SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDING MARCH 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
NONE
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of March 31, 2000, was 14,334,922.
- 1 -
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three months
ended March 31, 2000 and 1999. 3
Consolidated Balance Sheet as of March 31, 2000 and
December 31, 1999. 4
Consolidated Statement of Cash Flows for the three months
ended March 31, 2000 and 1999. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 7
- Short-term Credit Arrangements 8
- Income Taxes 9
- Supplementary Information 10
- Commitments and Contingencies 11
- Capital Expenditure Program 11
- Nuclear Insurance Contingencies 11
- Other Commitments and Contingencies 11
- Connecticut Yankee 11
- Hydro-Quebec 12
- Environmental Concerns 12
- Site Decontamination, Demolition and Remediation
Costs 12
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 13
- Segment Information 14
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 15
- Major Influences on Financial Condition 15
- Capital Expenditure Program 18
- Liquidity and Capital Resources 18
- Subsidiary Operations 19
- Results of Operations 20
- Looking Forward 24
Item 3. Quantitative and Qualitative Disclosure About Market Risk. 26
PART II. OTHER INFORMATION
Item 1. Legal Proceedings. 27
Item 4. Submission of Matters to a Vote of Security Holders. 27
Item 6. Exhibits and Reports on Form 8-K. 27
SIGNATURES 28
- 2 -
PART I: FINANCIAL INFORMATION
ITEM I: FINANCIAL STATEMENTS
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Thousands except per share amounts)
(Unaudited)
Three Months Ended
March 31,
2000 1999
---- ----
OPERATING REVENUES (NOTE G) $180,977 $168,667
------------- -------------
OPERATING EXPENSES
Operation
Fuel and energy 67,469 33,899
Capacity purchased 1,447 9,062
Other 34,464 38,754
Maintenance 5,071 9,446
Depreciation (Note G) 7,119 17,739
Amortization of regulatory assets 15,804 7,026
Income taxes (Note F) 13,206 15,525
Other taxes (Note G) 11,741 14,009
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Total 156,321 145,460
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OPERATING INCOME 24,656 23,207
------------- -------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 181 13
Other-net (Note G) 2,402 (469)
Non-operating income taxes (Note F) (640) 891
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Total 1,943 435
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INCOME BEFORE INTEREST CHARGES 26,599 23,642
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INTEREST CHARGES
Interest on long-term debt 9,606 12,227
Interest on Seabrook obligation bonds owned by the company (1,618) (1,711)
Dividend requirement of mandatorily redeemable securities 1,203 1,203
Other interest (Note G) 391 1,856
Allowance for borrowed funds used during construction (411) (448)
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9,171 13,127
Amortization of debt expense and redemption premiums 563 614
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Net Interest Charges 9,734 13,741
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NET INCOME 16,865 9,901
Dividends on preferred stock - 51
------------- -------------
INCOME APPLICABLE TO COMMON STOCK 16,865 9,850
============= =============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,069 14,042
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,072 14,044
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $1.20 $0.70
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 3 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
March 31, December 31,
2000 1999*
---- -----
(Unaudited)
Utility Plant at Original Cost
In service $930,875 $1,007,065
Less, accumulated provision for depreciation 461,855 532,409
-------------- ---------------
469,020 474,656
Construction work in progress 26,580 25,708
Nuclear fuel 21,798 21,101
-------------- ---------------
Net Utility Plant 517,398 521,465
-------------- ---------------
Other Property and Investments
Investment in generation facility 79,746 83,494
Nuclear decommissioning trust fund assets 29,568 28,255
Other 22,030 20,098
-------------- ---------------
131,344 131,847
-------------- ---------------
Current Assets
Unrestricted cash and temporary cash investments 21,951 39,099
Restricted cash 28,919 29,223
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 52,741 56,057
Other, less allowance for doubtful accounts
of $525 and $508 63,278 53,612
Accrued utility revenues 21,068 25,019
Fuel, materials and supplies, at average cost 9,754 9,259
Prepayments 6,200 3,056
Other 6,736 4,801
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Total 210,647 220,126
-------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 8,048 8,688
Other 5,786 6,099
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Total 13,834 14,787
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Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Nuclear plant investments-above market 513,149 518,268
Income taxes due principally to book-tax differences 163,599 166,965
Long-term purchase power contracts-above market 140,387 144,406
Connecticut Yankee 35,671 37,013
Unamortized redemption costs 23,143 22,314
Unamortized cancelled nuclear projects 8,487 8,780
Displaced worker protection costs 5,157 5,746
Uranium enrichment decommissioning cost 1,031 1,040
Other 21,234 5,453
-------------- ---------------
Total 911,858 909,985
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$1,785,081 $1,798,210
============== ===============
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
March 31, December 31,
2000 1999*
---- -----
(Unaudited)
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,320 2,253
Capital stock expense (2,170) (2,170)
Unearned employee stock ownership plan equity (9,023) (9,261)
Retained earnings 182,204 175,470
------------------ ----------------
465,337 458,298
Company-obligated mandatorily redeemable securities
of subsidiary holding solely parent debentures 50,000 50,000
Long-term debt
Long-term debt 604,800 605,641
Investment in Seabrook obligation bonds (82,635) (87,413)
------------------ ----------------
Net long-term debt 522,165 518,228
------------------ ----------------
Total 1,037,502 1,026,526
------------------ ----------------
Noncurrent Liabilities
Purchase power contract obligation 140,387 144,406
Nuclear decommissioning obligation 29,568 28,255
Connecticut Yankee contract obligation 25,565 27,056
Pensions accrued 15,110 19,026
Obligations under capital leases 16,032 16,131
Other 10,646 10,394
------------------ ----------------
Total 237,308 245,268
------------------ ----------------
Current Liabilities
Current portion of long-term debt 859 25,000
Notes payable 14,121 17,131
Accounts payable 33,715 49,069
Accounts payable - APS customers 62,069 56,220
Dividends payable 10,130 10,125
Taxes accrued 11,240 2,570
Interest accrued 12,266 8,433
Obligations under capital leases 383 375
Other accrued liabilities 42,672 39,421
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Total 187,455 208,344
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Customers' Advances for Construction 1,873 1,867
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Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Accumulated deferred investment tax credits 15,070 15,157
Deferred gains on sale of property 15,901 15,901
Customer refund 18,554 18,381
Other 2,924 2,543
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Total 52,449 51,982
------------------ ----------------
Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
TO TAXING AUTHORITIES) 268,494 264,223
Commitments and Contingencies (Note L)
------------------ ----------------
$1,785,081 $1,798,210
================== ================
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 5 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Three Months Ended
March 31,
2000 1999
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $16,865 $9,901
------------ -----------
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 16,602 22,466
Deferred income taxes 5,415 (732)
Deferred investment tax credits - net (87) (190)
Amortization of nuclear fuel 1,890 3,191
Allowance for funds used during construction (592) (461)
CTA and SBC revenue adjustment (9,528) -
Amortization of deferred return - 3,147
Changes in:
Accounts receivable - net (6,350) 11,113
Fuel, material and supplies (495) (427)
Prepayments (3,144) (5,044)
Accounts payable (9,505) (32,481)
Interest accrued 3,833 3,905
Taxes accrued 8,670 14,425
Other assets and liabilities 2,500 (9,818)
------------ -----------
Total Adjustments 9,209 9,094
------------ -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 26,074 18,995
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 304 300
Notes payable (3,010) (4,720)
Securities redeemed and retired:
Long-term debt (25,750) (86,202)
Lease obligations (91) (85)
Dividends
Preferred stock - (51)
Common stock (10,125) (10,104)
------------ -----------
NET CASH USED IN FINANCING ACTIVITIES (38,672) (100,862)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (9,632) (5,784)
Investment in debt securities 4,778 5,447
------------ -----------
NET CASH USED IN INVESTING ACTIVITIES (4,854) (337)
------------ -----------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (17,452) (82,204)
BALANCE AT BEGINNING OF PERIOD 68,322 124,501
------------ -----------
BALANCE AT END OF PERIOD 50,870 42,297
LESS: RESTRICTED CASH 28,919 26,503
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BALANCE: UNRESTRICTED CASH AND TEMPORARY CASH INVESTMENTS $21,951 $15,794
============ ===========
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $2,608 $6,306
============ ===========
Income taxes $2,000 $3,700
============ ===========
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 6 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The consolidated financial statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all adjustments that are, in the opinion of management, necessary to a fair
statement of the results for the periods presented. All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations. The Company believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year ended December 31, 1999. Such notes are supplemented as
follows:
(A) STATEMENT OF ACCOUNTING POLICIES
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The weighted average AFUDC rate applied in the first three months of 2000
and 1999 was 7.5% and 7.0%, respectively, on a before-tax basis.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $997,000 and $666,000 in the first three
months of 2000 and 1999, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 2000, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$21.7 million and $7.9 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
(B) CAPITALIZATION
COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at March 31, 2000, of which 265,434 shares were unallocated shares
held by The United Illuminating Company 401(k)/Employee Stock Ownership Plan
(KSOP) and not recognized as outstanding for accounting purposes.
In 1990, the Company's Board of Directors and the shareowners approved a
stock option plan for officers and key employees of the Company. Options to
purchase 3,500 shares of stock at an exercise price of $30 per share, 7,800
shares of stock at an exercise price of $39.5625 per share, and 5,000 shares of
stock at an exercise price of $42.375 per share have been granted by the Board
of Directors and remained outstanding at March 31, 2000. No options were
exercised during the first quarter ended March 31, 2000.
- 7 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the awarding of options to purchase up to 650,000 shares of the Company's
common stock over periods of from one to ten years following the dates when the
options are granted. The exercise price of each option cannot be less than the
market value of the stock on the date of the grant. On June 28, 1999, the
Company's shareowners approved the plan. Options to purchase 132,000 shares of
stock at an exercise price of $43.21875 per share and 186,900 shares of stock at
an exercise price of $39.40625 per share have been granted by the Board of
Directors and remained outstanding at March 31, 2000. No options to purchase
shares of the Company's common stock can be exercised without the approval of
the DPUC; and, as of March 31, 2000, the Company had not requested approval by
the DPUC.
The Company has entered into an arrangement under which it loaned $11.5
million to the KSOP. The trustee for the KSOP used the funds to purchase shares
of the Company's common stock in open market transactions. The shares will be
allocated to employees' KSOP accounts, as the loan is repaid, to cover a portion
of the Company's required KSOP contributions. The loan will be repaid by the
KSOP over a twelve-year period, using the Company's contributions and dividends
paid on the unallocated shares of the stock held by the KSOP. As of March 31,
2000, 265,434 shares, with a fair market value of $10.4 million, had been
purchased by the KSOP and had not been committed to be released or allocated to
KSOP participants.
RETAINED EARNINGS RESTRICTION
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$124.1 million were free from such limitations at March 31, 2000.
LONG-TERM DEBT
On December 16, 1999, the Company borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $25 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will be required to pay, when due, the principal of
and the premium, if any, and interest on the PCRRBs. The PCRRBs will mature in
2029, and their interest rate is fixed at 5.4% for the three-year period ending
December 1, 2002. At December 31,1999, these proceeds were held by a trustee and
were recognized as cash and long-term debt on the Consolidated Balance Sheet. On
January 15, 2000, the Company used the proceeds of this $25 million borrowing to
redeem and repay $25 million of 8.0%, 1989 Series A, Pollution Control Revenue
Bonds, an outstanding series of tax-exempt bonds on which the Company also had a
payment obligation to a trustee for the bondholders. Expenses associated with
this transaction, including redemption premiums totaling $750,000 and other
expenses of approximately $417,000, were paid by the Company.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London. If a material adverse change in the business, operations, affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries, on a consolidated basis, should occur, the banks may decline to
lend additional money to the Company under this revolving credit agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and payable. As of March 31, 2000, the Company had $14 million in
short-term borrowings outstanding under this facility.
- 8 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(F) INCOME TAXES
Three Months Ended
March 31,
2000 1999
---- ----
(000's)
Income tax expense consists of:
Income tax provisions:
Current
Federal $6,862 $12,337
State 1,656 3,219
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Total current 8,518 15,556
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Deferred
Federal 4,651 (154)
State 764 (578)
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Total deferred 5,415 (732)
------------- -------------
Investment tax credits (87) (190)
------------- -------------
Total income tax expense $13,846 $14,634
============= =============
Income tax components charged as follows:
Operating expenses $13,206 $15,525
Other income and deductions - net 640 (891)
------------- -------------
Total income tax expense $13,846 $14,634
============= =============
The following table details the components
of the deferred income taxes:
Seabrook sale/leaseback transaction ($1,997) ($2,082)
Pension benefits 1,548 1,525
Accelerated depreciation (353) 1,250
Tax depreciation on unrecoverable plant investment 23 1,188
Unit overhaul and replacement power costs (454) (898)
Conservation and load management (27) (873)
Postretirement benefits (92) (433)
Displaced worker protection costs (235) -
Bond redemption costs 184 (256)
Cancelled nuclear plant (117) (117)
Restructuring costs 2,330 -
SBC and CTA accrual 3,799 -
Other - net 806 (36)
------------- -------------
Deferred income taxes - net $5,415 ($732)
============= =============
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
Three Months Ended
March 31,
2000 1999
---- ----
(000's)
Operating Revenues
- ------------------
Retail $148,941 $152,391
Wholesale 18,614 13,593
CTA and SBC revenue 9,528 -
Other 3,894 2,683
------------- -------------
Total Operating Revenues $180,977 $168,667
============= =============
Sales by Class(MWH's)
- --------------------
Retail
Residential 537,082 533,768
Commercial 574,772 553,798
Industrial 277,019 269,060
Other 13,325 12,199
------------- -------------
1,402,198 1,368,825
Wholesale 625,005 652,746
------------- -------------
Total Sales by Class 2,027,203 2,021,571
============= =============
Depreciation
- ------------
Plant in Service $6,121 $14,655
Amortization of Conservation and
Load Management Costs - 2,418
Nuclear Decommissioning 998 666
------------- -------------
$7,119 $17,739
============= =============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $6,388 $5,854
Local real estate and personal property 3,849 6,326
Payroll taxes 1,504 1,829
------------- -------------
11,741 14,009
Nonoperating and other accounts 120 134
------------- -------------
Total Other Taxes $11,861 $14,143
============= =============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $287 $667
Equity earnings from Connecticut Yankee 149 181
Earnings (Loss) from subsidiary companies-before tax 2,210 (1,206)
Miscellaneous other income and (deductions) - net (244) (111)
------------- -------------
Total Other Income and (Deductions) - net $2,402 ($469)
============= =============
Other Interest Charges
- ----------------------
Notes Payable $312 $1,284
Other 79 572
------------- -------------
Total Other Interest Charges $391 $1,856
============= =============
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $195.2 million, excluding AFUDC, for 2000 through 2004.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate 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 resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the two operating nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $17.8 million per incident. However, any
assessment would be limited to $2.1 million per incident per year.
The Nuclear Regulatory Commission requires each operating nuclear
generating unit to obtain property insurance coverage in a minimum amount of
$1.06 billion and to establish a system of prioritized use of the insurance
proceeds in the event of a nuclear incident. The system requires that the first
$1.06 billion of insurance proceeds be used to stabilize the nuclear reactor to
prevent any significant risk to public health and safety and then for
decontamination and cleanup operations. Only following completion of these tasks
would the balance, if any, of the segregated insurance proceeds become available
to the unit's owners. For each of the two operating nuclear generating units in
which the Company has an interest, the Company is required to pay its ownership
and/or leasehold share of the cost of purchasing such insurance. Although each
of these units has purchased $2.75 billion of property insurance coverage,
representing the limits of coverage currently available from conventional
nuclear insurance pools, the cost of a nuclear incident could exceed available
insurance proceeds. Under those circumstances, the nuclear insurance pools that
provide this coverage may levy assessments against the insured owner companies
if pool losses exceed the accumulated funds available to the pool. The maximum
potential assessments against the Company with respect to losses occurring
during current policy years are approximately $3.0 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee.
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from the Company. In December of
1996, Connecticut Yankee filed decommissioning cost estimates and amendments to
the power contracts with its owners with the Federal Energy Regulatory
Commission (FERC). Based on regulatory precedent, this filing seeks confirmation
that Connecticut Yankee will continue to collect from its owners its
decommissioning costs, the unrecovered investment in the Connecticut Yankee Unit
and other costs associated with the permanent shutdown of the Connecticut Yankee
Unit. On August 31, 1998, a FERC Administrative Law Judge (ALJ) released an
initial decision regarding Connecticut
- 11 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Yankee's December 1996 filing. The initial decision contains provisions that
would allow Connecticut Yankee to recover, through the power contracts with its
owners, the balance of its net unamortized investment in the Connecticut Yankee
Unit, but would disallow any return on equity for Connecticut Yankee. The ALJ's
decision also states that decommissioning cost collections by Connecticut
Yankee, through the power contracts, should continue to be based on a
previously-approved estimate until a new, more reliable estimate has been
prepared and tested. During October of 1998, Connecticut Yankee and its owners
filed briefs setting forth exceptions to the ALJ's initial decision. If the
initial decision is upheld by the FERC, Connecticut Yankee could be required to
write off a portion of the regulatory asset on its balance sheet associated with
the retirement of the Connecticut Yankee Unit. In this event, however, the
Company would not be required to record any write-off on account of its 9.5%
ownership share in Connecticut Yankee, because the Company has recorded its
regulatory asset associated with the retirement of the Connecticut Yankee Unit
net of any return on equity. On April 7, 2000, Connecticut Yankee reached a
settlement agreement with the Connecticut Department of Public Utility Control
and the Connecticut Office of Consumer Counsel (two of the intervenors in the
FERC proceeding). Under this agreement, Connecticut Yankee would be allowed by
the FERC to earn a return on equity of 6% from the date of acceptance of the
settlement by the FERC. The settlement agreement also stipulates a new
decommissioning cost estimate for the Connecticut Yankee Unit for purposes of
FERC-approved decommissioning cost collections by Connecticut Yankee through the
power contracts with the unit's owners. This agreement has been submitted to the
FERC, but the Company is unable to predict, at this time, the outcome of the
FERC proceeding.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.1
million) and return on investment (approximately $3.7 million) at March 31,
2000, is approximately $25.6 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. The
Company is obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. As of March 31, 2000, the Company's
guarantee liability for this debt was approximately $6.0 million.
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water quality, hazardous waste handling and
disposal, toxic substances, and electric and magnetic fields, the Company may
incur substantial capital expenditures for equipment modifications and
additions, monitoring equipment and recording devices, and it may incur
additional operating expenses. The total amount of these expenditures is not now
determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.5 million had been incurred as of March 31, 2000, and that the
value of the property following remediation will not exceed $6.0 million. As a
result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The
- 12 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
remediation costs, property value and recovery from customers will be subject to
true-up in the Company's next retail rate proceeding based on actual remediation
costs and actual gain on the Company's disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities. In
addition, the Company is currently replacing the bulkhead that surrounds this
site, at an estimated cost of $13.5 million. Of this amount, $4.2 million
represents the portion of the costs to protect the Company's transmission
facilities and will be capitalized as plant in service. The remaining estimated
cost of $9.3 million was expensed in 1999. The Company has agreed to convey to
an unaffiliated entity, Quinnipiac Energy, LLC, (QE) the entire English Station
site, reserving to the Company permanent easements for the operation of its
transmission facilities on the site. This transaction is subject to the parties
obtaining various regulatory approvals, which are being sought. If the site is
conveyed to QE, the Company will fund 61% (approximately $460,000) of the
environmental remediation costs that will be incurred by QE to bring the site
into compliance with applicable Connecticut minimum standards following the
conveyance.
The Company has sold its Bridgeport Harbor Station and New Haven Harbor
Station generating plants in compliance with Connecticut's electric utility
industry restructuring legislation. Environmental assessments performed in
connection with the marketing of these plants indicate that substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable Connecticut minimum standards following their sale.
The purchaser of the plants has agreed to undertake and pay for the major
portion of this remediation. However, the Company will be responsible for
remediation of the portions of the plant sites that will be retained by it.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $565 million (in 2000 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $99 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. The Company's share of the decommissioning payments
made during the first quarter of 2000 was $0.8 million. The Company's share of
the fund at March 31, 2000 was approximately $21.7 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $619 million (in 2000 dollars), of which the
Company's share would be approximately $23 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). The Company's share of the Millstone Unit 3 decommissioning
payments made during the first quarter of 2000 was $0.2 million. The Company's
share of the fund at March 31, 2000 was approximately $7.9 million. The current
decommissioning cost estimate for the Connecticut Yankee Unit, assuming the
prompt removal and dismantling of the unit, is $498 million, of which the
Company's share would be $47 million. Through March 31, 2000, $183 million has
been expended for decommissioning. The projected remaining decommissioning cost
is $315 million, of which the Company's share would be $30 million. The
decommissioning trust fund for the Connecticut Yankee Unit is also managed by
NU. For the Company's 9.5% equity ownership in Connecticut Yankee,
decommissioning costs of $0.6 million were funded by the Company during the
first quarter of 2000, and the Company's share of the fund at March 31, 2000 was
$18.6 million.
- 13 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(P) SEGMENT INFORMATION
The Company has one reportable operating segment, that of regulated
generation, distribution and sale of electricity. The accounting policies used
for that segment do not differ from those used for nonreportable operating
segments. Revenues from inter-segment transactions are not material and all of
the Company's revenues are derived in the United States.
The revenues from external customers, interest income, interest expense and
depreciation charges of the one reportable segment are identical to the amounts
shown on the Consolidated Statement of Income for each year presented. Income
before taxes of the reportable segment is not materially different from that of
the Company as a whole.
The following table reconciles the total assets of the reportable segment
with the total assets shown on the Consolidated Balance Sheet at March 31, 2000
and December 31, 1999:
MARCH 31, DECEMBER 31,
2000 1999
---- ----
(000's)
Total Assets - Regulated Utility $1,785,651 $1,809,451
Total Assets - Unregulated Subsidiaries 201,470 194,642
Total Assets - Elimination (202,040) (205,883)
--------- ---------
Total Consolidated Assets $1,785,081 $1,798,210
========== =========
- 14 -
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its utility retail sales and the Company's ability to control expenses,
as well as on the performance of the non-regulated businesses of the Company's
subsidiaries. The two primary factors that affect utility sales volume are
economic conditions and weather. Total utility operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, declined
by 1.6% annually, on average, during the five years 1995-1999.
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and
regulations.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of assets, and one-third retained as earnings.
The Rate Plan includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999, the DPUC issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates, as directed by the Restructuring Act described in detail below.
These standard offer customer rates are in effect for the period 2000-2001 and
supercede the rate reductions for this period that were included in the Rate
Plan. The decision also reduced the required amount of accelerated amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect through 2001. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. As a result of the Act, the business of
generating and selling electricity directly to consumers is opened to
competition. These business activities are separated from the business of
delivering electricity to consumers, also known as the transmission and
distribution business. The business of delivering electricity remains with the
incumbent franchised utility companies (including the Company), which continue
to be regulated by the DPUC as Distribution Companies. Since mid-1999,
Distribution Companies have been required to separate on consumers' bills the
electricity generation services component from the charge for delivering the
electricity and all other charges.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge." The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
- 15 -
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, the Company must
attempt to divest its ownership interests in its nuclear-fueled power plants
prior to 2004. On October 1, 1998, in its "unbundling plan" filing with the DPUC
under the Restructuring Act, and in other regulatory dockets, the Company stated
that it plans to divest its nuclear generation ownership interests (17.5% of
Seabrook Unit 1 in New Hampshire and 3.685% of Millstone Station Unit 3 in
Connecticut) by the end of 2003, in accordance with the Restructuring Act. On
April 19, 2000 the DPUC approved the Company's plan for divesting its ownership
interest in Millstone Unit 3 by participation in an auction process to be
conducted by a consultant selected by the DPUC. On April 26, 2000, the DPUC
selected J. P. Morgan & Co. to conduct this auction, which is expected to be
concluded by the end of 2000. It is currently estimated that obtaining requisite
regulatory approvals of the auction results and consummating the sale will
require at least an additional six months. The divestiture process for Seabrook
Unit 1 has not yet been determined.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This is to be achieved by a corporate restructuring
of the Company and its unregulated subsidiaries into a holding company
structure. In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company will be converted into a share of common stock of the holding
company. As soon as this becomes effective, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. In a
decision dated May 19, 1999, the DPUC approved the proposed corporate
restructuring. At a special meeting of the Company's shareowners, held on March
17, 2000, the shareowners voted to approve the restructuring. In an order issued
March 31, 2000, the Federal Energy Regulatory Commission authorized the proposed
corporate restructuring. An application is pending before the Nuclear Regulatory
Commission seeking its consent to the proposed corporate restructuring.
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets,
including the results of the Company's divestiture of its ownership interests in
Millstone Unit 3 and Seabrook Unit 1, in accordance with the Restructuring Act.
The Connecticut Office of Consumer Counsel, the statutory representative of
consumer interests in public utility matters, appealed to the Connecticut
Superior Court from the DPUC decision, challenging the DPUC's determination of
the minimum bid price to be used in the auctions of Millstone Unit 3 and
Seabrook Unit 1 ownership interests. On May 2, 2000, the Company entered into a
settlement agreement with the Office of Consumer Counsel and the DPUC staff
resolving the issue raised in this Superior Court appeal; and the agreement has
been submitted to the DPUC for its consideration and approval. If the DPUC
approves the settlement agreement, the Superior Court appeal will be withdrawn.
- 16 -
Under the Restructuring Act, retail customers representing a total of up
to 35% of the Company's retail customer load became able to choose their power
supply providers on and after January 1, 2000, and all of the Company's
customers will be able to choose their power supply providers as of July 1,
2000. On and after January 1, 2000 and through December 31, 2003, the Company is
required to offer fully-bundled "standard offer" electric service, under
regulated rates, to all customers who do not choose an alternate power supply
provider. The standard offer rates must include the fully-bundled price of
generation, transmission and distribution services, the competitive transition
assessment, the systems benefits charge and the conservation and renewable
energy charges. The fully-bundled standard offer rates must also be at least 10%
below the average fully-bundled prices in 1996.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates would be under the Restructuring Act. On July 27,
1999, the Company and Enron Capital & Trade Resources Corp. (ECTR), an affiliate
of Enron Corp., of Houston, Texas (Enron) filed with the DPUC a joint
stipulation and settlement proposal to resolve simultaneously all of the issues
in the Company's standard offer rate proceeding. The proposal included an
arrangement between the Company and ECTR whereby ECTR would supply the
generation services needed by the Company to meet its standard offer obligations
for the four-year standard offer period, and an assumption by ECTR of all of the
Company's long-term purchased power agreement (PPA) obligations. The stipulation
and settlement proposal also provided for the Company's standard offer rates at
a fully-bundled level complying with the 10% reduction required by the
Restructuring Act, including the generation services component of these rates,
the Company's stranded costs for purposes of future recovery, the competitive
transition assessment, systems benefits charge, delivery (transmission and
distribution) charges, and conservation, load management and renewable energy
charges. In its decision, dated October 1, 1999, on the Company's standard offer
rates, the DPUC approved elements of the stipulation and settlement proposal,
including the arrangements with ECTR, subject to specified changes, including
changes in the level of the generation services component of customers' rates.
On October 15, 1999, the Company filed its standard offer rates in compliance
with the DPUC's decision, and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal. These filings were approved by the DPUC on
December 9, 1999 and, on December 28, 1999, the Company and Enron Power
Marketing, Inc. (EPMI), another affiliate of Enron, entered into a Wholesale
Power Supply Agreement, a PPA Entitlements Transfer Agreement and related
agreements documenting the approved four-year standard offer power supply
arrangement and the assumption of all of the Company's PPAs, effective January
1, 2000. The agreements with EPMI also include a financially settled contract
for differences related to certain call rights of EPMI and put rights of the
Company with respect to the Company's entitlements in Seabrook Unit 1 and in
Millstone Unit 3, and the Company's provision to EPMI of certain ancillary
products and services associated with those nuclear entitlements, which
provisions terminate at the earlier of December 31, 2003 or the date that the
Company sells its nuclear interests. The agreements do not restrict the
Company's right to sell to third parties the Company's ownership interests in
those nuclear generation units or the generated energy actually attributable to
its ownership interests. The Office of Consumer Counsel has appealed to the
Connecticut Superior Court from the DPUC's standard offer decision, challenging
the DPUC's determination of the Company's average fully-bundled prices in 1996
rates from which a 10% reduction is required by the Restructuring Act. The
Company and the Connecticut Attorney General are contesting this court challenge
of the DPUC's decision. The Company is unable to predict, at this time, the
outcome of this Superior Court appeal.
- 17 -
CAPITAL EXPENDITURE PROGRAM
The Company's 2000-2004 estimated capital expenditure program, excluding
allowance for funds used during construction, is presently budgeted as follows:
2000 2001 2002 2003 2004 TOTAL
---- ---- ---- ---- ---- -----
(000's)
Nuclear Generation (1) $ 2,817 $ 3,624 $ - $ - $ - $ 6,441
Distribution and Transmission 39,007 31,396 17,240 14,516 31,915 134,074
Other 3,300 - - - - 3,300
------ ------ ------ ------ ------ -------
Subtotal 45,124 35,020 17,240 14,516 31,915 143,815
Nuclear Fuel 8,920 6,962 2,837 8,274 - 26,993
------ ------ ------ ------ ------ -------
Total Utility Expenditures 54,044 41,982 20,077 22,790 31,915 170,808
Total Non-Regulated Business
Expenditures 7,788 4,564 3,864 4,038 4,167 24,421
------ ------ ------ ------ ------ -------
Total $61,832 $46,546 $23,941 $26,828 $36,082 $195,229
======= ======= ======= ======= ======= ========
(1) The Connecticut Restructuring Act and decisions of the Connecticut DPUC do
not allow for the capitalization of nuclear generation costs, other than
for nuclear fuel, beyond 2001.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2000, the Company had $50.9 million of cash and temporary cash
investments, a decrease of $17.4 million from the corresponding balance at
December 31, 1999. The components of this decrease, which are detailed in the
Consolidated Statement of Cash Flows, are summarized as follows:
(Millions)
Balance, December 31, 1999 $68.3
----
Net cash provided by operating activities 26.1
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (28.6)
- Dividend payments (10.1)
Investment in debt securities 4.8
Cash invested in plant, including nuclear fuel (9.6)
----
Net Change in Cash (17.4)
----
Balance, March 31, 2000 $50.9
=====
- 18 -
The Company's capital requirements are presently projected as follows:
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year (1) $39.1 $ - $ - $ - $ -
Internally Generated Funds less Dividends (2) 78.2 81.1 83.5 90.9 71.1
---- ---- ---- ---- ----
Subtotal 117.3 81.1 83.5 90.9 71.1
Less:
Utility Capital Expenditures (2) 54.0 42.0 20.1 22.8 31.9
Non-Regulated Business Capital Expenditures (2) 7.8 4.6 3.9 4.0 4.2
---- ---- ---- ---- ----
Cash Available to pay Debt Maturities and Redemptions 55.5 34.5 59.5 64.1 35.0
Less:
Maturities and Mandatory Redemptions - - 100.0 100.0 -
Optional Redemptions 75.0 - - - -
Repayment of Short-Term Borrowings 17.0 - - - -
---- ---- ----- ----- ----
External Financing Requirements (Surplus) (2) $36.5 $(34.5) $ 40.5 $35.9 $(35.0)
==== ==== ==== ==== ====
(1) Excludes $2.3 million Seabrook Unit 1 operating deposit and restricted cash
of American Payment Systems, Inc. of $26.9 million.
(2) Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections. All of these estimates are subject to change due to
future events and conditions that may be substantially different from those
used in developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $60
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
additional short-term and long-term debt. The continued availability of these
methods of financing will be dependent on many factors, including conditions in
the securities markets, economic conditions, and the level of the Company's
income and cash flow.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London. If a material adverse change in the business, operations, affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries, on a consolidated basis, should occur, the banks may decline to
lend additional money to the Company under this revolving credit agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and payable. As of March 31, 2000, the Company had $14 million in
short-term borrowings outstanding under this facility.
SUBSIDIARY OPERATIONS
The Company has one wholly-owned subsidiary, United Resources, Inc. (URI),
that serves as the parent corporation for several unregulated businesses, each
of which is incorporated separately to participate in business ventures that
will complement the Company's regulated electric utility business and provide
long-term rewards to the Company 's shareowners.
- 19 -
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
RESULTS OF OPERATIONS
FIRST QUARTER OF 2000 VS. FIRST QUARTER OF 1999
- -----------------------------------------------
GENERAL IMPACTS OF CONNECTICUT'S RESTRUCTURING ACT ON FINANCIAL REPORTS
- -----------------------------------------------------------------------
On April 16, 1999, the Company completed the sale of its operating
fossil-fueled generating plants that was required by Connecticut's electric
utility industry restructuring legislation. On October 1, 1999, the Department
of Public Utility Control (DPUC) issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates (about 6% below 1999 rates), as directed by Connecticut's
Restructuring Act. As a result of these two and other associated events, the
"geography" of the Company's costs, particularly with respect to comparisons
between the first quarter of 2000 and the first quarter of 1999, and the
quarterly pattern of revenues and earnings comparing 2000 to 1999 have changed.
This particularly relates to retail pricing patterns, wholesale revenue and
expense, other operating revenues, retail purchased energy and fossil fuel
expenses, operation and maintenance expense, depreciation and property taxes.
For example, increased purchased energy expenses are more than offset by
portions of the decreases in miscellaneous operation and maintenance expense,
depreciation and property taxes, due to the sale of generating plants. The
results of these changes are explained below, and in the "Quarterly Earnings
Pattern for 2000" portion of the LOOKING FORWARD section.
FIRST QUARTER OF 2000 VS. FIRST QUARTER OF 1999
- -----------------------------------------------
Earnings for the first quarter of 2000 were $16.9 million, or $1.20 per
share (on both a basic and diluted basis), up $7.0 million, or $.50 per share,
from the first quarter of 1999. Excluding a one-time item recorded in the first
quarter of 1999, earnings from operations (on both a basic and diluted basis),
were up $7.6 million, or $.54 per share, from the first quarter of 1999. The
earnings from operations contribution of utility operations, excluding the
Nuclear Division, was $.97 per share in the first quarter of 2000. The Nuclear
Division contributed $.22 per share, for a total utility contribution of $1.19
per share, compared to $.71 per share in the first quarter of 1999. The
Company's non-regulated businesses earned $.01 per share in the first quarter of
2000, compared to a loss of $.05 per share in the first quarter of 1999.
The utility earnings increase was attributable to increased sales, both
retail and wholesale, expense reductions, and a shift in the quarterly earnings
pattern that is estimated to have added about $.20 per share to the first
quarter of 2000 compared to the first quarter of 1999.
The one-time item recorded in the first quarter of 1999 was: EPS
------------------ ----------------------------------------- ---------------
1999 Quarter 1 Purchased power expense refund $ .12
Sharing due to refund $(.08)
------------------ ----------------------------------------- ---------------
Utility Earnings from Operations
- --------------------------------
Overall, retail revenue decreased by $3.5 million in the first quarter of
2000 compared to the first quarter of 1999. Retail revenues from operations
decreased by $4.5 million for the reasons shown below. Retail revenues
- 20 -
applicable to a one-time item increased by $1.0 million because of 1999
"sharing" required under the current regulatory structure as applied to the
one-time item recorded in the first quarter of 1999.
- ---------------------------------------------------------------- -------------- ------------- ---------
From From
Retail Revenues: $ millions Operations One-time Total
- ---------------------------------------------------------------- -------------- ------------- ---------
Revenue from:
- ---------------------------------------------------------------- -------------- ------------- ---------
Sharing: for 1999 one-time item 0.0 1.0 1.0
- ---------------------------------------------------------------- -------------- ------------- ---------
Estimate of operating Distribution Division component of
"real" retail sales growth, up 1.3% 0.7 0.0 0.7
- ---------------------------------------------------------------- -------------- ------------- ---------
Estimate of operating Distribution Division component of
"leap year day" retail sales growth, up 1.1% 0.6 0.0 0.6
- ---------------------------------------------------------------- -------------- ------------- ---------
Estimate of operating Distribution Division component of
weather effect on retail sales 1.1 0.0 1.1
- ---------------------------------------------------------------- -------------- ------------- ---------
Estimate of operating Distribution Division component o
price reduction (2.8) 0.0 (2.8)
- ---------------------------------------------------------------- -------------- ------------- ---------
Other retail price reduction, mix of sales and other (see
other operating revenues) (4.1) 0.0 (4.1)
- ---------------------------------------------------------------- -------------- ------------- ---------
TOTAL RETAIL REVENUE (4.5) 1.0 (3.5)
- ---------------------------------------------------------------- -------------- ------------- ---------
Retail fuel and energy expense increased by $39.6 million in the first
quarter of 2000 compared to the first quarter of 1999. The Company's operating
fossil-fueled generation units were sold on April 16, 1999, and the Company
receives, and will receive through 2003, its standard offer service requirements
through purchased power agreements. These costs are recovered through the
Generation Service Charge (GSC) portion of unbundled rates.
Wholesale sales margin increased by $13.7 million in the first quarter of
2000 compared to the first quarter of 1999. Margin from the Nuclear Division,
which was incorporated in retail rates in 1999, increased by $14.2 million. The
Company's operating nuclear assets, Seabrook and Millstone 3, supply power
solely to the wholesale market in 2000. Overall, the Nuclear Division produced
earnings of $.22 per share in the first quarter of 2000, reflecting the
wholesale sales margin less operations and maintenance and other costs,
including taxes. See the LOOKING FORWARD section for more details. There was
margin of $0.5 million from general wholesale activities in the first quarter of
1999.
Other operating revenues increased by $10.7 million in the first quarter of
2000 compared to the first quarter of 1999. Accrued revenues for the Competitive
Transition Assessment (CTA) and the System Benefits Charge (SBC) of $8.7 million
and $0.9 million, respectively, were recorded in the first quarter of 2000.
These revenues true-up the CTA and SBC equity returns to 11.5% and, as a
consequence, compensate for variances in other retail revenues shown in the
table above. See the LOOKING FORWARD section for more details. Other operating
revenues also include transmission revenues from the New England Power Pool
(NEPOOL), which increased by $1.3 million in the first quarter of 2000 compared
to the first quarter of 1999, and were mostly offset by an increase in
transmission operation expense.
- 21 -
Operating expenses for operations, maintenance and purchased capacity
decreased by $16.3 million in the first quarter of 2000 compared to the first
quarter of 1999. The principal components of these expense changes include:
$millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Cogeneration (see Note A) (7.0)
- --------------------------------------------------------------------- ----------
Other purchases (0.6)
- --------------------------------------------------------------------- ----------
TOTAL CAPACITY EXPENSE (7.6)
- --------------------------------------------------------------------- ----------
Operating Distribution Division O&M expense:
- --------------------------------------------------------------------- ----------
1999 fossil generation unit operating and maintenance costs (5.6)
- --------------------------------------------------------------------- ----------
Pension and other employee benefit costs (3.4)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 0.8
- --------------------------------------------------------------------- ----------
Other (3.0)
- --------------------------------------------------------------------- ----------
TOTAL OPERATING DISTRIBUTION DIVISION (11.2)
- --------------------------------------------------------------------- ----------
Other unbundled components of O&M expense:
- --------------------------------------------------------------------- ----------
Nuclear Division (see Note B) (2.2)
- --------------------------------------------------------------------- ----------
Conservation and Load Management and Renewable Energy
(see note B) 4.7
- --------------------------------------------------------------------- ----------
TOTAL OTHER COMPONENTS 2.5
- --------------------------------------------------------------------- ----------
TOTAL O&M EXPENSE (8.7)
- --------------------------------------------------------------------- ----------
Note A: The Company's wholesale purchased power agreements were assumed by
Enron Power Marketing, Inc. as part of agreements for Enron to supply the
power needed by the Company to meet its standard offer obligations until
the end of the four-year standard offer period and the power needed to
serve the Company's special contract customers for the remaining contract
terms. The Company has created a regulatory asset and liability to reflect
this transaction, and the regulatory asset is being amortized, on a
straight line basis, as part of the CTA. The amortization for the first
quarter of 2000 of about $6.7 million is included in the "Amortization of
regulatory assets" line of the income statement.
Note B: Nuclear Division operation and maintenance expenses are incurred in
the production of energy for the wholesale market and are reflected in the
Nuclear Division results. About $1.3 million of the reduction was due to
the absence of refueling outage costs incurred in the first quarter of
1999. Conservation and load management and renewable energy costs are
pass-through costs recovered in unbundled rates.
Other taxes, primarily property taxes, decreased by $2.8 million in the
first quarter of 2000 compared to the first quarter of 1999, due principally to
the generating plant sale in April of 1999.
Depreciation expense decreased by $10.6 million in the first quarter of
2000 compared to the first quarter of 1999. About $5.1 million of the decrease
was due to the shifting of depreciation on nuclear plant stranded assets from
depreciation expense to amortization of regulatory assets. About $2.4 million of
the decrease was due to the completion of depreciation of conservation assets in
the first half of 1999, and another $2.4 million was due to the generation asset
sale in 1999. Other depreciation expenses decreased by $0.7 million.
Amortization of regulatory assets increased by $8.8 million in the first
quarter of 2000 compared to the first quarter of 1999. With three exceptions,
these costs, as recorded in 2000, are associated solely with either the CTA or
the SBC. The exceptions are described in the following two paragraphs. The CTA
and SBC amortization components in the first quarter of 2000 amounted to $12.8
million (pre-tax) and were: nuclear assets (from
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depreciation) $5.1 million, purchased power contracts (in place of purchased
power expense) $6.7 million, displaced worker costs $0.6 million, and other $0.4
million. These were partially offset by the elimination (completed in 1999) of
$3.1 million (after-tax) of amortization of Seabrook Nuclear Station deferred
return.
The exceptions noted in the previous paragraph are amortizations that apply
to the operating Distribution Division. They include the amortization of Retail
Access assets, $0.4 million (pre-tax), and accelerated amortizations (both
scheduled and "sharing" amortization). On December 31, 1996, the Connecticut
Department of Public Utility Control issued an order that implemented a
five-year Rate Plan to reduce the Company's retail prices and accelerate the
recovery of certain "regulatory assets." According to the Rate Plan, under which
the Company is currently operating, "accelerated" amortization of past utility
investments is scheduled for every year that the Rate Plan is in effect,
contingent upon the Company earning a 10.5% return on utility common stock
equity. Beginning in 2000, these accelerated amortizations are charged to the
operating Distribution Division, although they reduce CTA plant costs and rate
base. About $2.2 million (after-tax) of accelerated amortization was charged in
the first quarter of 2000, compared to about $3.0 million (after-tax) in 1999,
for a decrease of $0.8 million.
The Company can also incur additional accelerated amortization expense as a
result of the "sharing" mechanism in the Rate Plan if the Company achieves a
return on utility common stock equity above 11.5%, which the Company did achieve
during the third and fourth quarters of 1999. One-time items recorded against
the return on utility common stock equity, before the Company achieves the
11.5%, are recorded with an appropriate "sharing" effect if the Company
projects, at that time, that there will be total "sharing" for the year adequate
to cover the "sharing" for the one-time item. Such "sharing" amortization was
recorded in the first quarter of 1999, in the amount of $1.0 million before-tax
($0.6 million after-tax), as a result of the one-time gain recorded in that
quarter.
Interest charges for the regulated business continued on a downward trend,
decreasing by $6.0 million in the first quarter of 2000 compared to the first
quarter of 1999, partly offset by an increase of $2.0 million in interest
charges for non-regulated subsidiaries. Most of the reduction in utility
interest charges occurred after the generation asset sale, which was completed
on April 16, 1999. The Company used proceeds received from the sale of plant to
pay off $205 million of debt. The decrease in utility interest charges was
applied to the various unbundled components in 2000.
Non-regulated Business Earnings from Operations
- -----------------------------------------------
Overall, the consolidated non-regulated businesses operating under the
parent United Resources, Inc. (URI), after corporate parent-allocated interest,
earned approximately $0.1 million, or $.01 per share, in the first quarter 2000,
compared to losses of about $0.7 million, or $.05 per share, in the first
quarter of 1999.
The results of each of the subsidiaries of URI for the first quarter of
2000 reflects the allocation of debt costs from the parent based on a capital
structure, including an equity component, and interest rate, deemed to be
appropriate for that type of business. American Payment Systems, Inc. (APS)
earned approximately $0.7 million, or $.05 per share, in the first quarter of
2000, reflecting an increase of $0.6 million, or $.04 per share, over the first
quarter of 1999. Precision Power, Inc. (PPI) lost approximately $0.3 million, or
$.02 per share, in the first quarter of 2000, compared to a loss of
approximately $0.5 million, or $.03 per share, in the first quarter of 1999. The
improvement was the result of cost reduction efforts and the acquisition of
Allan Electric Company, Inc., despite expected seasonably low business activity
at Allan.
On May 11, 1999, the Company's non-regulated subsidiary, United Bridgeport
Energy, Inc. (UBE), increased its 4% passive investment in Bridgeport Energy LLC
(BE) to 33 1/3%. The second phase of BE's merchant wholesale electric generating
project went into commercial operation in July 1999, adding 180 megawatts of
generation capacity for a total of 520 megawatts. UBE lost approximately $1.0
million, or $.07 per share, in the first quarter of 2000, as a result of a
shutdown to repair the steam turbine and to make modifications to the combustion
turbine. These repairs and modifications are expected to be completed by the end
of May. United Capital Investment, Inc. earned approximately $1.0 million, or
$.07 per share, in the first quarter of 2000, compared
- 23 -
to a loss of about $0.4 million, or $.03 per share, in the first quarter of
1999. The improvement reflects unrealized gains on an investment in a venture
capital fund that is valued at its market value at the end of each quarter.
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year Rate Plan
- -------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework (Rate Plan) to reduce the Company's retail prices and accelerate the
recovery of certain "regulatory assets," beginning with deferred conservation
costs. The Company has operated under the terms of this Order since January 1,
1997. The Order's schedule of price reductions and accelerated amortizations was
based on a DPUC pro-forma financial analysis that anticipated the Company would
be able to implement such changes and earn an allowed annual return on common
stock equity invested in utility assets of 11.5% over the period 1997 through
2001. The Order established a set formula to share (see "Sharing Implementation"
below) any utility income that would produce a return above the 11.5% level:
one-third to be applied to customer price reductions, one-third to be applied to
additional amortization of regulatory assets, and one-third to be retained by
shareowners. Utility income is inclusive of earnings from operations and
one-time items.
Sharing Implementation
- ----------------------
"Sharing", in 2000, will result only if the regulated operating
Distribution Division exceeds its allowed return of 11.5% on utility common
stock equity. The operating Distribution Division is expected to realize about
40-50% of its pre-sharing earnings in the third quarter of each year. It will
not likely ever exceed the sharing level of utility earnings before the third
quarter of any year that "sharing" is in effect. Assuming the sharing level of
earnings is exceeded in the third quarter of a particular year, then all
positive utility earnings recorded in the fourth quarter of that year will be
subject to "sharing."
A look at 2000; continued growth of non-regulated business value
- ----------------------------------------------------------------
On January 1, 2000, the Company completed the restructuring process
required by the Connecticut electric utility industry restructuring legislation
in 1998 and its regulated business became an electricity delivery business. All
customers are now seeing at least a 10% reduction in their electric rates from
1996 levels.
The framework of the current Rate Plan, including the "sharing" mechanism,
is expected to continue through 2001. Regulatory decisions during 1999 did not
alter the Company's allowed return of 11.5% on utility equity, and did not
impinge on the Company's ability to achieve that return.
On January 24, 2000, the Company estimated its year 2000 earnings would be
in the range of $3.60-$3.80 per share. Following better than expected first
quarter 2000 earnings from both the regulated and non-regulated businesses and
experience with the new regulated pricing structure that became effective
January 1, 2000, the Company is now revising its full year 2000 earnings
estimate upwards, to $3.95-$4.10 per share.
If the Company were to earn 11.5% on utility equity in the regulated
business, including the Nuclear Division, that level of earnings would generate
$3.35-$3.45 per share. In addition, continued operation of the Company's nuclear
entitlements at the high availability rates experienced in the first quarter of
2000 would produce additional earnings.
- 24 -
Sharing will be greatly reduced from the 1999 levels, due to mandates in
the restructuring legislation. The Company expects sharing to contribute no more
than $.20-$.25 per share in 2000.
The Company's non-regulated businesses, under the parent URI, are expected
to contribute $.25-$.30 per share to earnings in 2000. This is an improvement
from previous expectations. URI's wholly-owned subsidiary, American Payment
Systems, Inc., is expected to contribute about half of this total, and United
Bridgeport Energy, Inc. should add $.05-$.10 per share. Precision Power, Inc.
and the other URI subsidiaries will contribute the rest. As a result of
management's continued confidence in the potential of the non-regulated
businesses, the Company is evaluating further investments in this area. However,
additional near-term losses could be incurred due to these new growth
initiatives, if the potential for future benefits warrants such losses.
Quarterly Earnings Pattern for 2000
- -----------------------------------
The quarterly earnings pattern for 2000 will be somewhat smoother than the
earnings pattern for 1999. The primary reason is the new regulated utility
pricing structure set by the Department of Public Utility Control (DPUC),
effective January 1, 2000, to implement standard offer customer rates at a level
10% below 1996 rates.
Overall, the implementation of the new rates will produce a retail price
reduction of about 6% compared to 1999 retail revenues, excluding any further
reduction resulting from earnings sharing. In 2000, all of the unbundled rate
components, except for the component attributable to the operating Distribution
Division, reflect fixed pricing within each rate class. That is, the seasonality
previously associated with historical underlying costs of those rate components,
the largest of which is the Competitive Transition Assessment (CTA) for recovery
of stranded costs, has been eliminated. Only the operating Distribution Company
component maintains a seasonal pricing structure, and that component is expected
to produce an average price for the year of about 4.2 cents per kilowatthour.
The Company earns the allowed 11.5% return on the equity portions of CTA
and the System Benefits Charge (SBC) rate base (the latter is minimal). For the
most part, the regulatory assets that are being recovered through the CTA are
being amortized on a straight-line basis. If CTA revenues do not produce the
allowed return, then deferred accounting is used to "true-up" to the allowed
return. This true-up adjusts for sales volume fluctuations as well as pricing
factors. A similar adjustment, on a much less significant scale, applies to the
SBC component. The generation service, conservation and renewables charges are
pass-through charges. The only retail sales volume fluctuations that flow to net
income are those that apply to the operating Distribution Division component of
rates. Thus, a 1% sales volume increase will produce additional sales margin of
about $2.4 million in 2000, whereas it produced additional sales margin of about
$6.0 million in 1999.
The other utility earnings component that can vary significantly is the
Nuclear Division component. The Company's operating nuclear assets, Seabrook and
Millstone 3, supply power solely to the wholesale market in 2000. Unit outages,
whether scheduled or unscheduled, will result in lowered sales, and unscheduled
outages could result in higher maintenance expenses. For 2000, Seabrook is
currently scheduled to be out-of-service for refueling in the fourth quarter for
about 29 days, and will show lower earnings in that period. The Company plans to
divest its nuclear generation ownership interests by the end of 2003, if not
sooner, in accordance with the restructuring legislation.
The following is a representation of the possible quarterly earnings from
operations pattern for currently expected 2000 results, compared to a normalized
pattern for 1999. Actual 2000 results may vary depending on changes due to
weather, economic conditions, sales mix (the usage pattern of the Distribution
Division's retail customers) and the Company's ability to control expenses, as
well as the performance of the non-regulated businesses and other unanticipated
events.
- 25 -
The Company's current overall estimate of earnings per share from
operations for 2000 is $3.95-$4.10. Significant variability could occur each
quarter and still produce earnings within that range. The Company has made range
estimates of quarterly results for 2000 as follows:
Earnings per share from operations:
Estimated Actual
Quarter 2000 Range 1999
------- ---------- ----
1 $1.20 (Actual) $ .66
2 $ .88 - $1.00 .99
3 $1.22 - $1.43 1.78
4 $ .50 - .62 .24
----
$3.67
Quarterly range estimates are not additive, that is, adding the low range
numbers produces a result that is lower than the Company's low estimate for the
year. The sums of the low and high range values should not be construed to
represent any estimate other than the Company's annual estimate of $3.95-$4.10
per share.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
The Company believes that it has no material quantitative or qualitative
exposure to market risk associated with activities in derivative financial
instruments, other financial instruments or derivative commodity instruments.
- 26 -
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
In the arbitration proceeding and lawsuits against Northeast Utilities and
its subsidiaries (NU) with respect to their operation of Millstone Unit 3,
described in Item 2, "Properties-Nuclear Generation" of the Registrant's Annual
Report (Form 10-K) for the fiscal year ended December 31, 1999, four additional
non-NU joint owners, who together own about 1 2/3% of the unit, have settled
their claims against NU and have withdrawn from the prosecution of the
arbitration proceeding and lawsuits. The Registrant and two other non-NU joint
owners, who together own about 6 1/3% of the unit, continue to prosecute the
arbitration proceeding and lawsuits.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
See the Registrant's Current Report (Form 8-K) filed March 22, 2000.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit
Table Item Exhibit
Number Number Description
---------- ------- -----------
(10) 10.8e Copy of Agreement for Extension of Transmission Line Agreement,
dated February 9, 2000, between The United Illuminating Company and
National Railroad Passenger Corporation, regarding extension of
Transmission Line Agreement, Exhibit 10.8a*, as supplemented and
modified by Exhibit 10.8c**.
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed Charges
and Ratios of Earnings to Combined Fixed Charges and Preferred Stock
Dividend Requirements (Twelve Months Ended March 31, 2000 and Twelve
Months Ended December 31, 1999, 1998, 1997, 1996 and 1995).
(27) 27 Financial Data Schedule.
* Filed with Registration Statement No. 2-60849, effective July 24, 1978
(Exhibit 5.4)
** Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991 (Exhibit 10.9c)
(b) Reports on Form 8-K.
Item Financial
Reported Statement Date of Report
-------- --------- --------------
5 None March 17, 2000
- 27 -
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
Date 05/12/2000 Signature /s/ Robert L. Fiscus
------------- ------------------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors,
Chief Financial Officer, Treasurer and Secretary
- 28 -