Exhibit 13.2
1993
ANNUAL REPORT
---------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
1993 Annual Report
The Connecticut Light and Power Company
Index
Contents Page
- -------- ----
Balance Sheets. . . . . . . . . . . . . . . . . . . . . . 1-2
Statements of Income. . . . . . . . . . . . . . . . . . . 3
Statements of Cash Flows. . . . . . . . . . . . . . . . . 4
Statements of Common Stockholder's Equity . . . . . . . . 5
Notes to 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
BALANCE SHEETS
At December 31, 1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Utility Plant, at original cost:
Electric......................................... $5,936,344 $ 5,822,783
Less: Accumulated provision for depreciation.. 2,010,962 1,827,024
----------- -----------
3,925,382 3,995,759
Construction work in progress.................... 121,177 110,081
Nuclear fuel, net................................ 156,878 167,816
----------- -----------
Total net utility plant...................... 4,203,437 4,273,656
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at cost.......... 147,657 121,888
Investments in regional nuclear generating
companies and subsidiary companies, at equity... 53,951 53,717
Other, at cost................................... 14,184 14,198
----------- -----------
215,792 189,803
----------- -----------
Current Assets:
Cash and special deposits <F2>(Note 1).......... 2,283 12,104
Receivables, less accumulated provision for
uncollectible accounts of $10,816,000 in 1993
and $8,358,000 in 1992......................... 210,805 231,614
Receivables from affiliated companies............ 29,687 4,804
Accrued utility revenues......................... 97,662 92,366
Fuel, materials, and supplies, at average cost... 60,247 72,199
Recoverable energy costs, net--current
portion <F2>(Note 1)........................... 9,985 77,002
Prepayments and other............................ 33,697 31,875
----------- -----------
444,366 521,964
----------- -----------
Deferred Charges:
Regulatory asset--income taxes <F2>(Note 1)..... 1,026,046 -
Deferred costs--nuclear plants <F2>(Note 1)...... 185,909 199,914
Unrecovered contract obligation-YAEC <F4>(Note 3) 84,526 98,559
Deferred conservation and load-management costs.. 111,442 87,487
Recoverable energy costs, net <F2>(Note 1)....... 26,311 82,423
Deferred DOE assessment <F2>(Note 1)............. 39,279 41,730
Unamortized debt expense......................... 8,971 10,497
Amortizable property investment.................. 6,228 8,720
Other............................................ 45,073 68,053
----------- -----------
1,533,785 597,383
----------- -----------
Total Assets................................. $6,397,380 $5,582,806
=========== ===========
The accompanying notes are an integral part of these financial statements.
1
THE CONNECTICUT LIGHT AND POWER COMPANY
BALANCE SHEETS
At December 31, 1993 1992
- ------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITES
- -----------------------------
Capitalization:
Common stock, $10 par value--authorized
24,500,000 shares; outstanding 12,222,930
shares in 1993 and 1992......................... $ 122,229 $ 122,229
Capital surplus, paid in........................... 630,271 634,851
Retained earnings.................................. 750,719 748,817
----------- -----------
Total common stockholder's equity............ 1,503,219 1,505,897
Cumulative preferred stock--
$50 par value--authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1993 and
5,123,925 in 1992
$25 par value--authorized 8,000,000 shares;
outstanding 5,000,000 shares in 1993 and
7,000,000 shares in 1992
Not subject to mandatory redemption <F6>(Note 5) 166,200 231,196
Subject to mandatory redemption <F7> (Note 6). 230,000 197,500
Long-term debt <F8>(Note 7)....................... 1,743,260 1,930,832
----------- -----------
Total capitalization...................... 3,642,679 3,865,425
----------- -----------
Obligations Under Capital Leases..................... 121,892 136,800
----------- -----------
Current Liabilities:
Notes payable to banks............................. 95,000 96,500
Notes payable to affiliated company................ 1,250 -
Commercial paper................................... - 109,240
Long-term debt and preferred stock--current
portion......................................... 314,020 159,604
Obligations under capital leases--current
portion......................................... 55,526 60,604
Accounts payable................................... 117,858 108,797
Accounts payable to affiliated companies........... 52,179 55,808
Accrued taxes...................................... 36,114 118,132
Accrued interest................................... 29,669 32,829
Other.............................................. 32,287 17,185
----------- -----------
733,903 758,699
----------- -----------
Deferred Credits:
Accumulated deferred income taxes <F2>(Note 1)..... 1,575,965 475,355
Accumulated deferred investment tax credits........ 154,701 165,710
Deferred contract obligation--YAEC <F4>(Note 3).... 84,526 98,559
Deferred DOE obligation <F2>(Note 1)............... 31,523 41,730
Other.............................................. 52,191 40,528
----------- -----------
1,898,906 821,882
----------- -----------
Commitments and Contingencies <F12>(Note 11)
Total Capitalization and Liabilities...... $6,397,380 $5,582,806
=========== ===========
The accompanying notes are an integral part of these financial statements.
2
THE CONNECTICUT LIGHT AND POWER COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31, 1993 1992 1991
- -----------------------------------------------------------------------------
- -----------
(Thousands of
Dollars)
Operating Revenues................................ $2,366,050 $2,316,451
$2,275,737
----------- -----------
- -----------
Operating Expenses:
Operation--
Fuel, purchased and net interchange
power....................................... 657,121 598,287
559,131
Other......................................... 641,402 605,675
614,440
Maintenance..................................... 180,403 197,460
184,727
Depreciation.................................... 219,776 209,884
198,597
Amortization of regulatory assets, net.......... 112,353 73,456
55,693
Federal and state income taxes
<F9>(Note 8).................................. 144,547 172,236
173,102
Taxes other than income taxes................... 170,353 171,642
166,212
----------- -----------
- -----------
Total operating expenses..................... 2,125,955 2,028,640
1,951,902
----------- -----------
- -----------
Operating Income.................................. 240,095 287,811
323,835
----------- -----------
- -----------
Other Income:
Deferred nuclear plants return--
other funds.................................. 23,537 35,396
36,714
Equity in earnings of regional
nuclear generating companies.................. 6,193 8,014
8,021
Other, net...................................... (1,044) 6,964
9,226
Income taxes--credit............................ 4,859 11,171
13,004
----------- -----------
- -----------
Other income, net............................ 33,545 61,545
66,965
----------- -----------
- -----------
Income before interest charges............... 273,640 349,356
390,800
----------- -----------
- -----------
Interest Charges:
Interest on long-term debt...................... 134,263 151,314
166,256
Other interest.................................. 9,654 4,205
1,542
Deferred nuclear plants return--
borrowed funds <F2>(Note 1)................... (13,979) (12,877)
(17,816)
----------- -----------
- -----------
Interest charges, net........................ 129,938 142,642
149,982
----------- -----------
- -----------
Income before cumulative effect of
accounting change............................... 143,702 206,714
240,818
Cumulative effect of accounting change <F2>(Note 1) 47,747 -
-
----------- -----------
- -----------
Net Income........................................ $ 191,449 $ 206,714 $
240,818
=========== ===========
===========
The accompanying notes are an integral part of these financial statements.
3
The Connecticut Light and Power Company
STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------
- ---------------
For the Years Ended December 31, 1993 1992
1991
---------
- --------- ---------
(Thousands
of Dollars)
Cash Flows From Operations:
Net Income .............................................. $ 191,449 $
206,714 $ 240,818
Adjusted for the following:
Depreciation............................................ 226,951
223,058 204,534
Deferred income taxes and investment tax credits, net... (20,188)
72,138 107,599
Deferred nuclear plants return, net of amortization..... 58,740
10,071 (3,529)
Deferred energy costs, net of amortization.............. 123,129
(22,408) (119,629)
Deferred conservation and load-management,
net of amortization.................................... (23,955)
(31,989) (47,402)
Other sources of cash................................... 81,386
13,256 37,143
Other uses of cash...................................... (26,431)
(66,494) (38,730)
Changes in working capital:
Receivables and accrued utility revenues............... (9,370)
245 (36,882)
Fuel, materials, and supplies.......................... 11,951
1,296 24,735
Accounts payable....................................... 5,433
(18,067) 52,029
Accrued taxes.......................................... (82,018)
15,344 (42,228)
Other working capital (excludes cash).................. 9,754
7,154 12,462
---------
- --------- ---------
Net Cash Flows From Operations............................. 546,831
410,318 390,920
---------
- --------- ---------
Cash Flows Used For Financing Activities:
Long-term debt........................................... 740,500
491,000 -
Preferred stock.......................................... 80,000
75,000 -
Financing expenses....................................... (2,393)
(9,825) -
Net increase (decrease) in short-term debt............... (109,490)
15,240 108,385
Reacquisitions and retirements of long-term debt.........
and preferred stock.................................... (886,969)
(523,123) (90,877)
Cash dividends on preferred stock........................ (29,182)
(31,977) (34,541)
Cash dividends on common stock........................... (160,365)
(164,277) (172,587)
---------
- --------- ---------
Net cash flows used for financing activities............... (367,899)
(147,962) (189,620)
---------
- --------- ---------
Investment Activities:
Investment in plant (including capital leases):
Electric utility plant................................. (149,308)
(225,901) (178,670)
Nuclear fuel........................................... (13,658)
3,139 (3,432)
---------
- --------- ---------
Net cash flows used for investments in plant........... (162,966)
(222,762) (182,102)
Other investment activities, net....................... (25,787)
(32,181) (18,334)
---------
- --------- ---------
Net cash flows used for investments........................ (188,753)
(254,943) (200,436)
---------
- --------- ---------
Net Increase (Decrease) In Cash for the Period............. (9,821)
7,413 864
Cash and special deposits - beginning of period........ 12,104
4,691 3,827
---------
- --------- ---------
Cash and special deposits - end of period.............. $ 2,283 $
12,104 $ 4,691
=========
========= =========
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized during
construction............................................. $ 130,592 $
143,957 $ 162,760
=========
========= =========
Income taxes............................................. $ 149,056 $
95,199 $ 92,884
=========
========= =========
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 40,140
30,948 14,713
=========
========= =========
Capital leases........................................... $ - -
10,500
=========
========= =========
The accompanying notes are an integral part of these financial statements.
4
THE CONNECTICUT LIGHT AND POWER COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- -----------------------------------------------------------------------------
- -------
Capital Retained
Common Surplus, Earnings
Stock Paid In <F1>(a) Total
- -----------------------------------------------------------------------------
- -------
(Thousands of Dollars)
Balance at January 1, 1991.......... $122,229 $636,175 $ 705,303
$1,463,707
Net income for 1991............. 240,818
240,818
Cash dividends on preferred
stock......................... (34,541)
(34,541)
Cash dividends on common stock.. (172,587)
(172,587)
Capital stock expenses, net..... 1,027
1,027
--------- --------- ----------
- -----------
Balance at December 31, 1991........ 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
========= ========= ==========
===========
<F1> (a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1993, these restrictions totaled
approximately
$540.0 million.
The accompanying notes are an integral part of these financial statements.
5
THE CONNECTICUT LIGHT AND POWER COMPANY COMPANY
- ---------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS
- ---------------------------------------------------------------------
[FN]
<F2>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
The Connecticut Light and Power Company (CL&P or the company), 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.
ACCOUNTING CHANGES
Property Taxes: CL&P adopted a one-time change in the method of accounting
for municipal property tax expense for their Connecticut properties. Most
municipalities in Connecticut assess property values as of October 1. Prior
to 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, these subsidiaries changed their method of accounting
for Connecticut municipal property taxes to recognize the expense from July 1
through June 30, to match the payment and services provided by the
municipalities. This one-time change increased net income by approximately
$47.7 million for CL&P in 1993.
Income Taxes: The company adopted the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109),
effective January 1, 1993. For more information on this change, see <F2>
Note 1, "Summary of Significant Accounting Policies - Income Taxes."
Postretirement Benefits Other Than Pensions: The company adopted the
provisions of Statement of Financial Accounting Standards No. 106,
Employer's Accounting for Postretirement Benefits Other Than Pensions (SFAS
106), effective January 1, 1993. For more information on this change, see
<F11> Note 10, "Postretirement Benefits Other Than Pensions."
ACCOUNTING RECLASSIFICATIONS
Certain amounts in the accompanying financial statements of CL&P for the
year ended December 31, 1992 and 1991 have been reclassified to conform
with the December 31, 1993 presentation.
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
6
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 and other matters by the FERC and the
Connecticut Department of Public Utility Control (DPUC), and follows the
accounting policies prescribed by the respective commissions.
REVENUES
Other than special contracts, 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.
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. At December 31, 1993, fees due to the
DOE for the disposal of prior-period fuel were approximately $136.1 million,
including interest costs of $69.6 million. As of December 31, 1993,
approximately $134.5 million had been collected through rates.
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its
proportionate shares of the costs of decontaminating and decommissioning
uranium enrichment plants operated by the DOE (D&D assessment). The Energy
Act imposes an overall cap of $2.25 billion on the obligation of the
commercial power industry and limits the annual special assessment to $150
million each year over a 15-year period beginning in 1993. The Energy Act
also requires that regulators treat D&D assessments as a reasonable and
necessary cost of fuel, to be fully recovered in rates, like any other fuel
cost. The cap and annual recovery amounts will be adjusted annually for
inflation. The D&D assessment is allocated among utilities based upon
services purchased in prior years. At December 31, 1993, CL&P's remaining
share of these costs is estimated to be approximately $39.3 million. CL&P
has begun to recover these costs. Accordingly, CL&P has recognized these
costs as a regulatory asset, with a corresponding obligation, on its
Balance Sheets.
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. The electricity produced by these facilities that are operating is
committed to the participants substantially on the basis
7
of their ownership interests and is billed pursuant to
contractual agreements. For more information on these agreements, see <F12>
Note 11, "Commitments and Contingencies - Purchased Power Arrangements."
The 173 megawatt (MW) YAEC nuclear power plant was shut down permanently on
February 26, 1992. For more information on the Yankee companies, see <F4>
Note 3, "Nuclear Decommissioning."
Millstone 1: CL&P has an 81 percent joint-ownership interest in Millstone
1, a 660 MW nuclear generating unit. As of December 31, 1993, plant-in-
service and the accumulated provision for depreciation included approximately
$332 million and $130.8 million, respectively, for CL&P's share of Millstone
1. CL&P's share of Millstone 1 operating expenses is included in the
corresponding operating expenses on the accompanying Statements of Income.
Millstone 2: CL&P has an 81 percent joint-ownership interest in Millstone
2, a 875 MW nuclear generating unit. As of December 31, 1993, plant-in-
service and the accumulated provision for depreciation included
approximately $676 million and $151.5 million, respectively, for CL&P's
share of Millstone 2. CL&P's share of Millstone 2 operating expenses is
included in the corresponding operating expenses on the accompanying
Statements of Income.
Millstone 3: CL&P has a 52.93 percent joint-ownership interest in
Millstone 3, a 1,149 MW nuclear generating unit. As of December 31, 1993,
plant-in-service and the accumulated provision for depreciation included
approximately $1.9 billion 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 Statements of
Income.
Seabrook: As of December 31, 1993, CL&P has a 4.06 percent joint-ownership
interest in Seabrook 1, a 1,150 MW nuclear generating unit. As of December
31, 1993, plant-in-service and the accumulated provision for depreciation
included approximately $173.4 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 Statements of
Income.
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 <F4> 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 3.8 percent in 1993, 3.7 percent in 1992, and
3.5 percent in 1991.
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
8
subject to tax) is accounted for in accordance with the ratemaking treatment
of the applicable regulatory commissions. See <F9> Note 8, "Income Tax
Expense," for the components of income tax expenses.
In 1992, the Financial Accounting Standards Board (FASB) issued 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. At December 31, 1993, the deferred tax obligation relating to the
adoption of SFAS 109 approximated $1.0 billion. 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. SFAS 109 does not permit
net-of-tax accounting. Accordingly, the company no longer utilizes
net-of-tax accounting for the deferred nuclear plants return-borrowed funds
and allowance for funds used during construction (AFUDC) - borrowed funds.
The temporary differences which give rise to the accumulated deferred tax
obligation at December 31, 1993, are as follows:
(Thousands of Dollars)
Accelerated depreciation and other plant-related
differences. . . . . . . . . . . . . . . . . . $1,049,849
The tax effect of net regulatory assets. . . . . 434,894
Other. . . . . . . . . . . . . . . . . . . . . . 91,222
----------
$1,575,965
==========
ENERGY ADJUSTMENT CLAUSES
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. Administrative proceedings are required each month to approve
the FAC charges or credits proposed for the following month. Monthly FAC
rates are also subject to retroactive review and appropriate adjustment by
the DPUC each quarter after public hearings.
Beginning in 1979, the DPUC approved the use of 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. Generally, at the end of a 12-month period ending July
31 of each year, these deferrals are refunded to, or collected from, customers
over the subsequent 11-month period beginning in September. Should the annual
composite nuclear capacity factor fall below the 55 percent GUAC floor, CL&P
would have to apply to the DPUC for permission to recover the additional fuel
expense associated with nuclear performance below 55 percent.
On January 5, 1994, the DPUC issued a decision which ordered CL&P to offset
GUAC deferred charges against prior fuel over-recoveries. The disallowance
resulted in a zero GUAC rate for the period September 1993 through August
1994. CL&P is considering an appeal of this decision.
The DPUC further ordered that any GUAC deferrals subsequent to July 1993
will be offset by any fuel overrecoveries whenever the composite nuclear
capacity factor is below the level embedded in base rates. For the period
August 1993 to December 1993, there have been no further adjustments
necessary as a result of the DPUC's decision.
9
The January 5, 1994 DPUC decision creates some uncertainty about the future
operation of the GUAC. CL&P has requested the DPUC to clarify the portion
of the decision related to future calculation of the GUAC rate. Management
does not expect the decision to have a material adverse impact on CL&P's
future results of operations.
For additional information see <F12> Note 11, "Commitments and Contingencies
"Nuclear Performance."
CONSERVATION AND LOAD MANAGEMENT COSTS
Conservation and Load Management (C&LM) costs are recovered through a
Conservation Adjustment Mechanism (CAM). The DPUC issued an order in April
1993, which allowed CL&P to recover C&LM expenditures over an eight-year
period and reaffirmed program performance incentives. In December 1993,
CL&P filed a proposed CAM settlement with the DPUC. The settlement
proposes 1994 C&LM expenditures of $39 million, a reduction in the cost
recovery period from 8 to 3.85 years, and other changes in program designs,
performance incentives, and cost recovery. Unrecovered C&LM costs at
December 31, 1993 were $111.4 million.
PHASE-IN PLANS
As discussed below, CL&P is phasing into rates the recoverable parts of its
investments in Millstone 3 and Seabrook 1. All plans are in compliance
with Statement of Financial Accounting Standards No. 92, Regulated
Enterprises-Accounting for Phase-in Plans.
As allowed by the DPUC, CL&P is phasing into rate base its allowed investment
in Millstone 3. The DPUC has provided for full deferred earnings and carrying
charges on the portion of CL&P's allowed investment in Millstone 3 not included
in rate base. Through December 31, 1993, CL&P had placed into rate base $1.58
billion, or 90 percent, of its allowed investment in Millstone 3. The remaining
$175.7 million, or 10 percent, is to be phased into rate base annually in two
5-percent steps beginning January 1, 1994. The amortization and recovery of
deferrals through rates began January 1, 1988 and will end no later than
December 31, 1995. As of December 31, 1993, $349.6 million of the deferred
return, including carrying charges, has been recovered, and $161.9 million of
the deferred return to date, plus carrying charges, remains to be recovered.
As allowed by the DPUC, CL&P phased into rate base its allowed investment
in Seabrook 1. The DPUC provided for full deferred earnings and carrying
charges on the portion of CL&P's allowed investment in Seabrook 1 not
included in rate base. Through December 31, 1993, CL&P has placed into
rate base its full allowed investment in Seabrook 1. The amortization and
recovery of deferrals through rates began September 1, 1991 and will end no
later than August 31, 1996. As of December 31, 1993, $15.8 million of the
deferred return, including carrying charges, has been recovered, and $24.0
million of the deferred return recorded to date, plus carrying charges,
remains to be recovered.
CASH AND SPECIAL DEPOSITS
Cash and special deposits at December 31, 1992 included $10 million in
special deposits that was used to redeem $10 million of CL&P's Pollution
Control Notes.
<F3>
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 share of the nuclear fuel for Millstone 3. CL&P and
WMECO make quarterly lease payments for the cost of nuclear fuel consumed
10
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 substation equipment, 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
---- ------- ---------
1993. . . . . . . . . . $76,549,000 $24,355,000
1992. . . . . . . . . . 61,795,000 26,919,000
1991. . . . . . . . . . 50,998,000 26,320,000
Interest included in capital lease rental payments was $11,298,000 in 1993,
$14,782,000 in 1992, and $15,974,000 in 1991.
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, 1993, are approximately:
11
Capital Operating
Year Leases Leases
---- ------- ---------
(Thousands of Dollars)
1994. . . . . . . . . . . . $ 2,800 $ 20,800
1995. . . . . . . . . . . . 2,800 19,500
1996. . . . . . . . . . . . 2,800 17,900
1997. . . . . . . . . . . . 2,800 17,200
1998. . . . . . . . . . . . 2,800 12,300
After 1998. . . . . . . . . 45,000 75,700
------- --------
Future minimum lease
payments . . . . . . . . . 59,000 $163,400
========
Less amount of representing
interest . . . . . . . . . 38,300
-------
Present value of future
minimum lease payments
for other than nuclear
fuel . . . . . . . . . . . 20,700
Present value of future
nuclear fuel lease
payments . . . . . . . . . 156,700
-------
Total. . . . . . $177,400
========
<F4>
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 1991
Seabrook decommissioning study also confirmed that complete and immediate
dismantlement at retirement is the most viable and economic method of
decommissioning Seabrook 1. Decommissioning studies are reviewed and
updated periodically to reflect changes in decommissioning requirements,
technology, and inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1
and 2, in year-end 1993 dollars, is $312.5 million and $251.0 million,
respectively. At December 31, 1993, the estimated cost of decommissioning
CL&P's ownership share of Millstone 3 and Seabrook 1, in year-end 1993
dollars, is $223.0 million and $14.9 million, respectively. Nuclear
decommissioning costs are accrued over the expected service life of the
units and are included in depreciation expense on the Statements of Income.
Nuclear decommissioning costs amounted to $21.9 million in 1993 and 1992,
and $16.2 million in 1991. Nuclear decommissioning, as a cost of removal,
is included in the accumulated provision for depreciation on the Balance
Sheets.
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.
12
As of December 31, 1993, CL&P has collected, through rates, $148.3 million,
toward the future decommissioning costs of its share of the Millstone
units, of which $116.8 million has been transferred to external
decommissioning trusts. As of December 31, 1993, CL&P has paid approximately
$860,000 into Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning trusts and financing fund increase the decommissioning trust
balance and the accumulated reserve for decommissioning. At December 31,
1993, the balance in the accumulated reserve for decommissioning amounted to
$179.1 million.
Changes in requirements or technology, or adoption of a decommissioning
method other than immediate dismantlement, could 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.
Although allowances for decommissioning have increased significantly in
recent years, ratepayers in future years will 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 1993 dollars, of decommissioning
CL&P's ownership share of CY and MY, are $117.3 million and $38.8 million,
respectively. The cost to decommission VY is currently being re-estimated.
The cost of decommissioning CL&P's ownership share of VY is projected to
range from $28.5 million to $33.3 million. As discussed in the following
paragraph, YAEC's owners voted to permanently shut down the YAEC unit on
February 26, 1992. 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 decommissioning its nuclear facility. On June 1, 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. At December 31, 1993, the estimated remaining costs amounted to
$345.0 million, of which CL&P's share was approximately $84.5 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
Balance Sheets. CL&P has a 24.5 percent equity investment, approximating
$5.9 million, in YAEC. CL&P had relied on YAEC for less than 1 percent of
its capacity.
<F5>
4. SHORT-TERM DEBT
The system companies have various credit lines, totaling $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 17 banks. Under
this facility, the participating companies may borrow up to an aggregate of
$360 million. Individual borrowing limits are $175 million for NU, $360
million for CL&P, $75 million for WMECO, $8 million for HWP, $60 million
for NNECO, and $25 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 of each bank's total
13
commitment under the three-year portion of the facility, representing 75
percent of the total facility, plus .135 percent of each bank's total
commitment under the 364-day portion of the facility, representing 25
percent of the total facility. At December 31, 1993, there were $22.5
million of borrowings under the facility, $5 million attributable to CL&P.
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. Investing and
borrowing subsidiaries receive or pay interest based on the average daily
Federal Funds rate. 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.
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, 1993, to incur short-term borrowings up
to a maximum of $375 million.
14
<F6>
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1993 Outstanding
December 31,
Redemption December 31
- --------------------------------
Description Price 1993 1993
1992 1991
- -----------------------------------------------------------------------------
- ---------------------
(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 20,000
$4.48 Series H of 1970. . . . - - -
15,000 15,000
$4.48 Series I of 1970. . . . - - -
20,000 20,000
$4.56 Series K of 1974. . . . - - -
- 50,000
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 9,996
9.36% Series of 1970. . . . . - - -
- 10,000
9.60% Series of 1974. . . . . - - -
- 14,999
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 $
231,196 $ 306,195
========
======== ========
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.
15
<F7>
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1993 Outstanding December
31,
Redemption December 31
- --------------------------------
Description Price* 1993 1993
1992 1991
- -----------------------------------------------------------------------------
- ---------------------
(Thousands
of Dollars)
$5.52 Series L of 1975 . . . . $ - $ - $ - $
- $ 1,926
10.48% Series of 1980 . . . . . - - -
- 14,000
11.52% Series of 1975 . . . . . - - -
- 966
9.10% Series of 1987 . . . . . - - -
50,000 50,000
9.00% Series of 1989 . . . . . 26.65 3,000,000 75,000
75,000 75,000
7.23% Series of 1992 . . . . . 52.41 1,500,000 75,000
75,000 -
5.30% Series of 1993 . . . . . 51.00 1,600,000 80,000
- -
--------
- -------- --------
230,000
200,000 141,892
Less preferred stock to be
redeemed within on year . . . . -
2,500 2,500
--------
- -------- --------
Total preferred stock
subject to mandatory
redemption . . . . . . . . . . $230,000
$197,500 $139,392
========
======== ========
*Redemption prices reduce in future years.
The following table details redemption and sinking fund activity forpreferred
stock subject to
mandatory redemption:
Minimum
Annual Shares Reacquired
Sinking-Fund
- ------------------------------------
Series Requirement 1993 1992
1991
- -----------------------------------------------------------------------------
- ---------
(Thousands of Dollars)
$5.52 Series L of 1975 $ - - 38,524
40,000
10.48% Series of 1980 - - 280,000
40,000
11.52% Series of 1975 - - 19,318
20,008
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.
16
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1994 through 1998, aggregate approximately $0 in
1994, $3,750,000 in 1995, 1996, and 1997, and $7,500,000 in 1998. 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.
17
<F8>
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
- -------------------------------------------------------------------------
December 31,
---------------
1993 1992
- -------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
4 1/4% Series 1963 due 1993 . . . . $ - $ 15,000
8 1/2% Series PP due 1993 . . . . - 125,000
4 1/2% Series 1964 due 1994 . . . . 12,000 12,000
4 1/4% Series WW due 1994 . . . . 170,000 170,000
5 5/8% Series 1967 due 1997 . . . . 20,000 20,000
6% Series S due 1997 . . . . 30,000 30,000
7 5/8% Series UU due 1997 . . . . 200,000 200,000
6 7/8% Series U due 1998 . . . . 40,000 40,000
7 1/8% Series 1968 due 1998 . . . . 25,000 25,000
6 1/2% Series T due 1998 . . . . 20,000 20,000
6 1/2% Series 1968 due 1998 . . . . 10,000 10,000
7 1/4% Series VV due 1999 . . . . 100,000 100,000
8 3/4% Series V due 2000 . . . . - 40,000
8 7/8% Series W due 2000 . . . . - 40,000
5 3/4% Series XX due 2000 . . . . 200,000 -
7 3/8% Series X due 2001 . . . . 30,000 30,000
7 5/8% Series 1971 due 2001 . . . . 30,000 30,000
7 1/2% Series 1972 due 2002 . . . . 35,000 35,000
7 5/8% Series Y due 2002 . . . . 50,000 50,000
7 5/8% Series Z due 2003 . . . . 50,000 50,000
7 1/2% Series 1973 due 2003 . . . . 40,000 40,000
8 3/4% Series AA due 2004 . . . . - 65,000
9 1/4% Series 1974 due 2004 . . . . - 30,000
8 7/8% Series DD due 2007 . . . . - 45,000
9 1/4% Series EE due 2008 . . . . - 40,000
9 3/8% Series 1978 due 2008 . . . . - 40,000
9 3/4% Series QQ due 2018 . . . . 75,000 75,000
9 1/2% Series RR due 2019 . . . . 75,000 75,000
9 3/8% Series SS due 2019 . . . . 75,000 75,000
7 3/8% Series TT due 2019 . . . . 20,000 20,000
7 1/2% Series YY due 2023 . . . . 100,000 -
7 3/8% Series ZZ due 2025 . . . . 125,000 -
---------- ----------
Total First Mortgage Bonds. . $1,532,000 $1,547,000
18
- ---------------------------------------------------------------------------
December 31,
---------------------------
1993 1992
- ---------------------------------------------------------------------------
(Thousands of Dollars)
Pollution Control Notes:
5.90%, due 1998. . . . . . . . . $ - $ 6,197
6.50%, due 2007. . . . . . . . . - 16,000
Variable rate, due 2013-2022 . . 46,400 350,100
Tax exempt, due 2028 . . . . . . . 315,500 -
Fees and interest due for spent fuel
disposal costs . . . . . . . . . 136,125 132,015
Other. . . . . . . . . . . . . . . 35,417 41,493
Less amounts due within one year . 314,020 157,104
Unamortized premium and
discount, net. . . . . . . . . . (8,162) (4,869)
---------- ----------
Long-term debt, net . . . . . $1,743,260 $1,930,832
========== ==========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1993 for the years 1994 through 1998 are
approximately: $189,020,000, $8,111,000, $9,372,000, $260,828,000, and
$95,011,000, respectively. Also, $125 million of first mortgage bonds
outstanding at December 31, 1993 had been called in December 1993 for
redemption in 1994. In addition, there are annual one percent sinking- and
improvement-fund requirements, currently amounting to $13,950,000 for the
year 1994, $12,250,000 for 1995, 1996, and 1997, and $9,750,000 for 1998.
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, 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 indentures.
CL&P has entered into an interest-rate cap contract to reduce the potential
impact of upward changes in interest rates on certain variable-rate tax-
exempt pollution control revenue bonds. Approximately $340 million of total
outstanding long-term variable-rate debt is secured by this interest rate
cap. The total cost of the interest-rate cap for 1993 was approximately $2.9
million, the cost of which is amortized over the terms of the contract, which
is three years. The fair market value of the interest-rate cap contract as
of December 31, 1993 is approximately $388,000.
Fees and interest due for spent fuel disposal costs are scheduled to be paid
to the United States Department of Energy just prior to the first delivery
of prior-period spent fuel, which is anticipated to be in 1998. Until such
payment is made, the outstanding balance will continue to accrue interest at
the three-month Treasury Bill Yield Rate. For additional information, see
<F2> Note 1 of the accompanying Notes to Financial Statements.
19
<F9>
8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions charged to
operations are:
- -----------------------------------------------------------------------------
- ---------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992
1991
- -----------------------------------------------------------------------------
- ---------------
(Thousands of Dollars)
Current income taxes:
Federal. . . . . . . . . . . . . . . . . $115,403 $ 61,773
$ 33,717
State. . . . . . . . . . . . . . . . . . 44,473 27,153
18,782
-------- --------
- --------
Total current. . . . . . . . . . . . . 159,876 88,926
52,499
-------- --------
- --------
Deferred income taxes, net:
Federal. . . . . . . . . . . . . . . . . 3,808 60,788
88,554
State. . . . . . . . . . . . . . . . . . (12,987) 11,833
26,430
-------- --------
- --------
Total deferred . . . . . . . . . . . . (9,179) 72,621
114,984
-------- --------
- --------
Investment tax credits, net . . . . . . (11,009) (6,230)
(6,230)
-------- ---------
- ---------
Total income tax expense. . . . . . . $139,688 $155,317
$161,253
======== ========
========
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses. . . . . . . . . . . . . . . . $144,547 $172,236
$173,102
Income taxes associated with the
amortization of deferred nuclear
plants return - borrowed funds. . . . . - (15,157)
(12,263)
Income taxes associated with AFUDC and
deferred nuclear plants return -
borrowed funds. . . . . . . . . . . . . - 9,409
13,418
Other income taxes - credit. . . . . . . (4,859) (11,171)
(13,004)
-------- --------
---------
Total income tax expense . . . . . . . . $139,688 $155,317
$161,253
======== ========
========
20
Deferred income taxes are comprised of the tax effects of temporary differences
as follows:
- -----------------------------------------------------------------------------
- -----------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992
1991
- -----------------------------------------------------------------------------
- -----------------
(Thousands of
Dollars)
Depreciation, leased nuclear fuel,
settlement credits, and disposal
costs. . . . . . . . . . . . . . . . . . $ 42,663 $ 43,715
$ 49,636
Conservation and load management. . . . . 9,156 13,506
22,594
Postretirement benefits accrual . . . . . (2,579) -
-
Energy adjustment clauses . . . . . . . . (52,189) 12,627
47,483
AFUDC and deferred nuclear plants
return, net. . . . . . . . . . . . . . . (13,741) (5,748)
1,155
Early retirement program. . . . . . . . . (3,355) 3,988
(9,718)
Pension accrual . . . . . . . . . . . . . 3,553 885
(351)
Settlement, canceled independent
power plants . . . . . . . . . . . . . . - 7,251
-
Loss on bond redemption . . . . . . . . . 8,145 10
-
Other . . . . . . . . . . . . . . . . . . (832) (3,613)
4,185
--------- --------
--------
Deferred income taxes, net. . . . . . $ (9,179) $ 72,621
$114,984
========= ========
========
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, 1993 <F2>(Note 1) 1992
1991
- -----------------------------------------------------------------------------
- -----------------
(Thousands of
Dollars)
Expected federal income tax at
35 percent of pretax income
for 1993 and 34 percent for
1992 and 1991. . . . . . . . . . . . . . $115,898 $123,091
$136,704
Tax effect of differences:
Depreciation differences . . . . . . . . 19,264 15,826
10,647
Deferred nuclear plants return -
other funds . . . . . . . . . . . . . . (8,294) (12,035)
(12,483)
Amortization of nuclear plants return -
other funds . . . . . . . . . . . . . . 18,648 14,511
12,918
Property tax differences . . . . . . . . (12,320) (732)
502
Investment tax credit amortization . . . (11,009) (6,230)
(6,230)
State income taxes, net of federal
benefit . . . . . . . . . . . . . . . . 20,466 25,730
29,987
Adjustment for prior years taxes . . . . (2,330) (3,500)
(7,000)
Other, net . . . . . . . . . . . . . . . (635) (1,344)
(3,792)
-------- --------
- --------
Total income tax expense . . . . . . . $139,688 $155,317
$161,253
======== ========
========
21
<F10>
9. PENSION BENEFITS
The company participates in a uniform noncontributory defined benefit
retirement plan covering all regular system employees (the Plan). Benefits
are based on years of service and employees' highest eligible compensation
during five consecutive years of employment. The company's direct-allocated
portion of the system's pension cost, part of which was charged to utility
plant, approximated $7.6 million in 1993, ($1.7) million in 1992, and $10.8
million in 1991. The company's pension costs for 1993 and 1991 include
approximately $13.1 million and $10.0 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 the Plan's net pension cost for the system (excluding PSNH
and NAESCO in 1992 and 1991) are:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . $ 59,068 $ 27,480 $ 48,738
Interest cost. . . . . . . . . . 81,456 69,746 71,041
Return on plan assets. . . . . . (176,798) (77,232) (198,437)
Net amortization . . . . . . . . 65,447 (16,266) 108,175
-------- -------- --------
Net pension cost . . . . . . . . $ 29,173 $ 3,728 $ 29,517
======== ======== ========
- ----------------------------------------------------------------------------
For calculating pension cost, the following assumptions were used:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- -----------------------------------------------------------------------------
Discount rate. . . . . . . . . . 8.00% 8.50% 9.00%
Expected long-term rate of
return. . . . . . . . . . . . . 8.50 9.00 9.70
Compensation/progression rate. . 5.00 6.75 7.50
- -----------------------------------------------------------------------------
22
The following table represents the Plan's funded status reconciled to the NU
Consolidated Balance Sheets:
- -----------------------------------------------------------------------------
At December 31, 1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $817,421,000 of vested
benefits at December 31, 1993 and
$719,608,000 of vested benefits at
December 31, 1992 . . . . . . . . . . $ 898,788 $ 764,432
========== ==========
Projected benefit obligation . . . . . $1,141,271 $1,055,295
Less: Market value of plan assets . . 1,340,249 1,226,468
---------- ----------
Market value in excess of projected
benefit obligation. . . . . . . . . . 198,978 171,173
Unrecognized transition amount . . . . (16,735) (18,277)
Unrecognized prior service costs . . . 10,287 8,658
Unrecognized net gain. . . . . . . . . (275,043) (214,894)
---------- ----------
Accrued pension liability. . . . . . . $ (82,513) $ (53,340)
========== ===========
- -----------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the Plan's year-
end funded status:
- -----------------------------------------------------------------------------
At December 31, 1993 1992
- -----------------------------------------------------------------------------
Discount rate. . . . . . . . . . . . . 7.75% 8.00%
Compensation/progression rate. . . . . 4.75 5.00
The discount rate for 1993 was determined by analyzing the interest rates, as
of December 31, 1993, of long-term high-quality corporate debt securities
having a duration comparable to the 13.8-year duration of the plan.
During 1993, NU's work force was reduced by approximately 7 percent through a
work force reduction program that involved an early retirement program and
involuntary terminations. CL&P's direct cost of the program, which
approximated $14.8 million, included pension, severance, and other benefits.
<F11>
10. 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. Through December 31, 1992, the company recognized the cost of
these benefits as
23
they were paid. In December 1990, the FASB issued SFAS 106. This new
standard requires that the expected cost of postretirement benefits,
primarily health and life insurance benefits, must be charged to expense
during the years that eligible employees render service. Effective January
1, 1993, the company adopted SFAS 106 on a prospective basis. Total health
care and life insurance cost, part of which were deferred or charged to
utility plant, approximated $23,170,000 in 1993, $8,791,000 in 1992, and
$7,525,000 in 1991.
On January 1, 1993, the accumulated postretirement benefit obligation (APBO)
represented the company's prior-service obligation upon the adoption of SFAS
106. As allowed by SFAS 106, the company is amortizing its APBO of
approximately $164 million over a 20-year period. For current employees and
certain retirees, the total SFAS 106 benefit is limited to two times the 1993
health care costs. The SFAS 106 obligation has been calculated based on this
assumption.
During 1993, the company did not fund SFAS 106 postretirement costs through
external trusts. The company expects to fund annually amounts once they have
been rate recovered and which also are tax-deductible under the Internal
Revenue Code.
The following table represents the plan's funded status reconciled to the
Balance Sheet at December 31, 1993:
- ----------------------------------------------------------------- -----------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees . . . . . . . . . . . . . . $(119,520)
Fully eligible active employees. . . (288)
Active employees not eligible to
retire. . . . . . . . . . . . . . . (29,270)
---------
Total accumulated postretirement
benefit obligation. . . . . . . . . (149,078)
Unrecognized transition amount . . . 139,539
Unrecognized net gain. . . . . . . . (2,591)
---------
Accrued postretirement benefit
liability . . . . . . . . . . . . . $ (12,130)
=========
- ----------------------------------------------------------------------------
The components of health care and life insurance costs for the year ended
December 31, 1993 are:
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . $ 3,397
Interest cost. . . . . . . . . . . . 12,091
Net amortization . . . . . . . . . . 7,682
-------
Net health care and life insurance
costs . . . . . . . . . . . . . . . $23,170
=======
- ----------------------------------------------------------------- -----------
24
For measurement purposes, an 11.1-percent annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1993; the rate
was assumed to decrease to 5.4 percent for 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, 1993 by $10.5 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit cost for the
year then ended by $1.0 million.
The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 7.75 percent. The discount rate for
1993 was determined by analyzing the interest rates, as of December 31, 1993,
of the long-term, high-quality corporate debt securities having a duration
comparable to that of the plan.
CL&P has received approval from the DPUC to defer and recover the incremental
SFAS 106 postretirement costs within eight years.
<F12>
11. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision. Actual
construction expenditures may vary from such 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 $741.8 million for the years 1994-1998, including $157.8
million for 1994. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $317.7 million for the years 1994-1998, including $74.6 million
for 1994. See <F3> Note 2, "Leases," for additional information about the
financing of nuclear fuel.
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 four of the
reviews. The Office of Consumer Counsel has appealed decisions favorable to
the company in two dockets. 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 docket is $26
million. The only remaining nuclear outage prudence docket before the DPUC
is the docket established to review the 1992 outage at Millstone 2 to replace
the steam generators. A decision is expected in late 1994. Management
believes that its actions with respect to these outages have been prudent,
and it does not expect the outcome of the prudence reviews to result in
material disallowances.
ENVIRONMENTAL MATTERS
CL&P is subject to regulation by federal, state, and local authorities with
respect to air and water quality, handling and 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 program to
prevent, detect, and remedy noncompliance with environmental laws or
regulations and believes that it is in substantial compliance with current
environmental laws and regulations. Changing
25
environmental requirements could hinder the construction of new fossil-fuel
environmental generating units, transmission, and distribution lines,
substations, and other facilities. The cumulative long-term economic cost
impact of increasingly stringent environmental requirements cannot be
estimated. Changing environmental requirements could also require extensive
and costly modifications to CL&P's existing hydro, nuclear, and fossil-fuel
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 and
disposal activities.
CL&P has recorded a liability for what it believes is, based upon information
currently available, the estimated environmental remediation costs for waste
disposal sites for which it expects to bear legal liability. To date, these
costs have not been material with respect to the earnings or financial
position of the company. In most cases, the extent of additional future
environmental cleanup costs is not estimable due to factors such as the
unknown magnitude of possible contamination, the appropriate remediation
method, the possible effects of future legislation and regulation, the
possible effects of technological changes related to future cleanup, and the
difficulty of determining future liability, if any, for the cleanup of sites
at which CL&P has been informed that it may be determined to be legally
liable by the federal or state environmental agencies. In addition, CL&P
cannot estimate the potential liability for future claims that may be brought
against it by private parties. However, considering known facts and existing
laws and regulatory practices, management does not believe that such matters
will have a material adverse effect on CL&P's financial position or future
results of operations. At December 31, 1993, the liability recorded by CL&P
for its estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to $2.9
million. However, in the event that it becomes necessary to effect
environmental remedies that are currently not considered probable for the
sites for which CL&P has recorded a liability, it is reasonably possible
that, based on information currently available and management intent, that
the upper limit of CL&P's environmental liability range could increase to
approximately $5.8 million.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $9.4 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 $8.8 billion
would be provided by an assessment of $75.5 million per incident, levied on
each of the 116 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 $437.9 million in total, for all 116 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 four
Yankee regional nuclear generating companies, CL&P would be responsible for
up to an additional $63.8 million per incident. Payments for CL&P's
ownership interest in nuclear generating facilities would be limited to a
maximum of $29.9 million per incident per year.
26
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 cost of
repair, replacement, or decontamination or premature decommissioning of
utility property resulting from 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 $9.7 million under the replacement power
policies and $18.9 million under the 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 companies insured under this coverage are
subject to retrospective assessments of $3.2 million per reactor. The
maximum potential assessments against CL&P with respect to losses arising
during the current policy period are approximately $9.6 million.
FINANCING ARRANGEMENTS FOR THE REGIONAL NUCLEAR GENERATING COMPANIES
CL&P believes that the regional nuclear generating companies may require
additional external financing in the next several years for construction
expenditures, nuclear fuel, possible refinancings, and other purposes.
Although the ways in which each regional nuclear generating company will
attempt to finance these expenditures has not been determined, CL&P may be
asked to provide direct or indirect financial support for one or more of
these companies.
PURCHASED POWER ARRANGEMENTS
CL&P purchases a portion of its electricity requirements pursuant to long-
term contracts with the Yankee companies. Under the terms of its agreements,
the company pays its ownership share (or entitlement share) of generating
costs, which include depreciation, operation and maintenance expenses, 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. The total cost of purchases under these contracts for the
units that are operating amounted to $112.3 million in 1993, $103.2 million
in 1992, and $99.7 million in 1991. See <F2> Note 1, "Summary Of Significant
Accounting Policies - Investments and Jointly Owned Electric Utility Plant"
and <F4> 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. Some of 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,
1993, 14 percent of NU system load requirements was met by cogenerators and
small power producers. The total cost of purchases under these arrangements
amounted to $279.8 million in 1993, $267.3 million in 1992, and $237.6
million in 1991. These costs are eventually recovered through the company's
rates.
27
The estimated annual cost of CL&P's significant purchase power arrangements
is provided below:
(In Millions)
- --------------------------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
Yankee companies $106.6 $109.2 $121.5 $111.8 $126.5
Nonutility generators 293.7 303.3 313.1 318.6 324.9
- --------------------------------------------------------------------------
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, PSNH, WMECO, and
HWP, in the aggregate, are obligated to pay, over a 30-year period, their
proportionate share of the annual operation, maintenance, and capital costs
of these facilities, which are currently forecast to be $172.1 million for
the years 1994-1998, including $37.2 million for 1994.
GREAT BAY POWER CORPORATION
CL&P and The United Illuminating Company, an unaffiliated company, have
agreed to make certain advances up to $20 million to cover shortfalls in the
funding of the 12.13 percent ownership interest in Seabrook 1 of Great Bay
Power Corporation, an unaffiliated company. CL&P's share of this commitment
is limited to 60 percent of the advances, or $12 million. As of December 31,
1993, $1,047,000 of advances from CL&P were outstanding under this agreement.
PROPERTY TAXES
CY has a significant court appeal pending for its property tax assessment in
the town of Haddam, Connecticut, concerning production plant. The central
issue is the fair market value of utility property. The company believes
that a properly derived assessment that recognizes the effect of rate
regulation will result in a fair market value that approximates net book
cost. This is the assessment level that taxing authorities are predominantly
using throughout Connecticut, Massachusetts, and some of New Hampshire.
However, towns such as Haddam advocate a method that approximates
reproduction cost. The company estimates that,for the Haddam assessment, the
change to a reproduction cost-methodology could result in a property tax
valuation approximately three times greater than a value approximating net
book cost. Although CY is currently paying property taxes based on the
higher assessment, to date, the higher assessment has not had a material
adverse effect on it or the company.
The company believes that assessment levels that approximate net book cost
accurately reflect the fair market value of regulated utility property.
However, because of uncertainties associated with the court appeal and the
potential impact of an adverse court decision on property tax assessment
policy in Connecticut, the company cannot estimate the potential effect of an
adverse court decision on future results of operations or financial
condition. However, the company believes that, based upon past regulatory
practices, it would be allowed to recover any increased property tax
assessment prospectively beginning at the time new rates are established.
28
<F13>
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash, special deposits, and nuclear decommissioning trusts: The carrying
amounts approximate fair value.
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, 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
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
Carrying Fair
At December 31, 1992 Amount Value
- --------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to mandatory
redemption . . . . . . . . . . . . . . . . . $ 231,196 $ 184,910
Preferred stock subject to mandatory
redemption . . . . . . . . . . . . . . . . . 200,000 208,750
Long-term debt:
First Mortgage Bonds . . . . . . . . . . . . 1,547,000 1,594,643
Other long-term debt . . . . . . . . . . . . 545,805 545,805
- --------------------------------------------------------------------------
29
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts that those
obligations would be settled at.
In May 1993, the FASB issued Statement of Financial Accounting Standards No.
115, "Accounting for Certain Investments in Debt and Equity Securities (SFAS
115)." SFAS 115 requires companies to disclose the classification of
investments in debt or equity securities based on management's intent and
ability to hold the security. SFAS 115 also requires disclosure of the
aggregate fair value, gross unrealized holding gains, gross unrealized
holding losses and amortized cost basis by major security type. Effective
January 1, 1994, CL&P will adopt SFAS 115 on a prospective basis. CL&P
anticipates that the adoption of SFAS 115 will not have a material impact on
future results of operations or financial position.
30
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
Report of Independent Public Accountants
- -----------------------------------------------------------------------------
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying balance sheets of The Connecticut Light and
Power Company (a Connecticut corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1993 and 1992, and the related
statements of income, common stockholder's equity and cash flows for each of
the three years in the period ended December 31, 1993. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of The Connecticut Light and
Power Company as of December 31, 1993 and 1992, and the results of its
operations and cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting
principles.
As discussed in <F2> Note 1 to the Financial Statements, "Summary of
Significant Accounting Policies-Accounting Changes," effective January 1, 1993,
The Connecticut Light and Power Company changed its methods of accounting for
property taxes, income taxes, and postretirement benefits other than
pensions.
/s/Arthur Andersen & Co.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
31
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -----------------------------------------------------------------------------
This section contains management's assessment of The Connecticut Light and
Power Company's (CL&P or the company) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This discussion should
be read in conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
The company's net income decreased to $191.4 million in 1993 from $206.7
million in 1992. The 1993 net income reflects the cumulative effect of a
change in the accounting for Connecticut municipal property taxes. The
company adopted a one-time change in the method of accounting for municipal
property tax expense in the first quarter of 1993. This change resulted in a
one-time contribution to net income of $47.7 million.
See the "Notes to Financial Statements" for further information on the
property tax accounting change.
Net income before the cumulative effect of the change in accounting for
property taxes was $143.7 million in 1993. The decrease from 1992 is
primarily attributable to one-time impacts of (a) disallowances ordered by
the Department of Public Utility Control (DPUC) in the 1993 rate case
decision and (b) the $10 million charge to earnings in the third quarter of
1993 for the costs of the company's employee reduction program. Other items
that affected net income in 1993 include increased revenues from the 1993
retail rate increase and the company's continued cost-management efforts.
These increases were offset by higher costs for the recovery of regulatory
deferrals and the higher contribution in 1992 of energy transactions with
other utilities.
The year 1993 was one of both challenge and success for the company. CL&P's
work force was reduced by about 11 percent in 1993 through an employee
reduction program that involved early retirements and involuntary
terminations. The 1993 composite nuclear capacity factor of 80.8 percent was
the highest level the NU system has ever achieved and far above the national
average. The DPUC approved a three-year rate plan that weakened 1993
earnings but will assure CL&P customers rate stability over the next few
years which will help to improve CL&P's future earnings and competitive
position.
In 1994, CL&P will continue to face challenges associated with a lagging
economy and competition. Retail sales for 1993 were flat, as compared to
1992, as a result of a stagnant Connecticut economy. The company expects
retail sales growth of about two percent in 1994, based on some modest
improvement in the economy.
Competition within the electric utility industry is increasing. In response,
CL&P 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. These initiatives are aimed at keeping
customers from either leaving CL&P's retail service territory or replacing
CL&P's electric service with alternative energy sources.
The cost of doing business, including the price of electricity, is higher in
the Northeast than in most other parts of the country. Relatively high state
and local taxes, labor costs, and other costs of doing business in New
England also contribute to competitive disadvantages for many industrial and
commercial customers of CL&P. These disadvantages have aggravated the
pressures on business customers in the current weakened
32
regional economy. Since 1991, the company has worked actively with the
Connecticut Department of Economic Development to package development
incentives for a variety of retail and wholesale customers. These economic
development packages typically include both electric rate discounts and
incentive payments for energy-efficient construction, as well as technical
support and energy conservation services. Targeted reductions in effect at
the end of 1993 to a limited group of large customers were successful in
preserving CL&P revenues of approximately $28 million. The amount of
discounts provided to customers are expected to increase as the company
intensifies its efforts to retain existing customers and gain new customers.
As a result of very limited load growth throughout the Northeast and the
operation of several new generating plants in the past five years, wholesale
competition has grown, and a seller's market for electricity has turned into
a buyer's market. The prices the company has been able to receive for new
wholesale sales have generally been far lower than the prices prevalent in
1988 and 1989. In future years, competition in the Northeast is expected to
increase, putting further downward pressure on prices. However, the
potential price decreases may be offset somewhat by an
improvement in the region's economy as well as by the retirement of a number
of the region's existing generating facilities.
The ability of retail customers to select an electricity supplier and then
force the local electric utility to transmit the power to the customer's site
is known as "retail wheeling". While wholesale wheeling is mandated by the
Energy Policy Act of 1992 under certain circumstances, retail wheeling is
generally not required in the company's jurisdiction. In Connecticut, the
DPUC has begun an investigation into the viability of retail wheeling.
NU management has taken steps to make the NU system companies, including
CL&P, more competitive and profitable in the changing utility environment. A
systemwide emphasis on improved customer service is a central focus of the
reorganization of NU that became effective on January 1, 1994. The
reorganization entails realignment of the system into two new core business
groups. The first core business group is devoted to energy resource
acquisition and wholesale marketing and focuses on nuclear, fossil, and
hydroelectric generation, wholesale power marketing, and new business
development. The second core business group oversees all customer service,
transmission and distribution operations, and retail marketing in
Connecticut, New Hampshire, and Massachusetts. These two core business
groups are served by various support functions.
In connection with NU's reorganization, a corporate reengineering process has
begun which should help the company to identify opportunities to become more
competitive while improving customer service and maintaining excellent
operational performance. NU has aggressive cost-reduction targets over the
next three years, which should enable the company to remain competitive by
reducing prices to vulnerable customers in particular.
To date, the company has not been materially affected by competition, and it
does not foresee substantial adverse effect in the near future, unless the
current regulatory structure is substantially altered. The company believes
the steps it is taking will have significant, positive effects in the next
few years. In addition, CL&P benefits from a diverse retail base. The
company has no significant dependence on any one customer or industry. The
NU system's extensive transmission facilities and diversified generating
capacity are all strong positive factors in the regional wholesale power
market. NU serves about 30 percent of New England's electric needs and is
one of the 20 largest electric utility systems in the country.
Achieving measurable improvement in earnings in 1994, will depend, in part,
on the success of the company's wholesale power marketing customer retention
and reengineering efforts.
33
RATE MATTERS
Deferred charges at December 31, 1993 were $1.5 billion, which includes $1.0
billion for the adoption in 1993 of Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes." Deferred charges,
excluding the regulatory asset for SFAS No. 109 decreased almost $90 million
in 1993. Recoveries for the deferred costs of Millstone 3, Seabrook, and the
Yankee Atomic Electric Company (YAEC) contract obligation and reductions in
deferred energy costs were partially offset by increased deferrals for
conservation and load management costs. The company is currently recovering
some amounts of its remaining deferred charges from customers. Management
expects that substantially all of the deferred charges will be recovered
through future rates.
Under SFAS No. 109, the company reflected a regulatory asset and a deferred
tax liability for the cumulative amount of income taxes associated with
timing differences for which deferred taxes had not been provided but are
expected to be recovered from customers in the future. The adoption of SFAS
No. 109 has not had a material effect on results of operations.
The company also adopted SFAS No. 106, "Employer's Accounting for
Postretirement Benefits Other Than Pensions" in 1993. Adopting SFAS No. 106
has not had a material impact on financial condition or results of
operations, because the company has received approval from the DPUC to defer
these costs and expects to recover these costs in the future.
See the "Notes To Financial Statements" for further details on deferred
charges and recently adopted accounting standards.
On June 16, 1993, the DPUC issued a final decision in CL&P's December 1992
retail rate case (the rate decision) approving a multiyear rate plan which
provides for annual rate increases of $46 million, or 2.01 percent, in July
1993; $47.1 million, or 2.04 percent, in July 1994; and $48.2 million, or
2.06 percent, in July 1995. The total cumulative increase granted of $141.3
million, or 6.1 percent, was approximately 42 percent of CL&P's updated
request.
In light of the State of Connecticut's concern over economic development and
industrial and commercial rates, one important aspect of the rate case was
that industrial and manufacturing rates will only rise by about 1.1 percent
annually over the three year period. Other significant aspects of the rate
decision included the reduction of CL&P's return on equity (ROE) from 12.9
percent to 11.5 percent for the first year of the multiyear plan, 11.6
percent for the second year, and 11.7 percent for the third year; a 32-month
phase-in beginning in 1995 of CL&P's nonpension, postretirement benefit costs
required to be recognized under SFAS No. 106 with amortization of deferred
amounts over five years; the three-year phase-in of the Millstone 2 steam
generators; the deferral of cogeneration expenses with carrying costs of
$42.1 million in fiscal year 1994 and $20.9 million in fiscal year 1995 with
recovery over five years beginning July 1, 1996; and the full recovery of the
remaining costs of the Millstone 3 and Seabrook phase-ins(balance of $185.9
million at December 31, 1993).
The rate decision used $49 million of prior fuel overrecoveries to offset a
similar amount of the unrecovered replacement power costs under CL&P's
Generation Utilization Adjustment Clause (GUAC). The GUAC has been in
operation since 1979 and was designed as a mechanism to recover or to refund
certain fuel costs if the nuclear plants do not operate at a predetermined
capacity factor. In January 1994, the DPUC issued a decision ordering CL&P
not to include a GUAC amount in customers' bills through August 1994. The
DPUC found that CL&P overrecovered its fuel costs during the 1992-1993 GUAC
period and offset the amount of the overrecovery against the unrecovered GUAC
balance. The effect of the order was a disallowance of $7.9 million. The
DPUC further ordered that any GUAC deferred charges subsequent to July 1993
will be offset by any fuel overrecoveries. There is an unrecovered GUAC
balance at December 31, 1993 of $13.7 million but there is not expected to be
an unrecovered balance at the end of the GUAC period in August 1994. The
DPUC's decision creates some uncertainty about the future operation of the
GUAC. CL&P
34
has requested further clarification of the decision, and has appealed it, but
does not expect that the decision will have a material adverse effect on
future results of operations.
The rate decision also required CL&P to allocate to customers a portion of
the property tax accounting change made in the first quarter of 1993, which
resulted in a charge against other income of $10.2 million in the second
quarter of 1993.
In August 1993, two appeals were filed from the DPUC's June 1993 rate
decision. CL&P appealed four issues from the decision. The second appeal
was filed by the Connecticut Office of Consumer Council (OCC) and the City of
Hartford. This appeal challenges the legality of the multi-year plan
accepted by the DPUC. CL&P has filed a motion to dismiss this appeal on
jurisdictional grounds. In addition, the Court rejected the City of
Hartford's and OCC's motion to stay implementation of the second and third
year of the rate plan pending the outcome of their appeal.
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 four of the
reviews. The OCC has appealed decisions favorable to the company in two
dockets. 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 docket is $26 million. The only remaining
nuclear outage prudence docket before the DPUC is the docket established to
review the 1992 nuclear outage at Millstone 2 to replace the steam
generators. A decision is expected in late 1994. Management believes that
its actions with respect to these outages have been prudent, and it does not
expect the outcome of the prudence reviews to result in material
disallowances.
In April 1993, the DPUC issued an order approving a new Conservation
Adjustment Mechanism (CAM), which allowed CL&P to recover Conservation and
Load Management (C&LM) expenditures over an eight-year period (reduced from
ten years) and reaffirmed program performance incentives. In December 1993,
CL&P filed a proposed CAM settlement with the DPUC. The settlement proposes
1994 C&LM expenditures of $39 million, reduction in the recovery period from
8 to 3.85 years and other changes in program designs, performance incentives
and cost recovery. Unrecovered C&LM costs at December 31, 1993, were $111.4
million.
ENVIRONMENTAL MATTERS
The NU system devotes substantial resources to identify and then to meet the
multitude of environmental requirements it faces. The system 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 of its service territory. To date, the
future estimated environmental remediation costs for these sites for which
the company expects some legal liability have not been material with respect
to the earnings or financial position of CL&P. At December 31, 1993, 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 $2.9 million. However, while not probable, it is
reasonably possible that these costs could rise to as much as $5.8 million.
The extent of additional future environmental cleanup costs is not estimable
due to factors such as the unknown magnitude of possible contamination and
changes in existing laws and regulatory practices.
The company expects that the implementation of Phase I of the 1990 Clean Air
Act Amendments will require only modest emissions reductions. CL&P's
exposure is minimal because of its investment in nuclear energy in the 1970s
and 1980s and the burning of low-sulfur fuels. The costs for meeting the
Phase II requirements cannot be estimated at this time because the emission
limits have not been determined.
35
The company's estimated cost of decommissioning its shares of Millstone Units
1, 2, and 3 and Seabrook is approximately $801 million in year end 1993
dollars. In addition, the company's estimated cost to decommission its
shares of the regional nuclear units is estimated to be approximately $185 to
$189 million. Decommissioning costs are recovered and recognized over the
lives of the respective units. YAEC has begun decommissioning its nuclear
facility. The company's estimated obligation to YAEC has been recorded on
its Balance Sheets. Management expects that the company will continue to be
allowed to recover these costs.
For further information regarding nuclear decommissioning, environmental
matters, and other contingencies, see the "Notes to Financial Statements."
NUCLEAR PERFORMANCE
The composite capacity factor of the five nuclear generating units that the
NU system operates (including the Connecticut Yankee nuclear unit) was 80.8
percent for 1993, compared with 63.7 percent in 1992 and a national average
of 70.6 percent for 1993. The lower 1992 capacity factor was primarily the
result of the 1992 Millstone 2 steam generator replacement outage and some
unexpected technical and operating difficulties.
In 1993, NU was informed by the Nuclear Regulatory Commission (NRC) of three
apparent violations related to the circumstances surrounding the repair of a
leaking valve in the reactor coolant system at the Millstone 2 nuclear power
station. Millstone 2 was shutdown on August 5, 1993, when extensive repair
efforts proved unsuccessful and the valve began to leak at a level beyond
operating requirements. NU was assessed and paid a civil penalty of $237,500
for the three violations that were identified during the NRC investigation.
NU has initiated a number of immediate and long-term actions designed to
further enhance the safe operation of all the NU nuclear plants. In an
effort to improve nuclear performance, NU management announced a
reorganization of its Connecticut-based nuclear organization in November
1993. The reorganization, which is based on an overview of NU's future
nuclear operational needs, resulted in a number of personnel changes,
including the appointment of a new senior vice president of Millstone
Station, realignment of engineering operations along unit lines and
management consolidation. In addition, centralization of the nuclear
engineering function at the generating stations is expected to occur during
the summer of 1994. No material expense will be incurred by the company in
connection with the reorganization.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations increased $136.5 million in 1993, compared with
the same period in 1992, primarily due to increased revenues in 1993 from the
rate increase and for the recovery of replacement power costs under the GUAC.
Cash used for financing activities was $219.9 million higher in 1993,
compared with the same period in 1992, primarily due to a net decrease in
short-term debt, long-term debt, and preferred stock. Cash used for
investments was $66.2 million lower in 1993, compared with the same period in
1992, primarily due to lower construction expenditures in 1993.
The company has been able to shift its financing focus to
refinancing
outstanding high-cost securities. Internally generated cash has generally
been, and is projected to continue to be, more than sufficient to cover
construction costs. The forecast through 1998 shows additional new
financings only in years with a large amount of securities maturing. CL&P
may issue up to $200 million in 1994 to finance maturing debt. The company
is obligated to meet $581 million of long-term debt and preferred stock
maturities and cash sinking-fund requirements for the 1994 through 1998
period, including $189 million for 1994. Also, $125 million of First
Mortgage Bonds outstanding at December 31, 1993 has been called in December
1993 for redemption in 1994.
Aggressive refinancing of its outstanding high-cost securities has enabled
the company to lower its cost of debt. There was no new money financing in
1993. To take advantage of favorable market conditions during
36
1993, the company refinanced $425 million of First Mortgage Bonds, $110
million of preferred stock and $135.5 million of pollution control bonds, in
addition to restructuring the company's various credit lines. It is
estimated that the 1993 refinancings and restructuring will save the company
approximately $15 million per year. The company intends, if market
conditions permit, to continue to refinance a portion of its outstanding
long-term debt and preferred stock at lower effective cost.
On February 17, 1994, CL&P issued two new First Mortgage Bonds, the $140
million 1994 Series A and the $140 million 1994 Series B Bonds, at annual
rates of 5.50 percent and 6.125 percent, respectively. The Series A Bond
will mature on February 1, 1999, and the Series B Bond will mature on
February 1, 2004. Proceeds from these issues, together with proceeds from
short-term debt, will be used to redeem $310 million of outstanding bonds
with interest rates ranging from 5.625 percent to 7.625 percent. Savings
from the refinancings are estimated to be approximately $4.5 million per year
in reduced interest rates.
The company's construction program expenditures, including allowance for
funds used during construction (AFUDC), for the period 1994 through 1998 are
estimated to be approximately $742 million, including $158 million for 1994.
The construction program's main focus is maintaining and upgrading the
existing transmission and distribution system as well as the nuclear and
fossil-generating facilities. The company does not foresee the need for new
major generating facilities, at least until the year 2007.
CL&P and WMECO utilize a nuclear fuel trust to finance nuclear fuel
requirements for Millstone 1, 2, and 3. Nuclear fuel requirements, including
nuclear fuel financed through the trust, are estimated to be approximately
$318 million for the period 1994 through 1998, including $75 million for
1994.
37
RESULTS OF OPERATIONS
Change in Operating Revenues
Increase/(Decrease)
- ----------------------------------------------------------------- ------
1993 vs. 1992 1992 vs. 1991
- ----------------------------------------------------------------- ------
(Millions of Dollars)
Regulatory decisions $34.2 $72.7
Fuel and purchased power
cost recoveries 1.9 20.0
Sales volume 3.0 5.4
Other revenues 10.5 (57.4)
----- ------
Total revenue change $49.6 $40.7
===== =====
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table above.
Operating revenues increased $49.6 million from 1992 to 1993. Revenues
related to regulatory decisions increased in 1993, primarily because of the
effects of the June 1993 DPUC retail rate increase and higher revenues under
the CAM. Retail sales were essentially flat in 1993. Other revenues
increased primarily because of higher 1993 capacity interchange sales.
Operating revenues increased $40.7 million from 1991 to 1992. Revenues
related to regulatory decisions increased in 1992 primarily because of the
effect of the August 1991 DPUC retail rate increase. Fuel and purchased-
power cost recoveries increased primarily due to the timing in the recovery
of fuel expenses under the provisions of CL&P's fuel adjustment clauses.
Retail sales in 1992 were slightly higher than 1991. Other revenues
decreased primarily because of 1992 capacity sales to other utilities that
took place at lower prices per kilowatt-hour and the 1991 one-time
reimbursement of costs associated with the reactivation of fossil-generating
units.
FUEL, PURCHASED, AND NET INTERCHANGE POWER
Fuel, purchased, and net interchange power increased $58.8 million in 1993,
as compared to 1992, primarily due to the timing in the recovery of fuel
expenses under the provisions of the company's fuel adjustment clauses and
disallowances of replacement power costs deferred under the GUAC, partially
offset by lower outside purchases due to better nuclear performance in 1993.
Fuel, purchased, and net interchange power increased $39.2 million in 1992,
as compared to 1991, primarily due to the timing in the recovery of fuel
expenses under the provisions of the company's fuel adjustment clauses, and
previously deferred replacement power costs that are not recoverable as a
result of regulatory reviews.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses increased $18.7 million in 1993, as
compared to 1992, primarily due to the one-time costs in 1993 associated with
the employee reduction program and 1993 SFAS No. 106 postretirement benefit
costs prior to the DPUC order allowing the deferral of these costs, partially
offset by lower 1993 costs associated with the operation and maintenance
activities of the nuclear units.
38
Other operation and maintenance expenses increased $4.0 million in 1992, as
compared to 1991, primarily due to higher 1992 costs of operation and
maintenance activities at nuclear units, partially offset by the 1991 costs
associated with a voluntary early retirement program, and lower 1992
conservation expenses.
DEPRECIATION EXPENSES
Depreciation expenses increased $9.9 million in 1993, as compared to 1992,
and $11.3 million in 1992, as compared to 1991, primarily as a result of
higher depreciation rates, higher depreciable plant balances, and higher
decommissioning levels in 1992 as compared to 1991.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased $38.9 million in 1993, as
compared to 1992, and $17.8 million in 1992, as compared to 1991, primarily
because of higher amortization of Millstone 3 and Seabrook deferred costs.
The increase in 1993 is also attributable to the gross-up of taxes due to
SFAS No. 109, and the amortization in 1993 of costs paid by CL&P to the
developers of two wood-to-energy plants as allowed in the recent rate
decision. CL&P was allowed to collect and amortize $17.9 million of
previously deferred costs over the one-year period beginning July 1993.
FEDERAL AND STATE INCOME TAXES
Federal and State income taxes, net decreased $21.4 million in 1993, as
compared to 1992, primarily because of lower book taxable income and higher
investment tax credit amortization, partially offset by an increase in flow-
through depreciation.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5.4 million in 1992, as compared to
1991, primarily due to higher property taxes and higher Connecticut gross
earnings taxes due to higher revenues.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased $10.8 million in 1993, as compared
to 1992, and $6.3 million in 1992, as compared to 1991, primarily because of
a decrease in Millstone 3 deferred return because additional Millstone 3
investment was phased into rates.
OTHER INCOME, NET
Other income, net decreased $8.0 million in 1993, as compared to 1992,
primarily because of the allocation to customers of a portion of the property
tax accounting change as ordered by the DPUC in the rate decision and lower
AFUDC.
INTEREST CHARGES
Interest on long-term debt increased $17.1 million in 1993, as compared to
1992 and $14.9 million in 1992, compared to 1991, primarily because of lower
average interest rates as a result of the substantial refinancing activity.
Other interest charges increased $5.4 million in 1993, as compared to 1992,
primarily because of higher interest on short-term borrowings, lower AFUDC
for borrowed funds and interest recognized for a potential Connecticut sales
tax assessment.
39
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
- -----------------------
SELECTED FINANCIAL DATA
- -----------------------------------------------------------------------------
- -----------------------
- -----------------------------------------------------------------------------
- -----------------------
Years Ended December 31, 1993 1992 1991
1990 1989
- -----------------------------------------------------------------------------
- -----------------------
(Thousands of Dollars)
Continuing Operations:
Operating Revenues. . . . . . $2,366,050 $2,316,451 $2,275,737
$2,170,087 $2,069,559
Operating Income. . . . . . . 240,095 287,811 323,835
320,641 327,220
Net Income. . . . . . . . . . 191,449 206,714 240,818
224,783 207,875
Discontinued Gas
Operations:
Operating Revenues . . . . . - - -
- 124,229
Operating Income . . . . . . - - -
- 12,563
Net Income . . . . . . . . . - - -
- 6,630
Cash Dividends on
Common Stock. . . . . . . . . 160,365 164,277 172,587
179,921 155,972
Total Assets . . . . . . . . . 6,397,380 5,582,806 5,338,441
5,176,784 5,148,120
Long-Term Debt*. . . . . . . . 2,057,280 2,087,936 2,023,268
2,101,334 2,147,892
Preferred Stock Not
Subject to Mandatory
Redemption. . . . . . . . . . 166,200 231,196 306,195
306,195 306,195
Preferred Stock
Subject to Mandatory
Redemption* . . . . . . . . . 230,000 200,000 141,892
146,892 151,892
Obligations Under
Capital Leases* . . . . . . . 177,418 197,404 208,924
233,919 252,652
*Includes portions due within one year.
- -----------------------------------------------------------------------------
- -----------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- -----------------------------------------------------------------------------
- -----------------------
Quarter Ended
- -----------------------------------------------------------------------------
- -----------------------
1993 March 31 June 30 September
30 December 31
- -----------------------------------------------------------------------------
- -----------------------
(Thousands of Dollars)
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
======== ======== ========
========
1992
- -----------------------------------------------------------------------------
- -----------------------
Operating Revenues. . . . . . . $633,933 $547,010 $554,635
$580,873
======== ======== ========
========
Operating Income. . . . . . . . $ 90,840 $ 58,892 $75,438
$ 62,641
======== ======== ========
========
Net Income. . . . . . . . . . . $ 68,042 $ 40,615 $55,145
$ 42,912
======== ======== ========
========
40
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
- -----------------------
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,)
- -----------------------------------------------------------------------------
- -----------------------
1993 $6,214,399 26,107 8,519 1,078,925
2,676
1992 6,100,680 25,809 8,501 1,075,425
3,028
1991 5,986,269 24,992 8,435 1,069,912
3,364
1990 5,881,499 25,039 8,434 1,064,695
3,517
1989 5,732,850 25,078 8,570 1,054,055
3,556
41
The Connecticut Light and Power Company
First and Refunding Mortgage Bonds
----------------------------------
Trustee and Interest Paying Agent
Bankers Trust Company, Corporate Trust and Agency Group
P.O. Box 318, Church Street Station, New York, New York 10015
Preferred Stock
---------------
Transfer Agent, Dividend Disbursing Agent and Registrar
Northeast Utilities Service Company Shareholder Services
P.O. Box 5006, Hartford, CT 06102-5006
1994 Dividend Payment Dates
5.28%, 5.30%, 9.00%, $3.24 Series -
January 1, April 1, July 1, and October 1
4.50% (1956), 4.96%, 6.56%
$1.90, $2.00, $2.04, $2.06, $2.09, and $2.20 Series -
February 1, May 1, August 1, and November 1
3.90%, 4.50% (1963), 7.23% Series -
January 12, March 1, June 1, September 1, and December 1
DARTS*
January 12, March 2, April 20, June 8, July 27,
September 14, November 2, December 21
Address General Correspondence in Care of:
Northeast Utilities Service Company
Investor Relations Department
P.O. Box 270
Hartford, Connecticut 06141-0270
Tel. (203) 665-5000
General Office
Selden Street, Berlin, Connecticut 06037-1616
_________________________
*Transfer and Paying Agent:
Bankers Trust Company, Corporate Trust and Agency Group
P.O. Box 318, Church Street Station, New York, New York 10015
The data contained in this Annual Report is submitted for the sole purpose of
providing information to present stockholders about the Company.