million in
1993 represents the one-time change in the method of accounting for Connecticut
municipal property tax expense recognized in the first quarter of 1993.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA (A)
- ------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues... $2,386,107 $2,328,052 $2,366,050 $2,316,451 $2,275,737
Operating Income..... 324,026 286,948 241,655 288,088 324,428
Net Income........... 205,216 198,288 191,449(b) 206,714 240,818
Cash Dividends on
Common Stock 164,154 159,388 160,365 164,277 172,587
Total Assets......... 6,030,735 6,217,457 6,397,405 5,582,831 5,338,466
Long-Term Debt....... 1,822,018 1,823,690 2,057,280 2,087,936 2,023,268
Preferred Stock Not
Subject to Mandatory
Redemption.... 116,200 166,200 166,200 231,196 306,195
Preferred Stock Subject to
Mandatory Redemption(c) 155,000 230,000 230,000 200,000 141,892
Obligations Under Capital
Leases(c) 172,264 175,969 177,418 197,404 208,924
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- --------------------------------------------------------------------------------
Quarter Ended(a)
--------------------------------------------------
1995 March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------
Operating Revenues...... $601,194 $525,147 $638,392 $621,374
======== ======== ======== ========
Operating Income........ $ 96,191 $ 65,867 $ 88,012 $ 73,956
======== ======== ======== ========
Net Income.............. $ 65,877 $ 38,089 $ 60,462 $ 40,788
======== ======== ======== ========
1994
- --------------------------------------------------------------------------------
Operating Revenues...... $619,815 $551,135 $598,706 $558,396
======== ======== ======== ========
Operating Income........ $ 90,259 $ 59,289 $ 74,771 $ 62,629
======== ======== ======== ========
Net Income.............. $ 68,590 $ 39,162 $ 50,191 $ 40,345
======== ======== ======== ========
(a)Reclassifications of prior data have been made to conform with the current
presentation.
(b)Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares by $47.7
million.
(c)Includes portion due within one year.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
STATISTICS
- -------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31)
- -------------------------------------------------------------------------
1995 $6,389,190 26,366 8,519 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
1992 6,100,682 25,809 8,501 1,075,425 3,028
1991 5,986,271 24,992 8,435 1,069,912 3,364