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 JUNE 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIE
EXCHANGE ACT OF 1934
For the transition period from to
------------ -------------
Commission Registrant; State of Incorporation; I. R. S. Employer
File Number Address; and Telephone Number Identification No.
1-6788 THE UNITED ILLUMINATING COMPANY 06-0571640
(a Connecticut Corporation)
157 Church Street
New Haven, Connecticut 06506
Telephone: (203) 499-2000
1-15995 UIL HOLDINGS CORPORATION 06-1541045
(a Connecticut Corporation)
157 Church Street
New Haven, Connecticut 06506
Telephone: (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 June 30, 2000, was 14,334,922.
- 1 -
<PAGE>
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three and
six months ended June 30, 2000 and 1999. 3
Consolidated Balance Sheet as of June 30, 2000 and
December 31, 1999. 4
Consolidated Statement of Cash Flows for the three and
six months ended June 30, 2000 and 1999. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 8
- Short-term Credit Arrangements 9
- Income Taxes 10
- Supplementary Information 11
- Commitments and Contingencies 12
- Capital Expenditure Program 12
- Nuclear Insurance Contingencies 12
- Other Commitments and Contingencies 12
- Connecticut Yankee 12
- Hydro-Quebec 13
- Environmental Concerns 13
- Site Decontamination, Demolition and Remediation Costs 13
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 14
- Segment Information 15
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 16
- Major Influences on Financial Condition 16
- Capital Expenditure Program 19
- Liquidity and Capital Resources 19
- Subsidiary Operations 21
- Results of Operations 21
- Looking Forward 28
Item 3. Quantitative and Qualitative Disclosure About Market Risk. 30
PART II. OTHER INFORMATION
Item 1. Legal Proceedings. 31
Item 4. Submission of Matters to a Vote of Security Holders. 31
Item 6. Exhibits and Reports on Form 8-K. 32
SIGNATURES 33
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<PAGE>
<TABLE>
PART I: FINANCIAL INFORMATION
ITEM I: FINANCIAL STATEMENTS
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
---- ---- ---- ----
<S> <C> <C> <C> <C>
OPERATING REVENUES (NOTE G) $164,012 $164,533 $344,989 $333,200
------------ ------------ ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 72,870 38,483 140,339 72,382
Capacity purchased 1,457 8,678 2,904 17,740
Other 33,535 36,761 67,999 75,515
Maintenance 5,748 6,013 10,819 15,459
Depreciation (Note G) 7,127 15,618 14,246 33,357
Amortization (deferral) of regulatory assets (9,211) 6,464 6,593 13,490
Income taxes (Note F) 15,692 15,851 28,898 31,376
Other taxes (Note G) 10,128 11,472 21,869 25,481
------------ ------------ ------------ ------------
Total 137,346 139,340 293,667 284,800
------------ ------------ ------------ ------------
OPERATING INCOME 26,666 25,193 51,322 48,400
------------ ------------ ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 244 254 425 267
Other-net (Note G) (709) (2,380) 1,693 (2,849)
Non-operating income taxes (Note F) 1,574 1,748 934 2,639
------------ ------------ ------------ ------------
Total 1,109 (378) 3,052 57
------------ ------------ ------------ ------------
INCOME BEFORE INTEREST CHARGES 27,775 24,815 54,374 48,457
------------ ------------ ------------ ------------
INTEREST CHARGES
Interest on long-term debt 9,513 10,163 19,119 22,390
Interest on Seabrook obligation bonds owned by the company (1,617) (1,711) (3,235) (3,422)
Dividend requirement of mandatorily redeemable securities 1,203 1,203 2,406 2,406
Other interest (Note G) 635 820 1,026 2,676
Allowance for borrowed funds used during construction (331) (323) (742) (771)
------------ ------------ ------------ ------------
9,403 10,152 18,574 23,279
Amortization of debt expense and redemption premiums 576 677 1,139 1,291
------------ ------------ ------------ ------------
Net Interest Charges 9,979 10,829 19,713 24,570
------------ ------------ ------------ ------------
NET INCOME 17,796 13,986 34,661 23,887
Premium on preferred stock redemptions - 53 - 53
Dividends on preferred stock - 15 - 66
------------ ------------ ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $17,796 $13,918 $34,661 $23,768
============ ============ ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,076 14,049 14,073 14,045
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,079 14,050 14,075 14,047
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $1.26 $0.99 $2.46 $1.69
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72 $1.44 $1.44
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
June 30, December 31,
2000 1999*
---- -----
(Unaudited)
Utility Plant at Original Cost
In service $933,194 $1,007,065
Less, accumulated provision for depreciation 467,627 532,409
------------- --------------
465,567 474,656
Construction work in progress 29,128 25,708
Nuclear fuel 24,157 21,101
------------- --------------
Net Utility Plant 518,852 521,465
------------- --------------
Other Property and Investments
Investment in generation facility 91,361 83,494
Nuclear decommissioning trust fund assets 31,265 28,255
Other 15,735 20,098
------------- --------------
138,361 131,847
------------- --------------
Current Assets
Unrestricted cash and temporary cash investments 5,330 39,099
Restricted cash 26,615 29,223
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,500 and $1,800 56,329 56,057
Other, less allowance for doubtful accounts
of $709 and $508 77,986 53,612
Accrued utility revenues 23,327 25,019
Fuel, materials and supplies, at average cost 9,682 9,259
Prepayments 3,453 3,056
Other 7,068 4,801
------------- --------------
Total 209,790 220,126
------------- --------------
Deferred Charges
Goodwill 15,181 4,827
Unamortized debt issuance expenses 7,760 8,688
Other 613 1,272
------------- --------------
Total 23,554 14,787
------------- --------------
Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Nuclear plant investments-above market 508,029 518,268
Income taxes due principally to book-tax
differences 160,221 166,965
Long-term purchase power contracts-above market 136,367 144,406
Connecticut Yankee 34,125 37,013
Unamortized redemption costs 22,855 22,314
Unamortized cancelled nuclear projects 8,194 8,780
Displaced worker protection costs 4,585 5,746
Uranium enrichment decommissioning cost 1,011 1,040
Other 31,018 5,453
------------- --------------
Total 906,405 909,985
------------- --------------
$1,796,962 $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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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
<CAPTION>
June 30, December 31,
2000 1999*
---- -----
(Unaudited)
<S> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,344 2,253
Capital stock expense (2,170) (2,170)
Unearned employee stock ownership plan equity (8,785) (9,261)
Retained earnings 189,866 175,470
--------------- ---------------
473,261 458,298
Company-obligated mandatorily redeemable securities of
subsidiary holding solely parent company debentures 50,000 50,000
Long-term debt
Long-term debt 604,819 605,641
Investment in Seabrook obligation bonds (82,635) (87,413)
--------------- ---------------
Net long-term debt 522,184 518,228
--------------- ---------------
Total 1,045,445 1,026,526
--------------- ---------------
Noncurrent Liabilities
Purchase power contract obligation 136,365 144,406
Nuclear decommissioning obligation 31,265 28,255
Connecticut Yankee contract obligation 23,925 27,056
Pensions accrued 11,196 19,026
Obligations under capital leases 15,932 16,131
Other 10,689 10,394
--------------- ---------------
Total 229,372 245,268
--------------- ---------------
Current Liabilities
Current portion of long-term debt 859 25,000
Notes payable 14,262 17,131
Accounts payable 36,203 49,069
Accounts payable - APS customers 59,105 56,220
Dividends payable 10,135 10,125
Taxes accrued 12,488 2,570
Interest accrued 16,204 8,433
Obligations under capital leases 390 375
Other accrued liabilities 55,928 39,421
--------------- ---------------
Total 205,574 208,344
--------------- ---------------
Customers' Advances for Construction 1,872 1,867
--------------- ---------------
Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Accumulated deferred investment tax credits 14,984 15,157
Deferred gains on sale of property 15,901 15,901
Customer refund 12,640 18,381
Other 3,623 2,543
--------------- ---------------
Total 47,148 51,982
--------------- ---------------
Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
TO TAXING AUTHORITIES) 267,551 264,223
Commitments and Contingencies (Note L)
--------------- ---------------
$1,796,962 $1,798,210
=============== ===============
</TABLE>
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
---- ---- ---- ----
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $17,796 $13,986 $34,661 $23,887
------------- ------------ ------------ ------------
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 17,024 19,252 33,626 41,718
Deferred income taxes 211 4,547 5,626 3,815
Deferred income taxes - generation asset sale - (70,222) - (70,222)
Deferred investment tax credits - net (86) (191) (173) (381)
Amortization of nuclear fuel 1,903 1,489 3,793 4,680
Allowance for funds used during construction (575) (577) (1,167) (1,038)
CTA and SBC expense deferral (15,488) - (25,016) -
Amortization of deferred return - 3,146 - 6,293
Changes in:
Accounts receivable - net (18,296) 2,532 (24,646) 15,344
Fuel, materials and supplies 72 639 (423) 212
Prepayments 2,747 8,806 (397) 3,762
Accounts payable (476) 12,509 (9,981) (21,671)
Interest accrued 3,938 2,508 7,771 6,413
Taxes accrued 1,248 (9,615) 9,918 4,810
Taxes accrued - generation asset sale - 35,111 - 35,111
Other assets and liabilities (6,060) (26,915) (3,560) (36,733)
------------- ------------ ------------ ------------
Total Adjustments (13,838) (16,981) (4,629) (7,887)
------------- ------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 3,958 (2,995) 30,032 16,000
------------- ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 262 269 566 569
Notes payable 141 (33,488) (2,869) (38,208)
Securities redeemed and retired:
Preferred stock - (4,299) - (4,299)
Long-term debt - (125,000) (25,750) (211,202)
Premium on preferred stock redemptions - (53) - (53)
Lease obligations (93) (86) (184) (171)
Dividends
Preferred stock - (65) - (116)
Common stock (10,130) (10,111) (20,255) (20,215)
------------- ------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (9,820) (172,833) (48,492) (273,695)
------------- ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in unregulated businesses - (75,092) - (75,092)
Net cash received from sale of generation assets - 270,590 - 270,590
Plant expenditures, including nuclear fuel (13,063) (10,742) (22,695) (16,526)
Investment in debt securities - - 4,778 5,447
------------- ------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (13,063) 184,756 (17,917) 184,419
------------- ------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (18,925) 8,928 (36,377) (73,276)
BALANCE AT BEGINNING OF PERIOD 50,870 42,297 68,322 124,501
------------- ------------ ------------ ------------
BALANCE AT END OF PERIOD 31,945 51,225 31,945 51,225
LESS: RESTRICTED CASH 26,615 28,045 26,615 28,045
------------- ------------ ------------ ------------
BALANCE: UNRESTRICTED CASH $5,330 $23,180 $5,330 $23,180
============= ============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $5,951 $8,177 $8,559 $14,483
============= ============ ============ ============
Income taxes $10,600 $54,250 $12,600 $57,950
============= ============ ============ ============
</TABLE>
Note: Cash Flows from Operating Activities for the three and six months ended
June 30, 1999 were reduced by the current income tax effects of the
generation asset sale in the amount of $35,111.
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
HOLDING COMPANY FORMATION
On July 20, 2000, the corporate restructuring of The United Illuminating
Company (the Company) and its non-regulated subsidiaries into a holding company
structure was completed. In the holding company structure, the Company has
become a wholly-owned subsidiary of UIL Holdings Corporation, and each share of
the common stock of the Company has been converted into a share of common stock
of UIL Holdings Corporation. All of the Company's interests in all of its direct
and indirect non-regulated subsidiaries have been transferred to UIL Holdings
Corporation and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by UIL Holdings Corporation.
BASIS OF PRESENTATION
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 six months of 2000 and
1999 was 7.6% 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 $1,995,000 and $1,950,000 in the first six
months of 2000 and 1999, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 2000, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$23.0 million and $8.3 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.
COMPREHENSIVE INCOME
Comprehensive income for the six months ended June 30, 2000 and 1999 is
equal to net income as reported.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at June 30, 2000, of which 258,449 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 June 30, 2000. No options were
exercised during the six months ended June 30, 2000. Effective with the
formation of the holding company structure on July 20, 2000, all outstanding
options were converted into options to purchase an equivalent number of shares
of UIL Holdings Corporation common stock.
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 June 30, 2000. No options to purchase
shares of the Company's common stock can be exercised without the approval of
the DPUC; and, as of June 30, 2000, the Company had not requested approval by
the DPUC. Effective with the formation of the holding company structure on July
20, 2000, all outstanding options were converted into options to purchase an
equivalent number of shares of UIL Holdings Corporation common stock. As a
result, no approval by the DPUC is required for the exercise of these options as
of that date.
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 June 30,
2000, 258,449 shares, with a fair market value of $11.3 million, had been
purchased by the KSOP and had not been committed to be released or allocated to
KSOP participants. On July 20, 2000, effective with the formation of the holding
company structure, shares held in employees' KSOP accounts and unallocated
shares held by the KSOP were converted into shares of UIL Holdings Corporation
common stock.
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
$131.7 million were free from such limitations at June 30, 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
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
On August 9, 2000, the Company initiated the redemption process for $50
million of 9 5/8% Preferred Capital Securities, Series A, due 2025. These
securities were issued by United Capital Funding Partnership L. P., a Delaware
limited partnership, in April 1995. The securities will be redeemed on September
25, 2000 at 100% of par value.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company's $60 million revolving credit agreement with a group of banks
was terminated on August 4, 2000. As of June 30, 2000, the Company had no
short-term borrowings outstanding under this facility.
On August 4, 2000, UIL Holdings Corporation entered into a revolving credit
agreement with the same group of banks. The borrowing limit of this facility is
$97.5 million. The facility permits UIL Holdings Corporation to borrow funds at
a fluctuating interest rate determined by the prime lending market in New York,
and also permits UIL Holdings Corporation to borrow money for fixed periods of
time specified by UIL Holdings Corporation 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 UIL Holdings Corporation and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to UIL
Holdings Corporation under this revolving credit agreement, although borrowings
outstanding at the time of such an occurrence would not then become due and
payable.
On June 26, 2000, the Company entered into a Money Market Loan arrangement
with Chase Manhattan Bank. This is an uncommitted short-term borrowing
arrangement under which Chase Manhattan Bank may make loans totaling up to $125
million to the Company for fixed maturities from one day up to six months. Chase
Securities, Inc. acts as an agent and sells the loans to investors. The fixed
interest rates on the loans are determined based on conditions in the financial
markets at the time of each loan. As of June 30, 2000, the Company had loans
totaling $6.5 million outstanding under this arrangement.
- 9 -
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<CAPTION>
Three Months Ended Six Months Ended
(F) INCOME TAXES June 30, June 30,
2000 1999 2000 1999
---- ---- ---- ----
(000's) (000's) (000's) (000's)
<S> <C> <C> <C> <C>
Income tax expense consists of:
Income tax provisions:
Current
Federal $11,333 $63,457 $18,195 $75,794
State 2,660 16,512 4,316 19,731
------------ ------------ ------------ ------------
Total current 13,993 79,969 22,511 95,525
------------ ------------ ------------ ------------
Deferred
Federal 427 (51,490) 5,078 (51,644)
State (216) (14,185) 548 (14,763)
------------ ------------ ------------ ------------
Total deferred 211 (65,675) 5,626 (66,407)
------------ ------------ ------------ ------------
Investment tax credits (86) (191) (173) (381)
------------ ------------ ------------ ------------
Total income tax expense $14,118 $14,103 $27,964 $28,737
============ ============ ============ ============
Income tax components charged as follows:
Operating expenses $15,692 $15,851 $28,898 $31,376
Other income and deductions - net (1,574) (1,748) (934) (2,639)
------------ ------------ ------------ ------------
Total income tax expense $14,118 $14,103 $27,964 $28,737
============ ============ ============ ============
The following table details the components
of the deferred income taxes:
Tax gain on sale of generation assets - ($70,222) - ($70,222)
Seabrook sale/leaseback transaction (1,998) (2,082) (3,995) (4,164)
Pension benefits 1,547 580 3,095 2,105
Accelerated depreciation (352) 1,250 (705) 2,500
Tax depreciation on unrecoverable plant investment 23 1,186 46 2,374
Unit overhaul and replacement power costs (455) 3,116 (909) 2,218
Conservation and load management (26) (872) (53) (1,745)
Postretirement benefits (92) (265) (184) (698)
Loss from disposition of property (1,420) - (1,420) -
Displaced worker protection costs (228) 2,215 (463) 2,215
Bond redemption costs (257) (252) (73) (508)
Cancelled nuclear plant (116) (116) (233) (233)
Restructuring costs 335 - 2,665 -
SBC and CTA expense deferral 6,176 - 9,975 -
Other - net (2,926) (213) (2,120) (249)
------------ ------------ ------------ ------------
Deferred income taxes - net $211 ($65,675) $ 5,626 ($66,407)
============ ============ ============ ============
</TABLE>
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
2000 1999 2000 1999
---- ---- ---- ----
(000's) (000's) (000's) (000's)
<S> <C> <C> <C> <C>
Operating Revenues
------------------
Retail $148,728 $155,538 $297,669 $307,929
Wholesale 19,958 5,676 38,572 19,269
Other (4,674) 3,319 8,748 6,002
------------- ------------- ------------- -------------
Total Operating Revenues $164,012 $164,533 $344,989 $333,200
============= ============= ============= =============
Sales by Class(MWH's)
---------------------
Retail
Residential 471,211 443,304 1,008,293 977,072
Commercial 575,849 591,114 1,150,621 1,144,912
Industrial 294,177 292,199 571,196 561,259
Other 10,175 11,850 23,500 24,049
------------- ------------- ------------- -------------
1,351,412 1,338,467 2,753,610 2,707,292
Wholesale 644,291 205,837 1,269,296 858,583
------------- ------------- ------------- -------------
Total Sales by Class 1,995,703 1,544,304 4,022,906 3,565,875
============= ============= ============= =============
Depreciation
------------
Plant in Service $6,130 $11,916 $12,251 $26,571
Amortization of Conservation and
Load Management Costs - 2,418 - 4,836
Nuclear Decommissioning 997 1,284 1,995 1,950
------------- ------------- ------------- -------------
$7,127 $15,618 $14,246 $33,357
============= ============= ============= =============
Other Taxes
-----------
Charged to:
Operating:
State gross earnings $5,167 $5,898 $11,555 $11,752
Local real estate and personal property 3,805 4,349 7,654 10,675
Payroll taxes 1,156 1,225 2,660 3,054
------------- ------------- ------------- -------------
10,128 11,472 21,869 25,481
Nonoperating and other accounts 159 158 279 292
------------- ------------- ------------- -------------
Total Other Taxes $10,287 $11,630 $22,148 $25,773
============= ============= ============= =============
Other Income and (Deductions) - net
-----------------------------------
Interest income $324 $462 $611 $1,129
Equity earnings from Connecticut Yankee 94 143 243 324
Earnings (Loss) from subsidiary companies-before tax 2,614 (2,314) 4,824 (3,520)
Miscellaneous other income and (deductions) - net (3,741) (671) (3,985) (782)
------------- ------------- ------------- -------------
Total Other Income and (Deductions) - net ($709) ($2,380) $1,693 ($2,849)
============= ============= ============= =============
Other Interest Charges
----------------------
Notes Payable $203 $359 $515 $1,643
Other 432 461 511 1,033
------------- ------------- ------------- -------------
Total Other Interest Charges $635 $820 $1,026 $2,676
============= ============= ============= =============
</TABLE>
- 11 -
<PAGE>
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 $277.6 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
- 12 -
<PAGE>
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). This agreement was submitted to the FERC, which approved it in
all respects on July 26, 2000; and it became effective on August 1, 2000. The
agreement allows Connecticut Yankee to earn a return on equity of 6% and
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.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.2
million) and return on investment (approximately $3.6 million) at June 30, 2000,
is approximately $23.9 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 June 30, 2000, the Company's
guarantee liability for this debt was approximately $5.9 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 June 30, 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 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.
- 13 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company has been 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. The excavation of
contaminated soils and post-remediation monitoring is complete. 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. The Connecticut Department of Public Utility Control and
the Federal Energy Regulatory Commission have issued orders approving the
transaction and it is expected to close when these orders have become final. If
the site is conveyed to QE, the Company will fund 61% (approximately $1.2
million) 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 closed on the sale of its Bridgeport Harbor Station and New
Haven Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation on April 16, 1999. 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 six months of 2000 was $1.7 million. The Company's share
of the fund at June 30, 2000 was approximately $23.0 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 six months of 2000 was $0.3 million. The
Company's share of the fund at June 30, 2000 was approximately $8.3 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 June 30, 2000, $196 million has
been expended for decommissioning. The projected remaining decommissioning cost
is $302 million, of which the Company's share would be $29 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 $1.2 million were funded by the Company during the
first six months of 2000, and the Company's share of the fund at June 30, 2000
was $18.7 million.
- 14 -
<PAGE>
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 June 30, 2000
and December 31, 1999:
JUNE 30, DECEMBER 31,
2000 1999
---- ----
(000's)
Total Assets - Regulated Utility $1,781,132 $1,809,451
Total Assets - Non-regulated Subsidiaries 222,502 194,642
Total Assets - Elimination (206,672) (205,883)
--------- ---------
Total Consolidated Assets $1,796,962 $1,798,210
========= =========
- 15 -
<PAGE>
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
- 16 -
<PAGE>
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 participating in an auction process for all
three of the generating units at Millstone Station 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 was concluded on August 7, 2000 when
the DPUC and J. P. Morgan & Co. announced that Dominion Resources, Inc. had
agreed to purchase Millstone Units 1 and 2, and 93.47% of Millstone Unit 3 for
$1.298 billion. The purchase price agreed to for the Company's ownership
interest in Unit 3, which is subject to adjustments for expenditures and
eventualities prior to the date of closing on the sale, is approximately $31
million, exclusive of nuclear fuel. The Company's share of the payment to be
made for the projected nuclear fuel inventory at the date of closing on the sale
is approximately $2.5 million. It is currently estimated that obtaining other
requisite regulatory approvals of the auction results and consummating the sale
may require an additional eight months. The divestiture process for Seabrook
Unit 1 has not yet been determined.
The Company's unbundling plan also proposed a corporate restructuring to
separate its ongoing regulated transmission and distribution operations and
functions, that is, the Distribution Company assets and operations, from all of
its non-regulated operations and activities. In a decision dated May 19, 1999,
the DPUC approved the 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 corporate restructuring; and on July 19,
2000, the Nuclear Regulatory Commission authorized the corporate restructuring.
On July 20, 2000, the corporate restructuring of the Company and its
non-regulated subsidiaries into a holding company structure was completed. In
the holding company structure, the Company has become a wholly-owned subsidiary
of UIL Holdings Corporation, and each share of the common stock of the Company
has been converted into a share of common stock of UIL Holdings Corporation. All
of the Company's interests in all of its direct and indirect non-regulated
subsidiaries have been transferred to UIL Holdings Corporation and, to the
extent new businesses are subsequently acquired or commenced, they will also be
financed and owned by UIL Holdings Corporation.
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 Company has amortized less than the expected level of regulatory assets
related to stranded costs during the first six months of 2000, due to timing
differences and higher than anticipated costs associated with providing standard
offer service to customers. Since stranded costs are intended to be trued-up
annually, the Company continues to anticipate recovery through the competitive
transition assessment of these unamortized costs. The Connecticut
- 17 -
<PAGE>
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. This settlement agreement was approved by the DPUC
on July 5, 2000; and the Office of Consumer Counsel's Superior Court appeal has
been withdrawn.
Under the Restructuring Act, effective July 1, 2000, all of the Company's
customers are able to choose their power supply providers. 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.
- 18 -
<PAGE>
CAPITAL EXPENDITURE PROGRAM
The Company's 2000-2004 estimated capital expenditure program, excluding
allowance for funds used during construction, is presently budgeted as follows:
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004 TOTAL
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Nuclear Generation (1) $ 2,930 $ 2,855 $ - $ - $ - $ 5,785
Distribution and Transmission 44,520 37,386 20,313 16,395 32,496 151,110
------- ------ ------ ------ ------ -------
Subtotal 47,450 40,241 20,313 16,395 32,496 156,895
Nuclear Fuel 11,167 6,962 2,837 8,274 - 29,240
------- ------ ------ ------ ------ -------
Total Utility Expenditures 58,617 47,203 23,150 24,669 32,496 186,135
Total Non-Regulated Business
Expenditures 64,679 14,309 3,749 4,323 4,452 91,512
------- ------ ------ ------ ------ -------
Total $123,296 $61,512 $26,899 $28,992 $36,948 $277,647
======== ======= ======= ======= ======= ========
</TABLE>
(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 June 30, 2000, the Company had $31.9 million of cash and temporary cash
investments, a decrease of $36.4 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 30.0
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (28.2)
- Dividend payments (20.3)
Investment in debt securities 4.8
Cash invested in plant, including nuclear fuel (22.7)
------
Net Change in Cash (36.4)
------
Balance, June 30, 2000 $31.9
=====
- 19 -
<PAGE>
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year (1) $39.1 $ - $ - $ - $ -
Internally Generated Funds less Dividends (2) 74.9 91.5 95.0 89.9 94.2
----- ---- ---- ---- ----
Subtotal 114.0 91.5 95.0 89.9 94.2
Less:
Utility Capital Expenditures (excluding Nuclear Fuel) (2) 47.4 40.2 20.3 16.4 32.5
Utility Nuclear Fuel Expenditures (2) 11.2 7.0 2.8 8.3 -
Non-Regulated Business Capital Expenditures (2) 64.7 14.3 3.7 4.3 4.5
----- ----- ---- ---- ----
Total 123.3 61.5 26.8 29.0 37.0
Cash Available to pay Debt Maturities and Redemptions (9.3) 30.0 68.2 60.9 57.2
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) $101.3 $(30.0) $31.8 $39.1 $(57.2)
===== ===== ==== ==== =====
</TABLE>
(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 capital requirements that exceed available cash will have to be
provided by external financing. Although there is no commitment to provide such
financing from any source of funds, other than a $97.5 million revolving credit
agreement with a group of banks, described below, future external financing
needs are expected to be satisfied by the issuance of 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 future income and cash flow.
The Company's $60 million revolving credit agreement with a group of banks
was terminated on August 4, 2000. As of June 30, 2000, the Company had no
short-term borrowings outstanding under this facility.
On August 4, 2000, UIL Holdings Corporation entered into a revolving credit
agreement with the same group of banks. The borrowing limit of this facility is
$97.5 million. The facility permits UIL Holdings Corporation to borrow funds at
a fluctuating interest rate determined by the prime lending market in New York,
and also permits UIL Holdings Corporation to borrow money for fixed periods of
time specified by UIL Holdings Corporation 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 UIL Holdings Corporation and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to UIL
Holdings Corporation under this revolving credit agreement, although borrowings
outstanding at the time of such an occurrence would not then become due and
payable.
On June 26, 2000, the Company entered into a Money Market Loan arrangement
with Chase Manhattan Bank. This is an uncommitted short-term borrowing
arrangement under which Chase Manhattan Bank may make loans
- 20 -
<PAGE>
totaling up to $125 million to the Company for fixed maturities from one day up
to six months. Chase Securities, Inc. acts as an agent and sells the loans to
investors. The fixed interest rates on the loans are determined based on
conditions in the financial markets at the time of each loan. As of June 30,
2000, the Company had loans totaling $6.5 million outstanding under this
arrangement.
SUBSIDIARY OPERATIONS
United Resources, Inc. (URI), serves as the parent corporation for several
non-regulated 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. On July 20, 2000, the corporate restructuring of the Company and
its non-regulated subsidiaries into a holding company structure was completed.
In the holding company structure, the Company has become a wholly-owned
subsidiary of UIL Holdings Corporation, and the Company's interests in URI and
all of its direct and indirect non-regulated subsidiaries have been transferred
to UIL Holdings Corporation.
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,
Xcelecom, Inc., and its subsidiaries, provide electrical and voice-data-video
design, construction, systems integration and services to customers in New
England and the neighboring Mid-Atlantic region. 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
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 quarters of 2000 and the quarters 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 in 2000 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.
SECOND QUARTER OF 2000 VS. SECOND QUARTER OF 1999
-------------------------------------------------
Earnings for the second quarter of 2000 were $17.8 million, or $1.26 per
share (on both a basic and diluted basis), up $3.9 million, or $.27 per share,
from the second quarter of 1999. Excluding a one-time item recorded in the
second quarter of 2000, earnings from operations (on both a basic and diluted
basis) were $19.9 million or $1.41 per share, up $6.0 million, or $.42 per
share, from the second quarter of 1999. The earnings from operations
contribution of utility operations, excluding the Nuclear Division, was $1.23
per share in the second quarter of 2000. The Nuclear Division contributed $.17
per share, for a total utility contribution of $1.40 per share, compared to
$1.11 per share in the second quarter of 1999. The Company's non-regulated
businesses earned $.01 per share in the second quarter of 2000, compared to a
loss of $.12 per share in the second quarter of 1999.
- 21 -
<PAGE>
The one-time item recorded in the second quarter of 2000 was: EPS
-------------------- --------------------------------------------- --------
2000 Quarter 2 Impairment loss on property in North Haven $ (.15)
-------------------- --------------------------------------------- --------
On June 14, 2000, the Connecticut Department of Public Utility Control
approved a sale of property by the Company to Souwestcon Properties, Inc., an
indirect wholly-owned subsidiary. The sale price of the property was $1.2
million, and the property had a book value of $4.7 million. As a result of the
transaction, the Company recognized an impairment loss of $3.5 million
(before-tax) or $1.4 million (after-tax) in June 2000.
Utility Earnings from Operations
--------------------------------
Overall, retail revenue decreased by $6.8 million in the second quarter of
2000 compared to the second quarter of 1999.
------------------------------------------------------------ ---------------
Total From
Retail Revenues: $ millions Operations
------------------------------------------------------------ ---------------
Revenue from:
------------------------------------------------------------ ---------------
Estimate of operating Distribution Division component of
"weather corrected" retail sales growth, up 1.1% 0.6
------------------------------------------------------------ ---------------
Estimate of operating Distribution Division component of
weather effect on retail sales (1.4)
------------------------------------------------------------ ---------------
Estimate of operating Distribution Division component of
price reduction (3.3)
------------------------------------------------------------ ---------------
Other retail price reduction, mix of sales and other (see
other operating revenues) (2.7)
------------------------------------------------------------ ---------------
TOTAL RETAIL REVENUE (6.8)
------------------------------------------------------------ ---------------
Retail fuel and energy expense increased by $33.5 million in the second
quarter of 2000 compared to the second 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 $13.4 million in the second quarter of
2000 compared to the second quarter of 1999. Margin from the Nuclear Division,
which was incorporated in retail rates in 1999, increased by $14.3 million. The
Company's operating nuclear assets, Seabrook Unit 1 and Millstone Unit 3, supply
power solely to the wholesale market in 2000. Overall, the Nuclear Division
produced earnings of $.17 per share in the second 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
wholesale sales margin of $0.9 million from general wholesale activities in the
second quarter of 1999.
Other operating revenues decreased by $8.0 million in the second quarter of
2000 compared to the second quarter of 1999. Accrued revenues for the
Competitive Transition Assessment (CTA) and the System Benefits Charge (SBC)
decreased by $9.6 million in the second quarter of 2000 compared to the second
quarter of 1999. See the paragraph on amortization of regulatory assets below,
and 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 $1.4 million in the second quarter of 2000 compared to the
second quarter of 1999, and were mostly offset by an increase in transmission
operation expense.
- 22 -
<PAGE>
Operating expenses for operations, maintenance and purchased capacity
decreased by $10.7 million in the second quarter of 2000 compared to the second
quarter of 1999. The principal components of these expense changes include:
$millions
--------------------------------------------------------------------- ----------
Capacity expense:
--------------------------------------------------------------------- ----------
Cogeneration (see Note A) (7.1)
--------------------------------------------------------------------- ----------
Other purchases (0.1)
--------------------------------------------------------------------- ----------
TOTAL CAPACITY EXPENSE (7.2)
--------------------------------------------------------------------- ----------
Operating Distribution Division O&M expense:
--------------------------------------------------------------------- ----------
1999 fossil generation unit operating and maintenance costs (1.4)
--------------------------------------------------------------------- ----------
Pension and other employee benefit costs (2.3)
--------------------------------------------------------------------- ----------
NEPOOL transmission expense 1.1
--------------------------------------------------------------------- ----------
Other (3.7)
--------------------------------------------------------------------- ----------
TOTAL OPERATING DISTRIBUTION DIVISION (6.3)
--------------------------------------------------------------------- ----------
Other unbundled components of O&M expense:
--------------------------------------------------------------------- ----------
Nuclear Division (see Note B) (1.3)
--------------------------------------------------------------------- ----------
Conservation and Load Management and Renewable Energy
(see note B) 4.1
--------------------------------------------------------------------- ----------
TOTAL OTHER COMPONENTS 2.8
--------------------------------------------------------------------- ----------
TOTAL O&M EXPENSE (10.7)
--------------------------------------------------------------------- ----------
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 second 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 $1.0 million
of the reduction was due to the absence, in 2000, of refueling
outage costs incurred in the second 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 $0.6 million in the
second quarter of 2000 compared to the second quarter of 1999, due principally
to the generating plant sale in April of 1999.
Depreciation expense decreased by $8.5 million in the second quarter of
2000 compared to the second 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 $0.4 million was due to the generation asset
sale in 1999. Other depreciation expenses decreased by $0.6 million.
Amortization of regulatory assets decreased by $15.7 million in the second
quarter of 2000 compared to the second 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 paragraph. The CTA and
SBC amortization
- 23 -
<PAGE>
components in the second quarter of 2000 amounted to $12.8 million (pre-tax) and
were: nuclear assets (from 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. However, because the result of these
amortizations produced returns on both the CTA and SBC below the 11.5% return
allowed, about $24.9 million (before-tax) of amortization was deferred for the
second quarter of 2000, including about $8.9 million (before-tax) that was
offset by the other operating accrued revenue decrease mentioned above. The
elimination (completed in 1999) of $3.1 million (after-tax) of amortization of
Seabrook Nuclear Station deferred return also reduced amortization expense in
the second quarter of 2000 compared to the second quarter of 1999.
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 second quarter of 2000, compared to about $3.0 million (after-tax) in 1999,
for a decrease of $0.8 million.
Interest charges for the regulated business continued on a downward trend,
decreasing by $2.5 million in the second quarter of 2000 compared to the second
quarter of 1999, partly offset by an increase of $1.7 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 $0.2 million, or $.01 per share, in the second quarter
2000, compared to losses of about $1.7 million, or $.12 per share, in the second
quarter of 1999.
The results of each of the subsidiaries of URI for the second quarter of
2000 reflect 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. earned
approximately $0.6 million, or $.04 per share, in the second quarter of 2000,
reflecting an increase of $0.4 million, or $.03 per share, over the second
quarter of 1999. Xcelecom, Inc. earned approximately $0.2 million, or $.01 per
share, in the second quarter of 2000, compared to a loss of approximately $1.2
million, or $.08 per share, in the second quarter of 1999. The improvement was
the result of cost reduction efforts and the acquisitions of the Allan Electric
Co., Inc. and the DataStore Incorporated.
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 $0.1
million, or $.01 per share, in the second quarter of 2000, compared to a loss of
about $0.6 million, or $.05 per share, in the second quarter of 1999. The second
quarter 2000 loss was the result of a shutdown to repair the steam turbine and
to make modifications to the combustion turbine. These repairs and modifications
were partly completed in June and partial service was resumed in June. Full
service was resumed in mid-July. United Capital Investments, Inc. did not
contribute significantly to earnings in either second quarter. The remaining
non-regulated businesses loss of $.03 per share
- 24 -
<PAGE>
comparing the second quarter of 2000 to the second quarter of 1999 was the
result of higher interest charges at the parent URI.
FIRST SIX MONTHS OF 2000 VS. FIRST SIX MONTHS OF 1999
-----------------------------------------------------
Earnings for the first six months of 2000 were $34.7 million, or $2.46 per
share (on both a basic and diluted basis), up $10.9 million, or $.77 per share,
from the first six months of 1999. Excluding one-time items recorded in both
periods, earnings from operations (on both a basic and diluted basis) were up
$13.6 million, or $.96 per share, from the first six months of 1999. The
earnings from operations contribution of utility operations, excluding the
Nuclear Division, was $2.20 per share in the first six months of 2000. The
Nuclear Division contributed $.39 per share, for a total utility contribution of
$2.59 per share, compared to $1.86 per share in the first six months of 1999.
The Company's non-regulated businesses earned $.02 per share in the first six
months of 2000, compared to a loss of $.17 per share in the first six months of
1999.
The one-time item recorded in the first six months of 2000 was: EPS
-------------------- ------------------------------------------------ ----------
2000 Quarter 2 Impairment loss on property in North Haven $(.15)
-------------------- ------------------------------------------------ ----------
The one-time item recorded in the first six months 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 $10.3 million in the first six months
of 2000 compared to the first six months of 1999.
<TABLE>
---------------------------------------------------------------- ------------ ------------- -----------
<CAPTION>
From From
Retail Revenues: $ millions Operations One-time Total
---------------------------------------------------------------- ------------ ------------- -----------
<S> <C> <C> <C>
Revenue from:
---------------------------------------------------------------- ------------ ------------- -----------
Sharing: for 1999 one-time item - 1.0 1.0
---------------------------------------------------------------- ------------ ------------- -----------
Estimate of operating Distribution Division component of
"real" retail sales growth, up 1.2% 1.3 - 1.3
---------------------------------------------------------------- ------------ ------------- -----------
Estimate of operating Distribution Division component of
"leap year day" retail sales growth, up 0.6% 0.6 - 0.6
---------------------------------------------------------------- ------------ ------------- -----------
Estimate of operating Distribution Division component of
weather effect on retail sales (0.3) - (0.3)
---------------------------------------------------------------- ------------ ------------- -----------
Estimate of operating Distribution Division component of
price reduction (6.3) - (6.3)
---------------------------------------------------------------- ------------ ------------- -----------
Other retail price reduction, mix of sales and other (see
other operating revenues) (6.6) - (6.6)
---------------------------------------------------------------- ------------ ------------- -----------
TOTAL RETAIL REVENUE (11.3) 1.0 (10.3)
---------------------------------------------------------------- ------------ ------------- -----------
</TABLE>
Retail fuel and energy expense increased by $73.1 million in the first six
months of 2000 compared to the first six months 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 $27.1 million in the first six months
of 2000 compared to the first six months of 1999. Margin from the Nuclear
Division, which was incorporated in retail rates in 1999, increased by $28.5
million. The Company's operating nuclear assets, Seabrook Unit 1 and Millstone
Unit 3, supply power solely
- 25 -
<PAGE>
to the wholesale market in 2000. Overall, the Nuclear Division produced earnings
of $.39 per share in the first six months 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 $1.4
million from general wholesale activities in the first six months of 1999.
Other operating revenues increased by $2.7 million in the first six months
of 2000 compared to the first six months of 1999. Other operating revenues
include transmission revenues from the New England Power Pool (NEPOOL), which
increased by $2.7 million in the first six months of 2000 compared to the first
six months of 1999, and were mostly offset by an increase in transmission
operation expense.
Operating expenses for operations, maintenance and purchased capacity
decreased by $27.0 million in the first six months of 2000 compared to the first
six months of 1999. The principal components of these expense changes include:
$millions
--------------------------------------------------------------------- ----------
Capacity expense:
--------------------------------------------------------------------- ----------
Cogeneration (see Note A) (14.1)
--------------------------------------------------------------------- ----------
Other purchases (0.7)
--------------------------------------------------------------------- ----------
TOTAL CAPACITY EXPENSE (14.8)
--------------------------------------------------------------------- ----------
Operating Distribution Division O&M expense:
--------------------------------------------------------------------- ----------
1999 fossil generation unit operating and maintenance costs (7.1)
--------------------------------------------------------------------- ----------
Pension and other employee benefit costs (5.0)
--------------------------------------------------------------------- ----------
NEPOOL transmission expense 1.9
--------------------------------------------------------------------- ----------
Other (8.3)
--------------------------------------------------------------------- ----------
TOTAL OPERATING DISTRIBUTION DIVISION (18.5)
--------------------------------------------------------------------- ----------
Other unbundled components of O&M expense:
--------------------------------------------------------------------- ----------
Nuclear Division (see Note B) (3.5)
--------------------------------------------------------------------- ----------
Conservation and Load Management, Renewable Energy and System
Benefits (see note B) 9.8
--------------------------------------------------------------------- ----------
TOTAL OTHER COMPONENTS 6.3
--------------------------------------------------------------------- ----------
TOTAL O&M EXPENSE (27.0)
--------------------------------------------------------------------- ----------
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 six months of 2000 of about $13.3 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 $2.5 million
of the reduction was due to the absence of refueling outage costs
incurred in the first six months 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 $3.4 million in the
first six months of 2000 compared to the first six months of 1999, due
principally to the generating plant sale in April of 1999.
- 26 -
<PAGE>
Depreciation expense decreased by $19.1 million in the first six months of
2000 compared to the first six months of 1999. About $11.0 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
$4.8 million of the decrease was due to the completion of depreciation of
conservation assets in the first half of 1999, and another $2.8 million was due
to the generation asset sale in 1999. Other depreciation expenses decreased by
$0.5 million.
Amortization of regulatory assets decreased by $6.9 million in the first
six months of 2000 compared to the first six months 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 six months of
2000 amounted to $25.7 million (pre-tax) and were: nuclear assets (from
depreciation) $10.2 million, purchased power contracts (in place of purchased
power expense) $13.3 million, displaced worker costs $1.3 million, and other
$0.9 million. However, because the result of these amortizations produced
returns on both the CTA and SBC below the 11.5% return allowed, $25.0 million
(before-tax) of amortization was deferred for the first six months of 2000. The
elimination (completed in 1999) of $3.1 million (after-tax) of amortization of
Seabrook Nuclear Station deferred return also reduced amortization expense in
the first six months of 2000 compared to the first six months of 1999.
The exceptions noted in the previous paragraph are amortizations that apply
to the operating Distribution Division. They include the amortization of Retail
Access assets, $0.9 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 $4.4 million (after-tax) of accelerated amortization was charged in
the first six months of 2000, compared to about $6.0 million (after-tax) in
1999, for a decrease of $1.6 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 six months 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 period.
Interest charges for the regulated business continued on a downward trend,
decreasing by $8.6 million in the first six months of 2000 compared to the first
six months of 1999, partly offset by an increase of $3.7 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 $0.3 million, or $.02 per share, in the first six months of
2000, compared to losses of about $2.4 million, or $.17 per share, in the first
six months of 1999.
The results of each of the subsidiaries of URI for the first six months 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
- 27 -
<PAGE>
appropriate for that type of business. American Payment Systems, Inc. earned
approximately $1.3 million, or $.09 per share, in the first six months of 2000,
reflecting an increase of $1.0 million, or $.07 per share, over the first six
months of 1999. Xcelecom, Inc. lost approximately $0.2 million, or $.01 per
share, in the first six months of 2000, compared to a loss of approximately $1.6
million, or $.12 per share, in the first six months of 1999. The improvement was
the result of cost reduction efforts and the acquisitions of the Allan Electric
Co., Inc. and the DataStore Incorporated.
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 $1.1
million, or $.08 per share, in the first six months of 2000, compared to a loss
of about $0.6 million, or $.05 per share, in the first six months of 1999. The
2000 loss was the result of a shutdown to repair the steam turbine and to make
modifications to the combustion turbine. These repairs and modifications were
partly completed in June and partial service was resumed in June. Full service
was resumed in mid-July. United Capital Investments, Inc. earned approximately
$1.0 million, or $.07 per share, in the first six months of 2000, compared to a
loss of approximately $0.4 million, or $.03 per share, in the first six months
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. The
remaining non-regulated businesses loss of $.06 per share comparing the second
quarter of 2000 to the second quarter of 1999 was the result of higher interest
charges at the non-regulated parent URI.
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. Utility earnings will not likely ever exceed the sharing level
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 earnings in the third quarter that exceed that level and all positive
utility earnings recorded in the fourth quarter of that year will be subject to
"sharing."
- 28 -
<PAGE>
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
enacted 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 at least 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 April 24, 2000, the Company estimated its year 2000 earnings would be in
the range of $3.95-$4.10 per share. Following better than expected first and
second 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 $4.25-$4.35 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 and second
quarters of 2000 would produce additional earnings, although a four-week
refueling outage is scheduled for the Seabrook nuclear generating unit in the
fourth quarter of 2000.
Sharing will be significantly reduced from the 1999 levels, due to mandates
in the restructuring legislation. The Company expects sharing to contribute no
more than $.30-$.35 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 the same level as
previously expected. 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 about $.05 per share. Xcelecom, 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. 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
- 29 -
<PAGE>
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
Unit 1 and Millstone Unit 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, the Seabrook unit 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.
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.
The Company's current overall estimate of earnings per share from
operations for 2000 is $4.25-$4.35 and the estimates of quarterly results are as
follows:
Earnings per share from operations:
Estimated Actual
Quarter 2000 Range 1999
------- ---------- ----
1 $1.20 (Actual) $ .66
2 $1.41 (Actual) .99
3 $1.10 - $1.25 1.78
4 $ .44 - $ .59 .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 same is true for the high range numbers. 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 $4.25-$4.35 per share.
A look at 2001; continued growth of non-regulated businesses value
------------------------------------------------------------------
Currently, the Company is estimating earnings for 2001 to be in the same
range expected for 2000, $4.25-$4.35 per share. Continued strong growth is
forecast in the non-regulated businesses sector, which is expected to contribute
9-11 percent of total earnings for the year. About one-half of the non-regulated
businesses earnings should be contributed by Xcelecom, Inc., with the balance
spread among the other URI subsidiaries. The growth in the non-regulated sector
will be offset by a reduction of regulated business earnings in 2001. The
largest single influence on the forecasted downturn in utility earnings for 2001
is additional scheduled non-cash amortization. The Company's current and
anticipated performance is underscored by its continuing strong cash flow.
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.
- 30 -
<PAGE>
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 Part I, Item 2, "Properties - Nuclear Generation" of the Company's
Annual Report (Form 10-K) for the fiscal year ended December 31, 1999, the
Company and the two other minority, non-NU joint owners that continued to
prosecute the arbitration proceeding and lawsuits against NU following
settlements by the seven other minority, non-NU joint owners of their claims
against NU, have settled their claims against NU and stipulated to the dismissal
of all claims in the arbitration proceeding and lawsuits. The July 24, 2000
settlement agreement between the Company and NU involves the payment by NU to
the Company of approximately $15 million and certain contingent payments, and
provided for the inclusion of the Company's Millstone Unit 3 ownership interest
in NU's Millstone Station nuclear auction sale conducted by J. P. Morgan & Co.
pursuant to Connecticut's Restructuring Act.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Annual Meeting of the Shareowners of the Company was held on June 26,
2000, for the purpose of electing a Board of Directors for the ensuing year and
voting on approval of the employment of PricewaterhouseCoopers LLP as the firm
of independent public accountants to audit the books and affairs of the Company
for the fiscal year 2000.
All of the nominees for election as Directors listed in the Company's proxy
statement for the meeting were elected by the following votes:
NUMBER OF SHARES
-----------------------------------
VOTED NOT
NOMINEE "FOR" VOTED
------- ----- -----
Thelma R. Albright 12,524,540 166,772
Marc C. Breslawsky 12,525,354 165,957
David E. A. Carson 12,523,453 167,858
Arnold L. Chase 12,518,955 172,355
John F. Croweak 12,523,905 167,407
Robert L. Fiscus 12,522,379 168,934
Betsy Henley-Cohn 12,515,915 175,398
John L. Lahey 12,522,300 169,012
F. Patrick McFadden, Jr. 12,523,844 167,470
Daniel J. Miglio 12,514,398 176,913
James A. Thomas 12,522,505 168,806
Nathaniel D. Woodson 12,520,827 170,486
The employment of PricewaterhouseCoopers LLP as the firm of independent
public accountants to audit the books and affairs of the Company for the fiscal
year 2000 was approved by the following vote:
NUMBER OF SHARES
------------------------------------------------
VOTED VOTED NOT
"FOR" "AGAINST" VOTED
----- --------- -----
12,544,129 60,397 86,782
- 31 -
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
---------- ------- -----------
<S> <C> <C>
(3) 3.2a Copy of Article III, Section 2 of Bylaws of The United Illuminating
Company, amending Exhibit 3.2.*
(10) 10.2f Copy of 2000 Amendatory Agreement between The United Illuminating
Company and Connecticut Yankee Atomic Power Company, dated July 28,
2000, amending Exhibits 10.2b** and 10.2c***.
(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 June 30, 2000 and Twelve
Months Ended December 31, 1999, 1998, 1997, 1996 and 1995).
(21) 21a List of subsidiaries of The United Illuminating Company, superseding
Exhibit 21****.
(27) 27 Financial Data Schedule.
</TABLE>
* Filed with Quarterly Report on Form 10-Q for fiscal quarter ended March 31,
1999.
** Filed with Annual Report on Form 10-K for fiscal year ended December 31,
1995.
*** Filed with Annual Report on Form 10-K for fiscal year ended December 31,
1996.
**** Filed with Annual Report on Form 10-K for fiscal year ended December 31,
1999.
(b) Reports on Form 8-K.
None
- 32 -
<PAGE>
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 08/14/2000 Signature /s/ Robert L. Fiscus
-------------- -------------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
- 33 -
<PAGE>
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.
UIL HOLDINGS CORPORATION
Date 08/14/2000 Signature /s/ Robert L. Fiscus
----------------- ------------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors,
Chief Financial Officer, Treasurer and
Secretary
- 34 -
<PAGE>
