Exhibit 13.2
1994
ANNUAL REPORT
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
--------------------------------------------------------
1994 Annual Report
The Connecticut Light and Power Company and Subsidiaries
Index
Contents Page
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Consolidated Balance Sheets.......................... 1-2
Consolidated Statements of Income.................... 3
Consolidated Statements of Cash Flows................ 4
Consolidated Statements of Common Stockholder's Equity 5
Notes to Consolidated Financial Statements........... 6-30
Report of Independent Public Accountants............. 31
Management's Discussion and Analysis of Financial
Condition and Results of Operations................ 32-39
Selected Financial Data.............................. 40
Statements of Quarterly Financial Data............... 40
Statistics........................................... 41
Preferred Stockholder and Bondholder Information..... Back Cover
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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At December 31, 1994 1993
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(Thousands of Dollars)
ASSETS
------
Utility Plant, at original cost:
Electric................................................ $6,063,179 $5,936,346
Less: Accumulated provision for depreciation......... 2,194,314 2,010,962
----------- -----------
3,868,865 3,925,384
Construction work in progress........................... 99,993 121,177
Nuclear fuel, net....................................... 164,795 156,878
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Total net utility plant............................. 4,133,653 4,203,439
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Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994 and
at cost in 1993 (Note 12)<F12>......................... 171,950 147,657
Investments in regional nuclear generating
companies, at equity................................... 54,952 53,910
Other, at cost.......................................... 14,742 14,191
----------- -----------
241,644 215,758
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Current Assets:
Cash.................................................... 2,017 2,340
Receivables, less accumulated provision for
uncollectible accounts of $12,778,000 in 1994
and $10,816,000 in 1993................................ 192,926 210,805
Accounts receivable from affiliated companies........... 9,367 29,687
Accrued utility revenues................................ 90,475 97,662
Fuel, materials, and supplies, at average cost.......... 64,003 60,247
Prepayments and other................................... 54,215 43,682
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413,003 444,423
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Deferred Charges:
Regulatory assets (Note 1H)<F1H>........................ 1,410,334 1,517,943
Unamortized debt expense................................ 8,396 8,971
Other................................................... 10,427 6,871
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1,429,157 1,533,785
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Total Assets........................................ $6,217,457 $6,397,405
=========== ===========
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, 1994 1993
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(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock--$10 par value. Authorized
24,500,000 shares; outstanding 12,222,930
shares in 1994 and 1993.............................. $ 122,229 $ 122,229
Capital surplus, paid in.............................. 632,117 630,271
Retained earnings..................................... 765,724 750,719
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Total common stockholder's equity............ 1,520,070 1,503,219
Cumulative preferred stock--
$50 par value - authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1994 and in 1993
$25 par value - authorized 8,000,000 shares;
outstanding 5,000,000 shares in 1994 and in 1993
Not subject to mandatory redemption (Note 5)<F5>.... 166,200 166,200
Subject to mandatory redemption (Note 6)<F6>........ 226,250 230,000
Long-term debt (Note 7)<F7>........................... 1,815,579 1,743,260
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Total capitalization......................... 3,728,099 3,642,679
----------- -----------
Obligations Under Capital Leases........................ 120,268 121,892
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Current Liabilities:
Notes payable to banks................................ 76,000 95,000
Notes payable to affiliated company................... 92,750 1,250
Commercial paper...................................... 10,000 -
Long-term debt and preferred stock--current
portion.............................................. 11,861 314,020
Obligations under capital leases--current
portion.............................................. 55,701 55,526
Accounts payable...................................... 102,837 117,858
Accounts payable to affiliated companies.............. 43,033 52,179
Accrued taxes......................................... 26,413 36,139
Accrued interest...................................... 30,682 29,669
Other................................................. 22,828 32,287
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472,105 733,928
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Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>...... 1,544,021 1,575,965
Accumulated deferred investment tax credits........... 150,087 154,701
Deferred contract obligation--YAEC (Note 3)<F3>....... 100,003 84,526
Other................................................. 102,874 83,714
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1,896,985 1,898,906
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Commitments and Contingencies (Note 10)<F10>
Total Capitalization and Liabilities......... $6,217,457 $6,397,405
=========== ===========
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, 1994 1993 1992
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(Thousands of Dollars)
Operating Revenues................................ $2,328,052 $2,366,050 $2,316,451
----------- ----------- -----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power.... 568,394 657,121 598,287
Other........................................ 593,851 641,402 605,675
Maintenance..................................... 207,003 180,403 197,460
Depreciation.................................... 231,155 219,776 209,884
Amortization of regulatory assets, net.......... 77,384 112,353 73,456
Federal and state income taxes (Note 8)<F8>..... 195,038 144,547 172,236
Taxes other than income taxes................... 173,068 170,353 171,642
----------- ----------- -----------
Total operating expenses.................. 2,045,893 2,125,955 2,028,640
----------- ----------- -----------
Operating Income.................................. 282,159 240,095 287,811
----------- ----------- -----------
Other Income:
Deferred nuclear plants return--other
funds (Note 1K)<F1K>.......................... 13,373 23,537 35,396
Equity in earnings of regional nuclear
generating companies.......................... 7,453 6,193 8,014
Other, net...................................... 5,136 (1,044) 6,964
Income taxes--credit............................ 9,037 4,859 11,171
----------- ----------- -----------
Other income, net......................... 34,999 33,545 61,545
----------- ----------- -----------
Income before interest charges............ 317,158 273,640 349,356
----------- ----------- -----------
Interest Charges:
Interest on long-term debt...................... 119,927 134,263 151,314
Other interest.................................. 6,378 9,654 4,205
Deferred nuclear plants return--borrowed
funds (Note 1K)<F1K>.......................... (7,435) (13,979) (12,877)
----------- ----------- -----------
Interest charges, net..................... 118,870 129,938 142,642
----------- ----------- -----------
Income before cumulative effect of
accounting change............................... 198,288 143,702 206,714
Cumulative effect of accounting change
(Note 1B)<F1B>.................................. - 47,747 -
----------- ----------- -----------
Net Income........................................ $ 198,288 $ 191,449 $ 206,714
=========== =========== ===========
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, 1994 1993 1992
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(Thousands of Dollars)
Cash Flows From Operating Activities:
Net Income................................................ $ 198,288 $ 191,449 $ 206,714
Adjustments to reconcile to net cash
from operating activities:
Depreciation............................................ 231,155 219,776 209,884
Deferred income taxes and investment tax credits, net... 37,664 (20,188) 72,138
Deferred nuclear plants return, net of amortization..... 82,651 58,740 10,071
Recoverable energy costs, net of amortization........... 3,975 125,579 (64,138)
Deferred demand-side management, net of amortization.... (4,691) (23,955) (31,989)
Other sources of cash................................... 35,464 80,831 26,430
Other uses of cash...................................... (41,518) (23,544) (34,589)
Changes in working capital:
Receivables and accrued utility revenues................ 45,386 (9,370) 245
Fuel, materials, and supplies........................... (3,756) 11,951 1,296
Accounts payable........................................ (24,167) 5,433 (18,067)
Accrued taxes........................................... (9,726) (82,018) 15,344
Other working capital (excludes cash)................... (18,403) 9,754 7,154
----------- ----------- -----------
Net cash flows from operating activities.................... 532,322 544,438 400,493
----------- ----------- -----------
Cash Flows From Financing Activities:
Issuance of long-term debt................................ 535,000 740,500 491,000
Issuance of preferred stock............................... - 80,000 75,000
Net increase (decrease) in short-term debt................ 82,500 (109,490) 15,240
Reacquisitions and retirements of long-term debt.......... (774,020) (771,973) (431,232)
Reacquisitions and retirements of preferred stock......... - (114,996) (91,891)
Cash dividends on preferred stock......................... (23,895) (29,182) (31,977)
Cash dividends on common stock............................ (159,388) (160,365) (164,277)
----------- ----------- -----------
Net cash flows used for financing activities................ (339,803) (365,506) (138,137)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................. (149,889) (149,308) (225,901)
Nuclear fuel............................................ (20,905) (13,658) 3,139
----------- ----------- -----------
Net cash flows used for investments in plant.............. (170,794) (162,966) (222,762)
Other investment activities, net.......................... (22,048) (25,787) (32,181)
----------- ----------- -----------
Net cash flows used for investments......................... (192,842) (188,753) (254,943)
----------- ----------- -----------
Net (Decrease) Increase In Cash For The Period.............. (323) (9,821) 7,413
Cash - beginning of period.................................. 2,340 12,161 4,748
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Cash - end of period........................................ $ 2,017 $ 2,340 $ 12,161
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized during construction.. $ 115,120 $ 130,592 $ 143,957
=========== =========== ===========
Income taxes.............................................. $ 161,513 $ 149,056 $ 95,199
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust.................................... $ 52,353 $ 40,140 $ 30,948
=========== =========== ===========
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
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(Thousands of Dollars)
Balance at January 1, 1992.......... $122,229 $637,202 $ 738,993 $1,498,424
Net income for 1992............. 206,714 206,714
Cash dividends on preferred
stock......................... (31,977) (31,977)
Cash dividends on common stock.. (164,277) (164,277)
Loss on the retirement of
preferred stock............... (636) (636)
Capital stock expenses, net..... (2,351) (2,351)
--------- --------- ---------- -----------
Balance at December 31, 1992........ 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
========= ========= ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt
agreements.
At December 31, 1994, these restrictions totaled approximately $540 million.
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A>A. PRINCIPLES OF CONSOLIDATION
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).
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. Commencing June 29, 1992,
North Atlantic Energy Service Corporation (NAESCO) began acting 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.
<F1B>B. CHANGE IN ACCOUNTING FOR PROPERTY TAXES
CL&P adopted a one-time change in the method of accounting for
municipal property tax expense for its Connecticut properties. Most
municipalities in Connecticut assess property values as of October 1.
Before January 1, 1993, CL&P accrued Connecticut property tax expense
over the period October 1 through September 30 based on the lien-date
method. In the first quarter of 1993, CL&P changed its method of
accounting for Connecticut municipal property taxes to recognize the
expense from July 1 through June 30, to match the payments and the
services provided by the municipalities. This one-time change
increased earnings for common shares by approximately $47.7 million in
1993.
<F1C>C. RECLASSIFICATIONS
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
<F1D>D. 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 to the
participants substantially on the basis of their 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 - Purchased Power Arrangements."
The YAEC 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 percent joint-ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of
December 31, 1994 and 1993, plant-in-service included approximately
$370.9 million and $332 million, respectively, and the accumulated
provision for depreciation included approximately $135.0 million and
$130.8 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 percent joint-ownership interest in
Millstone 2, an 870-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $680.5 million
and $676 million, respectively, and the accumulated provision for
depreciation included approximately $175.2 million and $151.5 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,
1994 and 1993, plant-in-service included approximately $1.9 billion and
the accumulated provision for depreciation included approximately
$418.5 million and $366.6 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: CL&P has a 4.06 percent joint-ownership interest in
Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $173.2 million
and $173.4 million, respectively, and the accumulated provision for
depreciation included approximately $20.1 million and $17.7 million,
respectively, for CL&P's share of Seabrook 1. CL&P's share of
Seabrook 1 expenses is included in the corresponding operating expenses
on the accompanying Consolidated Statements of Income.
<F1E>E. 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. For
nuclear production plants, the costs of removal, less salvage, that
have been funded through external decommissioning trusts will be paid
with funds from the trusts and charged to the accumulated reserve for
decommissioning included in the accumulated provision for depreciation
over the expected service life of the plants. See Note 3, "Nuclear
Decommissioning," for additional information.
The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.9 percent in
1994, 3.8 percent in 1993, and 3.7 percent in 1992.
<F1F>F. 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).
<F1G>G. REVENUES
Other than 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. 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.
<F1H>H. REGULATORY ACCOUNTING
CL&P follows accounting policies that reflect the impact of the rate
treatment of certain events or transactions that differ from generally
accepted accounting principles for those events or transactions
followed by nonregulated enterprises. Under regulatory accounting,
assuming that future revenues are expected to be sufficient to provide
recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an
asset, or create a liability. If the economic entity no longer comes
under the jurisdiction of a regulator or external forces, such as a
move to a competitive environment, effectively limiting the influence
of cost-of-service based rate regulation, the entity may be forced to
abandon regulatory accounting, requiring a reexamination and potential
write-off of net regulatory assets. CL&P continues to be subject to
cost-of-service based rate regulation. Based on current regulation,
and recent regulatory decisions regarding competition in the company's
market, CL&P believes that its use of regulatory accounting is still
appropriate.
The components of regulatory assets are as follows:
At December 31, 1994 1993
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(Thousands of Dollars)
Income taxes, net (Note 1I) $ 949,134 $1,026,046
Deferred demand-side-management costs (Note 1J) 116,133 111,442
Deferred costs-nuclear plants (Note 1K) 101,632 185,909
Unrecovered contract obligation-YAEC (Note 3) 100,003 84,526
Recoverable energy costs, net (Note 1L) 61,040 65,591
Cogeneration costs (Note 1N) 36,821 -
Other 45,571 44,429
-------- --------
$1,410,334 $1,517,943
========== ==========
<F1I>I. INCOME TAXES
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial statements
and the periods in which they affect the determination of income
subject to tax) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 8,
"Income Tax Expense," for the components of income tax expenses.
In 1992, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income
tax accounting standards. The company adopted SFAS 109, on a
prospective basis, during the first quarter of 1993, and increased the
net deferred tax obligation by $1.0 billion at that time. As it is
probable that the increase in deferred tax liabilities will be
recovered from customers through rates, CL&P also established a
regulatory asset.
The tax effect of temporary differences which give rise to the
accumulated deferred tax obligation are as follows:
At December 31, 1994 1993
----------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ........ $1,063,823 $1,049,849
Regulatory assets - income tax gross up 402,685 434,894
Other ................................ 77,513 91,222
---------- ----------
$1,544,021 $1,575,965
========== ==========
<F1J>J. DEMAND-SIDE-MANAGEMENT COSTS (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). These costs are being recovered over
periods ranging from four to eight years. On October 31, 1994, CL&P
filed its 1995 CAM for 1995 DSM costs and programs. The filing
proposes expenditures of $36.7 million with recovery over four years
and a zero CAM rate.
<F1K>K. DEFERRED COSTS - NUCLEAR PLANTS
CL&P is phasing into rates the recoverable portions of its investments
in Millstone 3 and Seabrook 1. CL&P is deferring costs as part of its
phase-in plans. Both plans are in compliance with SFAS No. 92,
Regulated Enterprises - Accounting for Phase-in Plans.
As allowed by the DPUC, effective January 1, 1995, CL&P placed into
rate base its allowed investments in Millstone 3 and Seabrook 1 and is
recovering deferrals and carrying charges on these units. As of
December 31, 1994, $448.5 million of the deferred return, including
carrying charges, has been recovered, and $101.6 million of the
deferred return to date, plus carrying charges, remains to be
recovered. Recovery will be completed by December 31, 1995 and
August 31, 1996 for Millstone 3 and Seabrook 1, respectively.
<F1L>L. 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 has begun to recover these costs.
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
retroactive review and appropriate adjustment. 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.
In the past two GUAC proceedings before the DPUC, the DPUC determined
that CL&P overrecovered its fuel costs and offset the amount of the
overrecovery against the GUAC balance. This has resulted in
disallowances of GUAC recovery of $7.9 million for the 1992-1993 GUAC
period and $7.8 million for the 1993-1994 GUAC period. CL&P has
appealed the first decision and will appeal the second decision.
At December 31, 1994, CL&P's recoverable energy costs were $61.0
million, including D&D assessments of $37.4 million.
For additional information see Note 10B, "Commitments and
Contingencies-Nuclear Performance."
<F1M>M. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. 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, 1994, fees due to the DOE
for the disposal of prior-period fuel were approximately $141.7
million, including interest costs of $75.2 million. As of December 31,
1994, all fees had been collected through rates.
<F1N>N. COGENERATION COSTS
CL&P, with the approval of the DPUC, began deferring certain
cogeneration costs for future recovery beginning in 1994. At December
31, 1994, CL&P had deferred approximately $36.8 million in cogeneration
costs. CL&P will begin recovery of these deferrals over five years
beginning July 1, 1996.
<F1O>O. 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 as a reduction of 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 or
interest-rate caps will be deferred until realized. For further
information on derivatives, see Note 11, "Derivative Financial
Instruments."
<F2>2. LEASES
CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital
lease agreement to finance up to $530 million of nuclear fuel for
Millstone 1 and 2 and their shares of the nuclear fuel for Millstone 3.
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:
Capital Operating
Year Leases Leases
---- ------------ ----------
1994 ............ $60,975,000 $24,192,000
1993 ............ 76,606,000 24,355,000
1992 ............ 61,795,000 26,919,000
Interest included in capital lease rental payments was $10,228,000 in 1994,
$11,298,000 in 1993, and $14,782,000 in 1992.
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, 1994, are as follows:
Capital Operating
Year Leases Leases
---- ------------ ----------
(Thousands of Dollars)
1995 $ 2,700 .....$ 19,500
1996 2,700 ........18,000
1997 2,700 ........16,500
1998 2,700 ........12,100
1999 2,700 ........10,400
After 1999 42,100 .... 61,900
---------- ---------
Future minimum lease payments 55,600 ......$138,400
========
Less amount representing interest 35,900
--------
Present value of future minimum
lease payments for other than
nuclear fuel................. 19,700
Present value of future nuclear
fuel lease payments.......... 156,300
---------
Total .............. $176,000
========
<F3>3. NUCLEAR DECOMMISSIONING
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, which is currently under review by the New
Hampshire Decommissioning Finance Committee, 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, technology, and inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1
and 2, in year-end 1994 dollars, is $332.8 million and $267.3 million,
respectively. CL&P's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 (utilizing the currently
approved decommissioning study), in year-end 1994 dollars, is $237.5
million and $15.5 million, respectively. These estimated costs have been
levelized and assume after-tax earnings on the Millstone and Seabrook 1
decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future
escalation rates in decommissioning costs for the Millstone units and for
Seabrook 1 are assumed. 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 $25.6 million in 1994 and $21.9 million in 1993 and 1992.
Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation on the Consolidated Balance Sheets.
At December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $209.7 million. See "Nuclear Decommissioning"
in Management's Discussion and Analysis for a discussion of changes being
considered by the FASB related to accounting for decommissioning costs.
CL&P has established independent decommissioning trusts 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, 1994, CL&P has collected, through rates, $173.4 million,
toward the future decommissioning costs of its share of the Millstone
units, of which $135.9 million has been transferred to external
decommissioning trusts. As of December 31, 1994, CL&P has paid
approximately $1.2 million into Seabrook 1's decommissioning trust.
Earnings on the decommissioning trusts increase the decommissioning trust
balance and the accumulated reserve for decommissioning. Due to CL&P's
adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain
Investments in Debt and Equity Securities, unrealized gains and losses
associated with the decommissioning trusts also impact the balance of the
trusts 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. 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. Because allowances for
decommissioning have increased significantly in recent years, customers in
future years may need to increase their payments to offset the effects of
any insufficient rate recoveries in previous years.
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. The estimated costs, in year-end 1994 dollars, of
decommissioning CL&P's ownership share of CY, MY, and VY are $124.9
million, $40.6 million, and $31.3 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 CL&P's cost of power.
YAEC has begun component removal activities related to the decommissioning
of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain
FERC authorization to collect the closing and decommissioning costs and to
recover the remaining investment in the YAEC nuclear power plant, over the
remaining period of the plant's Nuclear Regulatory Commission (NRC)
operating license. The bulk of these costs has been agreed to by the YAEC
joint owners and approved as a settlement, by FERC. In October 1994, YAEC
submitted a revised decommissioning cost estimate as part of its
decommissioning plan with the NRC. Following the receipt of NRC approval,
this estimate will be filed with the FERC. The revised estimate increased
CL&P's ownership share of decommissioning YAEC's nuclear facility by
approximately $23.1 million in January 1, 1994 dollars. At December 31,
1994, the estimated remaining costs including decommissioning, amounted to
$408.2 million, of which CL&P's share was approximately $100 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 a corresponding obligation, on its
Consolidated Balance Sheets.
<F4>4. SHORT-TERM DEBT
The system companies have various revolving credit lines, totalling $485
million. NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company
(RRR) have established a revolving-credit facility with a group of
16 banks. Under this facility, the participating companies may borrow up
to an aggregate of $360 million. Individual borrowing limits as of January
1, 1995 were $150 million for NU, $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 0.20 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 0.135 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, 1994 and 1993, there were $30.0 million
and $22.5 million of borrowings, respectively, under the facility, all of
which had been borrowed by other system companies. At December 31, 1993,
CL&P had $5 million in borrowings outstanding under this facility.
The weighted average interest rates on notes payable to banks and
commercial paper outstanding on December 31, 1994 were 6.2 percent and 6.4
percent, respectively. The weighted average interest rate on notes payable
to banks outstanding on December 31, 1993 was 3.3 percent.
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.
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. Investing and borrowing subsidiaries receive or pay
interest based on the average daily Federal Funds rate. At December 31,
1994 and 1993, CL&P had $92.8 million and $1.3 million, respectively, of
borrowings outstanding from the Pool. The interest rate on borrowings from
the Pool on December 31, 1994 and 1993 were 4.9 percent and 2.9 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 the company 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.
<F5>5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1994 Outstanding
Redemption December 31, December
31,
-----------------------------
Description Price 1994 1994 1993 1992
-------------------------------------------------------------------------------------
(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
$3.80 Series J of 1971 - - - - 20,000
$4.48 Series H of 1970 - - - - 15,000
$4.48 Series I of 1970 - - - - 20,000
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
7.60% Series of 1971 - - - - 9,996
1989 Adjustable Rate
DARTS $25.00 2,000,000 50,000 50,000 50,000
------ ------ ------
Total preferred stock
not subject to
mandatory redemption $166,200 $166,200 $231,196
======== ======== ========
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 dividends to the date of redemption.
As of January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P, issued
$100 million of 9.3 percent cumulative Monthly Income Preferred Securities
to help finance the expected retirement of $125 million of CL&P preferred
stock.
<F6>6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1994 Outstanding December 31,
Redemption December 31, ----------------------------
Description Price* 1994 1994 1993 1992
-------------------------------------------------------------------------------------
(Thousands of Dollars)
9.10% Series of 1987 - - $ - $ - $ 50,000
9.00% Series of 1989 $26.50 3,000,000 75,000 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 -
-------- -------- --------
230,000 230,000 200,000
Less preferred stock to be
redeemed within one year 3,750 - 2,500
-------- -------- --------
Total preferred stock subject
to mandatory redemption $226,250 $230,000 $197,500
======== ======== ========
*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 Shares Reacquired
Sinking-Fund ------------------------------
Series Requirement 1994 1993 1992
------------------------------------------------------------------------------------
(Thousands of Dollars)
$5.52 Series L of 1975 $ - - - 38,524
11.52% Series of 1975 - - - 19,318
10.48% Series of 1980 - - - 280,000
9.10% Series of 1987 - - 2,000,000 -
9.00% Series of 1989 (1) 3,750 - - -
7.23% Series of 1992 (2) 3,750 - - -
5.30% Series of 1993 (3) 16,000 - - -
(1)Sinking fund requirements commence October 1, 1995.
(2)Sinking fund requirements commence September 1, 1998.
(3)Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1995 through 1999, aggregate approximately $3,750,000
in 1995, 1996, and 1997, $7,500,000 in 1998, and $23,500,000 in 1999. 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.
<F7>7. LONG-TERM DEBT
Details of long-term debt outstanding are: December 31,
------------------------
1994 1993
---------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
Series 1964 due 1994 $ - 12,000
Series WW due 1994 - 170,000
Series 1967 due 1997 - 20,000
Series S due 1997 - 30,000
Series UU due 1997 200,000 200,000
Series U due 1998 - 40,000
Series 1968 due 1998 - 25,000
Series T due 1998 20,000 20,000
Series 1968 due 1998 - 10,000
Series VV due 1999 100,000 100,000
Series A due 1999 140,000 -
Series XX due 2000 200,000 200,000
Series X due 2001 - 30,000
Series 1971 due 2001 - 30,000
Series 1972 due 2002 - 35,000
Series Y due 2002 - 50,000
Series Z due 2003 - 50,000
Series 1973 due 2003 - 40,000
Series B due 2004 140,000 -
Series QQ due 2018 - 75,000
Series RR due 2019 - 75,000
Series SS due 2019 - 75,000
Series TT due 2019 20,000 20,000
Series YY due 2023 100,000 100,000
Series C due 2024 115,000 -
Series D due 2024 140,000 -
Series ZZ due 2025 125,000 125,000
---------- ----------
Total First Mortgage Bonds 1,300,000 1,532,000
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 1M) 141,694 136,125
Other 28,398 35,417
Less amounts due within one year 8,111 314,020
Unamortized premium and discount, net (8,302) (8,162)
---------- ----------
Long-term debt, net $1,815,579 $1,743,260
========== ==========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
approximately: $8,111,000, $9,372,000, $210,828,000, $20,011,000, and
$240,005,000, respectively. In addition, there are annual one-percent
sinking-and improvement-fund requirements, currently amounting to
$13,000,000 for 1995, 1996 and 1997, $11,000,000 for 1998, and $10,800,000
for 1999. 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, 1994 and 1993, the
company has secured $315.5 million of pollution control notes with second
mortgage liens on Millstone 1, junior to the liens of its first mortgage
bond indenture. The average effective interest rates on the variable-rate
pollution control notes ranged from 2.7 percent to 3.3 percent for 1994 and
2.4 percent to 2.7 percent for 1993.
<F8>8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Current income taxes:
Federal $108,371 $115,403 $ 61,773
State 39,966 44,473 27,153
-------- -------- --------
Total current 148,337 159,876 88,926
-------- -------- --------
Deferred income taxes, net:
Federal 44,180 3,808 60,788
State 842 (12,987) 11,833
-------- -------- --------
Total deferred 45,022 (9,179) 72,621
-------- -------- --------
Investment tax credits, net (7,358) (11,009) (6,230)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses $195,038 $144,547 $172,236
Income taxes associated with the
amortization of deferred nuclear plants
return - borrowed funds - - (15,157)
Income taxes associated with allowance for
funds used during construction (AFUDC) and
deferred nuclear plants return -
borrowed funds - - 9,409
Other income taxes - credit (9,037) (4,859) (11,171)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel, settlement
credits, and disposal costs $38,874 $42,663 $43,715
Demand-side management 203 9,156 13,506
Postretirement benefits accrual (1,019) (2,579) -
Energy adjustment clauses 14,465 (52,189) 12,627
AFUDC and deferred nuclear plants return, net (18,483) (13,741) (5,748)
Early retirement program 671 (3,355) 3,988
Pension accrual 742 3,553 885
Settlement, canceled independent power plants - - 7,251
Loss on bond redemption 9,183 8,145 10
Other 386 (832) (3,613)
------- ------- --------
Deferred income taxes, net $45,022 ($9,179) $72,621
======= ======== ========
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, 1994 1993 (Note 1I) 1992
------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at 35 percent of pretax
income for 1994 and 1993 and at 34 percent for 1992 $134,501 $115,898 $123,091
Tax effect of differences:
Depreciation differences 18,602 19,264 15,826
Deferred nuclear plants return - other funds (4,681) (8,294) (12,035)
Amortization of deferred nuclear plants return -
other funds 19,755 18,648 14,511
Property tax differences 5,286 (12,320) (732)
Investment tax credit amortization (7,358) (11,009) (6,230)
State income taxes, net of federal
benefit 26,526 20,466 25,730
Adjustment for prior years taxes (2,706) (2,330) (3,500)
Other, net (3,924) (635) (1,344)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
9. EMPLOYMENT BENEFITS
<F9A>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
charged to utility plant, approximated $(2.3) million in 1994, $7.6
million in 1993, and ($1.7) million in 1992. The company's pension
costs for 1994 and 1993 include approximately $4.8 million and $13.1
million, respectively, related to work-force reduction programs.
Currently, the company funds annually an amount at least equal to that
which will satisfy the requirements of the Employment 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, 1994 1993 1992
--------------------------------------------------------------------------
(Thousands of Dollars)
Service cost $13,072 $21,907 $10,614
Interest cost 36,103 35,055 36,308
Return on plan assets 1,020 (80,615) (40,377)
Net amortization (52,536) 31,254 (8,206)
------- -------- --------
Net pension (income)/cos ($2,341) $7,601 ($1,661)
======= ======= =======
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------
(Thousands of Dollars)
Discount rate 7.75% 8.00% 8.50%
Expected long term rate
of return 8.50 8.50 9.00
Compensation/progression rate 4.75 5.00 6.75
The following table represents the plan's funded status reconciled
to the Consolidated Balance Sheets:
At December 31, 1994 1993
-----------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $374,109,000 of vested benefits
at December 31, 1994 and $380,238,000
of vested benefits at December 31, 1993 $401,889 $409,136
======== ========
Projected benefit obligation $471,079 $484,396
Market value of plan assets 568,294 604,320
-------- --------
Market value in excess of projected
benefit obligation 97,215 119,924
Unrecognized transition amount (9,204) (10,125)
Unrecognized prior service costs 1,420 1,547
Unrecognized net (gain) (88,845) (113,100)
--------- ---------
Prepaid/(Accrued) pension liability $586 ($1,754)
========= =========
The following actuarial assumptions were used in calculating the Plan's
year-end funded status:
At December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Discount rate ............ 8.25% 7.75%
Compensation/progression rate 5.00 4.75
>F9B>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. These benefits are available for employees leaving
the company who are otherwise eligible to retire and have met specified
service requirements. Effective January 1, 1993, the company adopted
SFAS 106, Employer's Accounting for Postretirement Benefits Other Than
Pensions on a prospective basis. CL&P's direct portion of health care
and life insurance costs, part of which were deferred or charged to
utility plant, approximated $22.3 million in 1994, $23.2 million in
1993, and $8.8 million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the company's transition obligation upon the adoption of
SFAS 106. As allowed by SFAS 106, the company is amortizing its
transition obligation of approximately $148 million over a 20-year
period. 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.
During 1994, the company funded through external trusts an amount
equivalent to total SFAS 106 benefits paid for 1994. During 1993, the
company did not fund SFAS 106 postretirement costs through external
trusts. The company expects to fund, annually, total SFAS 106 costs,
including benefits paid amounts, once they 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 following table represents the plan's funded status reconciled to
the Consolidated Balance Sheet:
At December 31, 1994 1993
--------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees .......................... $129,111 $119,520
Fully eligible active employees ... 241 288
Active employees not eligible to retire 25,203 29,270
--------- ---------
Total accumulated postretirement
benefit obligation 154,555 149,078
Market value of plan assets ....... 167 -
--------- ---------
Accumulated postretirement benefit obligation
in excess of plan assets ......... (154,388) (149,078)
Unrecognized transition amount ..... 132,194 139,539
Unrecognized net loss (gain) ...... 192 (2,591)
---------- ---------
Accrued postretirement benefit liability $(22,002) $(12,130)
======== ========
-------------------------------------------------------------
The components of health care and life insurance costs are:
For the Years Ended December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Service cost ....................... $ 2,371 $ 3,397
Interest cost ...................... 12,157 12,091
Return on plan assets ............. 2 -
Net amortization ................... 7,774 7,682
------- -------
Net health care and life insurance costs $22,304 $23,170
======= =======
The following actuarial assumptions were used in calculating the plan's
year end funded status:
At December 31, 1994 1993
------------------------------------------------------------
Discount rate ...................... 8.00% 7.75%
Long-term rate of return - health
assets, net of tax................ 5.00 5.00
Long-term rate of return - life assets 8.50 8.50
Health care cost trend rate (a) .... 10.20 11.10
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 percent by 2002.
The effect of increasing the assumed health care cost trend rates by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by $8.6
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$763,000. The trust holding the plan assets is subject to federal
income taxes at a 35-percent tax rate.
CL&P has received regulatory approval to defer SFAS 106 costs in excess
of costs incurred on a pay-as-you-go basis. Deferral of such costs is
permitted since it is expected that the period of recovery of deferred
costs will be within the time frame established by the applicable
accounting requirements.
10. COMMITMENTS AND CONTINGENCIES
<F10A>A.CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision.
Actual construction expenditures may vary from estimates due to factors
such as revised load estimates, inflation, revised nuclear safety
regulations, delays, difficulties in the licensing process, the
availability and cost of capital, and the granting of timely and
adequate rate relief by regulatory commissions, as well as actions by
other regulatory bodies.
CL&P currently forecasts construction expenditures (including AFUDC) of
approximately $716.9 million for the years 1995-1999, including $147.7
million for 1995. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $257.4 million for the years 1995-1999, including $46.8
million for 1995. See Note 2, "Leases," for additional information
about the financing of nuclear fuel.
<F10B>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. The Office of Consumer Counsel (OCC)
appealed decisions favorable to the company in two dockets. For the
one appeal decided, which related to a procedural issue, the OCC
prevailed and the case has been remanded to the DPUC for further
proceedings. The exposure under these two dockets is approximately $66
million. The DPUC has suspended a third docket, pending the outcome of
one of the appeals. The exposure under this remaining docket is $26
million. Management believes that its actions with respect to these
outages have been prudent, and it does not expect the outcome of the
appeals to result in material disallowances.
In October 1994, Millstone 2 began a planned refueling and maintenance
outage that was originally scheduled for 63 days. The outage has
encountered several unexpected difficulties which have lengthened the
duration of the outage. The magnitude of the schedule impact is
currently under review, but the unit is not expected to return to
service before April 1995. CL&P expects that replacement power costs
in the range of $7 million per month will be attributable to the
extension of the outage. Recovery of the costs related to this outage
is subject to scrutiny by the DPUC.
<F10C>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.
Changing environmental requirements could hinder the construction of
new generating units, transmission and distribution lines, substations,
and other facilities. The cumulative long-term, economic 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 is, based upon
information currently available, its estimated environmental
remediation costs for waste disposal sites for which it's expected to
bear legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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, 1994, the 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 million. However, in the event that it becomes
necessary to effect environmental remedies that are currently not
considered probable, it is reasonably possible that the upper limit of
CL&P's environmental liability range could increase to approximately
$10 million.
CL&P cannot estimate the potential liability for future claims 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.
<F10D>D.NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first
$200 million of liability would be provided by purchasing the maximum
amount of commercially available insurance. Additional coverage of up
to a total of $8.3 billion would be provided by an assessment of
$75.5 million per incident, levied on each of the 110 nuclear units
that are currently subject to the Secondary Financial Protection
Program in the United States, subject to a maximum assessment of
$10 million per incident per nuclear unit in any year. In addition, if
the sum of all public liability claims and legal costs arising from any
nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5 percent, up to
$3.8 million, or $415.3 million in total, for all 110 nuclear units.
The maximum assessment is to be adjusted at least every five years to
reflect inflationary changes. Based on CL&P's ownership interests in
Millstone 1, 2, and 3, and Seabrook 1, CL&P's maximum liability would
be $173.6 million per incident. In addition, through CL&P's 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.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences
with respect to CL&P's ownership interest in Millstone 1, 2, 3, and CY.
All companies insured with NML are subject to retroactive assessments
if losses exceed the accumulated funds available to NML. The maximum
potential assessment against CL&P with respect to losses arising during
the current policy year is approximately $13 million under the NML
primary property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) to cover: (1) certain extra costs incurred in obtaining
replacement power during prolonged accidental outages with respect to
CL&P's ownership interests in Millstone 1, 2, and 3, Seabrook 1, and
CY; and (2) the excess cost of repair, replacement, or decontamination
or premature decommissioning of utility property resulting from insured
occurrences with respect to CL&P's ownership interests in Millstone 1,
2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with NEIL
are subject to retroactive assessments if losses exceed the accumulated
funds available to NEIL. The maximum potential assessments against
CL&P, with respect to losses arising during current policy years are
approximately $7.5 million under the replacement power policies and
$32.2 million under the excess property damage, decontamination, and
decommissioning policies. Although CL&P has purchased the limits of
coverage currently available from the conventional nuclear insurance
pools, the cost of a nuclear incident could exceed available insurance
proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual
Atomic Energy Liability Underwriters, aggregating $200 million on an
industry basis for coverage of worker claims. All participating
reactor operators insured under this coverage are subject to
retrospective assessments of $3.1 million per reactor. The maximum
potential assessments against CL&P with respect to losses arising
during the current policy period are approximately $9.2 million.
<F10E>E.PURCHASED POWER ARRANGEMENTS
CL&P along with PSNH and WMECO purchase approximately 10 percent of
their electricity requirements pursuant to long-term contracts with the
Yankee companies. Under the terms of its agreements, CL&P pays its
ownership share (or entitlement share) of generating costs, which
include depreciation, operation and maintenance expenses, taxes, the
estimated cost of decommissioning, and a return on invested capital.
These costs are recorded as purchased power expense, and are recovered
through the company's rates. CL&P's total cost of purchases under
these contracts for the units that are operating amounted to $102.1
million in 1994, $112.3 million in 1993, and $103.2 million in 1992.
See Note 1D, "Summary Of Significant Accounting Policies - Investments
and Jointly Owned Electric Utility Plant" and Note 3, "Nuclear
Decommissioning" for more information on the Yankee companies.
CL&P has entered into various arrangements for the purchase of capacity
and energy from nonutility generators. These arrangements generally
have terms from 10 to 30 years, and require the company to purchase the
energy at specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of system electricity
requirements was met by nonutility generators. The total cost of the
company's purchases under these arrangements amounted to $277.4 million
in 1994, $279.8 million in 1993, and $267.3 million in 1992. These
costs are eventually recovered through the company's rates.
The estimated annual costs of CL&P's significant purchase power
arrangements are as follows:
1995 1996 1997 1998 1999
-------------------------------------------------------------
(Millions of Dollars)
Yankee companies ...... $110.2 $116.0 $103.7 $123.6 $118.1
Nonutility generators . 301.1 315.9 322.5 329.3 329.2
<F10F>F.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, its proportionate share of the
annual operation, maintenance, and capital costs of these facilities,
which are currently forecast to be $97.7 million for the years 1995-
1999, including $21.8 million for 1995.
<F11>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 1994, there was one outstanding
contract held by CL&P covering $340 million of variable-rate debt, with a
term of three years. The contract entitles 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. This contract is settled on a
quarterly basis. As of December 31, 1994, CL&P had a total of $340 million
in caps outstanding, with a positive mark-to-market position of
approximately $3.7 million.
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, 1994, CL&P had five
outstanding agreements with a total notional value of approximately $126
million, and a positive mark-to-market position of approximately $3.1
million. These swap agreements have been made with various financial
institutions, each of which are rated "A" or better by Standard and Poor's
rating group.
CL&P is exposed to credit risk on both the interest-rate caps and 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.
<F12>12.FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate
fair value.
SFAS 115 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. As a result of the adoption of SFAS 115, the investments
held in the company's nuclear decommissioning trusts decreased by
approximately $3.8 million as of December 31, 1994, with a corresponding
offset to the accumulated provision for depreciation. The $3.8 million
decrease 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, 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
-----------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ........ $ 166,200 $ 128,826
Preferred stock subject to
mandatory redemption ........ 230,000 240,400
Long-term debt -
First Mortgage Bonds ....... 1,532,000 1,580,396
Other long-term debt ....... 533,442 539,518
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
---------------------------------------------------------------------
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company and Subsidiaries (a Connecticut corporation
and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1994
and 1993, 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, 1994. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 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, 1994 and
1993, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
As explained in Note 1B and 9B to the financial statements, effective
January 1, 1993, The Connecticut Light and Power Company and Subsidiaries
changed its methods of accounting for property taxes and postretirement benefits
other than pensions.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
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 $198 million in 1994, as compared to approximately
$191 million in 1993. The 1994 net income is higher as a result of higher
retail kilowatt-hour sales, retail rate increases in 1993 and 1994, the deferral
of cogeneration expenses, and reduced operation and interest costs. These
increases were partially offset by lower revenues from wholesale sales. The
1993 net income was impacted by a number of one-time items, including the
cumulative effect of a one-time change in the accounting for municipal property
taxes, which resulted in an increase in 1993 net income of approximately
$48 million. In addition, 1993 net income reflected a decrease of approximately
$10 million for the costs of the company's employee-reduction program and a
decrease of approximately $15 million for disallowances in 1993 ordered in the
company's retail rate case. Net income before the effects of the change in
accounting for property taxes and other one-time items was approximately
$169 million in 1993.
In 1994, the company experienced its most significant retail kilowatt-hour sales
growth in six years, due in large part to the beginning of an economic recovery
in New England. Employment levels have risen, unemployment rates have fallen,
and personal income has increased. The company's 1994 retail sales rose by
3.4 percent over 1993. Overall, weather had little effect on sales volume, with
mild weather after mid-August offsetting unusually cold weather in January and
hot weather in late June and July.
In 1995, the company expects little retail sales growth over 1994, primarily
because of the effects of higher interest rates on the regional economy and
further cutbacks in defense-related industries in Connecticut. The company
estimates compounded annual sales growth of 1.4 percent from 1994 through 1999.
Competitive forces within the electric utility industry are continuing to
increase due to a variety of influences, including legislative and regulatory
actions, technological advances, and changes in consumer demand. The company
has developed, and is continuing to develop, a number of initiatives to retain
and continue to serve its existing customers and to expand its retail and
wholesale customer base.
The company believes the steps it is taking including a companywide process
reengineering effort, will have significant, positive effects, including reduced
operating costs and improved customer service, in the next few years. The
company also benefits from a diverse retail base with no significant dependence
on any one retail customer or industry.
CL&P continues to operate predominantly in a state-approved franchise territory
under traditional cost-of-service regulation. Retail wheeling, under which a
retail customer would be permitted to select an electricity supplier and require
the local electric utility to transmit the power to the customer's site, is not
required in Connecticut. In 1994, Connecticut regulators reviewed the
desirability of retail wheeling and determined that it was not in the best
interest of the state until new generating capacity is needed, which the NU
system projects to be in the year 2009. Connecticut regulators are presently
studying the potential restructuring of the electric utility industry. To date,
this regulatory proceeding has not progressed to the point where management can
assess the impact of any potential outcome on the company.
While retail competition is not required in the company's retail service
territory, competitive forces are nonetheless influencing retail pricing. These
forces include competition from alternate fuels such as natural gas, competition
from customer-owned generation, and regional competition for business retention
and expansion. The company's retail business group continues to work with
customers to address their concerns. The company has reached long-term rate
agreements with many new and existing customers to gain or retain their
business. In general, these rate agreements have terms of about five years.
Negotiated retail rate reductions for customers under rate agreements in effect
for 1994 amounted to approximately $11 million. Management believes that the
aggregate amount of negotiated retail rate reductions will increase in 1995 but
that the related agreements will continue to provide significant benefits to the
system, including the preservation of approximately 3 percent of retail
revenues.
The company is also working with its regulators to address the needs of
customers more widely. The company has a three-year rate agreement in effect
through June 1996. Management will continue to evaluate the use of agreements
of this type to keep retail rates competitive.
The company acts as both a buyer and a seller of electricity in the highly
competitive wholesale electricity market in the Northeastern United States
(Northeast). Many of the contracts signed in the late 1980s have or will expire
in the mid-1990s. Much of the revenue produced by such contracts has not been
replaced through new wholesale power arrangements. As a result, wholesale power
revenues fell to approximately $215 million in 1994 from approximately $268 mil-
lion in 1993. Unless prices on the wholesale market improve, revenues are
expected to fall still further in 1995 before stabilizing in late 1996 and 1997.
Wholesale sales are made primarily to investor-owned utilities and municipal or
cooperative electric systems in the Northeast. The company will be increasing
its efforts to increase wholesale sales through intensified marketing efforts.
The company's wholesale power marketing efforts benefit from the interconnection
of the NU system's transmission system with all of the major utilities in New
England, as well as with the three largest electric utilities in New York state.
RATE MATTERS
The company follows accounting principles that allow the rate treatment for
certain events or transactions to be reflected. These principles may differ
from the accounting principles followed by nonregulated enterprises. Regulators
may permit incurred costs, which would normally be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date. Regulatory assets at December 31, 1994 were
approximately $1.4 billion. Based on current regulation, the company believes
that its use of regulatory accounting is still appropriate.
See the "Notes to Consolidated Financial Statements," Note 1H, for further
details on regulatory accounting.
CL&P's retail rates increased by approximately $47 million, or 2.04 percent, in
July 1994, representing the second step of a three-year rate plan approved by
the Department of Public Utility Control (DPUC) in 1993. The third step of an
approximately $48 million, or 2.06 percent, increase will become effective in
July 1995. CL&P's 1993 rate decision has been appealed by the Connecticut
Office of Consumer Counsel and the city of Hartford. If this appeal prevails
there may be revenues subject to refund, however, management believes that the
possibility of the appeal prevailing is unlikely.
CL&P recovers from or refunds to customers certain fuel costs if the nuclear
units do not operate at a predetermined capacity factor (currently 72 percent)
through a Generation Utilization Adjustment Clause (GUAC). For the GUAC year
ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel costs and
reduced by approximately $8 million CL&P's overall request to recover
approximately $24 million of deferred GUAC costs. The company plans to appeal
the decision in court as it did for a similar DPUC decision on the 1992-1993
GUAC period, which also disallowed approximately $8 million of GUAC costs.
For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of
$50 million of GUAC fuel costs for projected nuclear performance below
72 percent. As of December 31, 1994, CL&P has reserved approximately
$13 million against this amount based on the methodology applied by the DPUC in
the previous GUAC decisions.
NUCLEAR PERFORMANCE
The composite capacity factor of the five nuclear generating units that the NU
system operates - including the Connecticut Yankee (CY) nuclear unit was
67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the
result of extended refueling and maintenance outages for Millstone 1,
Millstone 2, and Seabrook. CY, Seabrook, and Millstone 2 were also out of
service for varying lengths of time in 1994 because of unexpected technical and
operating difficulties. These difficulties included a manual shutdown of CY
when both service water headers were declared inoperable, an automatic trip from
100 percent power for Seabrook when a main steam isolation valve closed during
quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded
lower seal on a reactor coolant pump.
On October 1, 1994, Millstone 2 was shut down for a planned 63-day refueling and
maintenance outage. The outage has encountered several unexpected difficulties,
which will lengthen the duration of the outage. The outage extensions were
caused by a significant scope increase in service water system repairs as
identified through a comprehensive inspection plan and by a need for management
to exercise a deliberate approach to the conduct of work during the early
portions of the outage. The outage schedule is currently under review, but the
unit is not expected to return to service before April 1995. Replacement-power
costs attributable to the extension of the outage for CL&P are expected to be in
the range of approximately $7 million per month. These costs are deferred for
future recovery through the GUAC. (See rate matters above for further
discussion of the GUAC.) In addition, CL&P's operation and maintenance costs to
be incurred during the outage are estimated to be $42 million, an increase of
$15 million as a result of the extension. The recovery of these costs is
subject to prudence review in Connecticut.
The Nuclear Regulatory Commission's (NRC's) latest report for the Millstone
Station noted significant weaknesses in Millstone 2's operations and
maintenance. In a recent public statement in late 1994, a senior NRC official
expressed disappointment with the continued weaknesses in Millstone 2's
performance. The primary cause of the NRC's disappointment with Millstone 2's
performance appears to be that, despite significant management attention and
action over a period of years, the NRC does not believe it has seen enough
objective evidence of improvement in reducing procedural noncompliance and other
human errors. Management has acknowledged the basis for the NRC's concern with
Millstone 2 and has been devoting increased attention to resolving these issues.
Management and the NRC expect to continue to monitor closely the developments
at Millstone 2.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and then to meet the multitude of
environmental requirements it faces. NU has active auditing programs
addressing a variety of different regulatory requirements, including an
environmental auditing program to detect and remedy noncompliance with
environmental laws or regulations.
The company is potentially liable for environmental cleanup costs at a number of
sites both inside and outside its service territories. To date, the future
estimated environmental remediation liability has not been material with respect
to the earnings or financial position of the company. At December 31, 1994, the
liability recorded by the company, amounted to approximately $7 million. These
costs could rise to as much as $10 million if alternate remedies become
necessary.
The company expects that the implementation of the Clean Air Act Amendments of
1990 (CAAA) as they relate to sulfur dioxide emissions will require only modest
emissions reductions for the company. CL&P's exposure is minimal because of
the company's investment in nuclear energy in the 1970s and 1980s and the
burning of low-sulfur fuels. The CAAA requirements for emission limits for
nitrogen oxides will initially be met by capital expenditures of approximately
$10 million.
NUCLEAR DECOMMISSIONING
The company's estimated cost to decommission its shares of Millstone units 1, 2,
and 3 and Seabrook is approximately $853 million in year-end 1994 dollars. In
addition, the company's estimated cost to decommission its shares of the
regional nuclear generating units is approximately $197 million. These costs
are being recognized over the lives of the respective units and a portion of the
costs is being recovered through rates. Yankee Atomic Electric Company (YAEC)
has begun component removal activities related to the decommissioning of its
nuclear facility. The company's estimated obligation to YAEC has been recorded
on its Consolidated Balance Sheets. Management expects that the company will
continue to be allowed to recover these costs.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
this company, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. The Financial Accounting Standards Board is
currently reviewing the accounting for removal costs, including decommissioning.
If current electric utility industry accounting practices for such decom-
missioning costs are changed: (1) annual provisions for decommissioning could
increase, (2) the estimated costs for decommissioning could be recorded as a
liability rather than as accumulated depreciation, and (3) trust fund income
from the external decommissioning trust could be reported as investment income
rather than as a reduction to decommissioning expense.
See the "Notes to The Consolidated Financial Statements, " Note 3, for further
information on nuclear decommissioning.
PROPERTY TAXES
CY has a significant court appeal for municipal property tax assessments in the
town of Haddam, Connecticut. The central issue in this case is the fair market
value of utility property. CY believes that the assessments should be based on
a fair market value that approximates net book cost. This is the assessment
level that taxing authorities are predominantly using throughout Connecticut.
However, towns such Haddam advocate a method that approximates reproduction
costs.
CY's appeal is still pending. The company estimates that, for assessments in
towns such as Haddam, the change to the reproduction cost methodology could
result in property valuations approximately three times greater than values
approximating net book cost. If other towns in Connecticut adopt this
methodology, there could be a significant adverse impact on the company's future
results of operations and financial condition. However, the extent to which
other towns successfully adopt this methodology and any subsequent increase in
the company's property tax liability cannot be determined at this time.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $12 million in 1994, as
compared with 1993, primarily due to lower recovery of replacement-power costs
under the GUAC in 1994, partially offset by higher revenues from rate increases
and sales combined with lower cash operating expenses. Cash used for financing
activities was approximately $26 million lower in 1994, as compared with 1993,
primarily due to an increase in short-term debt, partially offset by higher net
reacquisitions and retirements of long-term debt. Cash used for investments
increased $4 million in 1994, as compared with 1993.
In 1994, the company refinanced approximately $535 million of debt. With
interest rates rising in mid-1994, much refinancing completed, and construction
needs remaining modest, the focus of CL&P's financing activities will shift
toward using the significant amount of cash generated by the company to retire
debt and to prepare the company for an increasingly competitive business
environment.
The company is obligated to meet approximately $531 million of long-term debt
and preferred stock maturities and cash sinking-fund requirements during the
1995 through 1999 period, including approximately $12 million for 1995.
The company's construction program expenditures, including allowance for funds
used during construction, for the period 1995 through 1999 are estimated to be
approximately $717 million, including approximately $148 million for 1995. The
construction program's main focus is maintaining and upgrading the existing
transmission and distribution system, as well as nuclear and fossil-generating
facilities. NU does not foresee the need for new major generating facilities,
at least until the year 2009. Construction expenditures and debt sinking fund
requirements will continue to be met through internal cash generation.
CL&P entered into interest rate cap contracts to reduce a portion of the
interest rate risk on certain variable-rate tax-exempt pollution control revenue
bonds. CL&P also uses fossil fuel-swap agreements to hedge against fuel-price
risk on certain long-term, negotiated energy contracts. Any premiums paid on
these contracts are deferred and amortized over the life of the contracts. The
differential paid or received as interest rates or fuel prices change is
recognized in income when realized.
See the "Notes To Consolidated Financial Statements," Note 8, for further
information on derivative financial instruments.
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)
1994 VS. 1993 1993 VS. 1992
--------------------------------------------------------------------
(MILLIONS OF DOLLARS)
Regulatory decisions $ 38 $34
Fuel and purchased power
cost recoveries (45) 2
Sales volume 40 3
Wholesale revenues (63) 7
Other revenues (8) 4
----- ----
Total revenue change $(38) $50
==== ===
Operating revenues decreased approximately $38 million in 1994 from 1993. Reve-
nues related to regulatory decisions increased, primarily because of 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 improving economy. Retail
sales increased 3.4 percent in 1994 from 1993 sales levels. Wholesale revenues
decreased primarily due to the expiration in late 1993 and 1994 of some
significant capacity sales contracts.
Operating revenues increased approximately $50 million in 1993 from 1992.
Revenues related to regulatory decisions increased, primarily because of the
effects of the June 1993 retail rate increase for CL&P and higher recoveries for
demand-side-management costs. Retail sales were essentially flat in 1993.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power decreased approximately $89 million in
1994, as compared with 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.
Fuel, purchased and net interchange power increased approximately $59 million in
1993, as compared with 1992, primarily due to the timing in the recognition of
fuel expenses under the provisions of CL&P's fuel adjustment clauses, and 1993
disallowances of replacement-power costs as a result of regulatory reviews in
Connecticut, partially offset by lower outside purchases due to better nuclear
performance in 1993.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses decreased approximately $21 million in
1994, as compared with 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.
Other operation and maintenance expenses increased approximately $19 million in
1993, as compared with 1992, primarily due to the 1993 costs associated with an
employee-reduction program ($24 million) and higher 1993 postretirement benefit
costs, partially offset by lower costs associated with the operation and
maintenance activities of the nuclear units.
DEPRECIATION EXPENSES
Depreciation expenses increased approximately $11 million in 1994, as compared
to 1993, primarily as a result of higher depreciable plant balances, higher
average depreciation rates, and higher decommissioning collections.
Depreciation expenses increased $10 million in 1993, as compared to 1992,
primarily as a result of higher depreciation rates and higher depreciable plant
balances.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased approximately $35 million in
1994, as compared with 1993, primarily because of 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 phase-in costs.
Amortization of regulatory assets, net increased approximately $39 million in
1993, as compared to 1992, primarily because of higher amortization of
Millstone 3 and Seabrook phase-in costs, the gross-up of taxes due to a required
change in the accounting for income taxes, and the amortization of costs paid to
the developers of two wood-to-energy plants as allowed in the 1993 rate
decision.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased approximately $46 million in 1994, as
compared with 1993, primarily because of higher taxable income.
Federal and state income taxes decreased approximately $21 million in 1993, as
compared with 1992, primarily because of lower taxable income and higher
investment tax credits, partially offset by an increase in flow-through
depreciation.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased approximately $17 million in 1994, as
compared with 1993, primarily because additional Millstone 3 investment was
phased into rates in 1994.
Deferred nuclear plants return decreased approximately $11 million in 1993, as
compared with 1992, primarily because additional Millstone 3 investment was
phased into rates in 1993.
OTHER INCOME, NET
Other income, net increased approximately $6 million in 1994, as compared with
1993, and decreased approximately $8 million in 1993, as compared with 1992,
primarily because of the 1993 allocation to customers of a portion of the
property tax accounting change as ordered in the 1993 CL&P rate decision.
INTEREST CHARGES
Interest on long-term debt decreased approximately $14 million in 1994, as
compared with 1993, primarily because of lower average interest rates as a
result of refinancing activities and lower 1994 debt levels.
Interest on long-term debt decreased approximately $17 million in 1993, as
compared with 1992, primarily because of lower average interest rates as a
result of substantial refinancing activities.
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 municipal
property tax expense recognized in the first quarter of 1993.
THE CONNECTICUT LIGHT AND POWER COMPANY
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SELECTED FINANCIAL DATA
------------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $2,328,052 $2,366,050 $2,316,451 $2,275,737 $2,170,087
Operating Income.... 282,159 240,095 287,811 323,835 320,641
Net Income.......... 198,288 191,449(a) 206,714 240,818 224,783
Cash Dividends on
Common Stock...... 159,388 160,365 164,277 172,587 179,921
Total Assets........ 6,217,457 6,397,405 5,582,831 5,338,466 5,176,809
Long-Term Debt*..... 1,823,690 2,057,280 2,087,936 2,023,268 2,101,334
Preferred Stock Not
Subject to Mandatory
Redemption......... 166,200 166,200 231,196 306,195 306,195
Preferred Stock
Subject to Mandatory
Redemption*........ 230,000 230,000 200,000 141,892 146,892
Obligations Under
Capital Leases*.... 175,969 177,418 197,404 208,924 233,919
* Includes portions due within one year.
(a) Includes the cumulative effect of a change in accounting for municipal
property tax expense, which increased earnings for common shares by $47.7
million.
------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------
1994 March 31 June 30 September 30December 31
---------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.. $619,815 $551,135 $598,706 $558,396
======== ======== ======== ========
Operating Income.... $ 88,796 $ 58,190 $ 73,640 $ 61,533
========= ========= ========= =========
Net Income.......... $ 68,590 $ 39,162 $ 50,191 $ 40,345
========= ========= ========= =========
1993
------------------------------------------------------------------------
Operating Revenues.. $627,134 $559,894 $604,343 $574,679
======== ======== ======== ========
Operating Income.... $ 67,201 $ 47,775 $ 58,321 $ 66,798
========= ========= ========= =========
Net Income.......... $ 91,596 $ 13,775 $ 39,068 $ 47,010
========= ========= ========= =========
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,)
--------------------------------------------------------------------------
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
1990 5,881,500 25,039 8,434 1,064,695 3,517