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 SEPTEMBER 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
NONE
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of September 30, 1998, was 14,334,922.
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<PAGE>
INDEX
Part I. FINANCIAL INFORMATION
PAGE
NUMBER
-------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three and nine months
ended September 30, 1998 and 1997. 3
Consolidated Balance Sheet as of September 30, 1998 and
December 31, 1997. 4
Consolidated Statement of Cash Flows for the three and nine
months ended September 30, 1998 and 1997. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 8
- Rate-Related Regulatory Proceedings 9
- Short-term Credit Arrangements 11
- Income Taxes 12
- Supplementary Information 13
- Fuel Financing Obligations and Other Lease Obligations 14
- Commitments and Contingencies 14
- Capital Expenditure Program 14
- Nuclear Insurance Contingencies 14
- Other Commitments and Contingencies 15
- Connecticut Yankee 15
- Hydro-Quebec 15
- Property Taxes 16
- Site Decontamination, Demolition and Remediation Costs 16
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 16
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 18
- Major Influences on Financial Condition 18
- Capital Expenditure Program 22
- Liquidity and Capital Resources 23
- Subsidiary Operations 24
- Results of Operations 25
- Looking Forward 28
Part II. OTHER INFORMATION
Item 1. Legal Proceedings. 35
Item 6. Exhibits and Reports on Form 8-K. 36
SIGNATURES 37
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<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 Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
OPERATING REVENUES (NOTE G) $198,601 $196,563 $520,867 $540,662
------------- ------------- ------------- ------------
OPERATING EXPENSES
Operation
Fuel and energy 39,701 44,024 113,654 137,965
Capacity purchased 9,124 8,359 24,324 30,198
Other 36,384 38,415 107,787 115,324
Maintenance 10,981 10,122 32,574 30,016
Depreciation 23,247 17,239 64,685 57,945
Amortization of cancelled nuclear project and deferred return 3,440 3,440 10,319 10,319
Income taxes (Note F) 24,448 23,101 47,128 35,128
Other taxes (Note G) 13,814 13,512 39,083 40,574
------------- ------------- ------------- ------------
Total 161,139 158,212 439,554 457,469
------------- ------------- ------------- ------------
OPERATING INCOME 37,462 38,351 81,313 83,193
------------- ------------- ------------- ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction (35) (12) 35 330
Other-net (Note G) 1,798 83 (2,218) 1,589
Non-operating income taxes 701 1,981 3,707 4,920
------------- ------------- ------------- ------------
Total 2,464 2,052 1,524 6,839
------------- ------------- ------------- ------------
INCOME BEFORE INTEREST CHARGES 39,926 40,403 82,837 90,032
------------- ------------- ------------- ------------
INTEREST CHARGES
Interest on long-term debt 11,759 16,233 38,161 48,481
Interest on Seabrook obligation bonds owned by the company (1,817) (1,691) (5,453) (5,073)
Other interest (Note G) 2,169 872 4,445 2,490
Allowance for borrowed funds used during construction (241) (288) (505) (1,127)
------------- ------------- ------------- ------------
11,870 15,126 36,648 44,771
Amortization of debt expense and redemption premiums 617 672 1,885 1,998
------------- ------------- ------------- ------------
Net Interest Charges 12,487 15,798 38,533 46,769
------------- ------------- ------------- ------------
MINORITY INTEREST IN PREFERRED SECURITIES 1,203 1,203 3,609 3,609
------------- ------------- ------------- ------------
NET INCOME 26,236 23,402 40,695 39,654
Discount on preferred stock redemptions 0 (29) (21) (48)
Dividends on preferred stock 50 51 151 154
------------- ------------- ------------- ------------
INCOME APPLICABLE TO COMMON STOCK $26,186 $23,380 $40,565 $39,548
============= ============= ============= ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,028 13,887 14,012 14,029
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,032 13,908 14,018 14,036
EARNINGS PER SHARE OF COMMON STOCK - BASIC $1.87 $1.68 $2.90 $2.82
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $1.87 $1.68 $2.89 $2.82
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72 $2.16 $2.16
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
<CAPTION>
September 30, December 31,
1998 1997*
---- ----
(Unaudited)
<S> <C> <C>
Utility Plant at Original Cost
In service $1,875,768 $1,867,145
Less, accumulated provision for depreciation 698,371 644,971
--------------- ---------------
1,177,397 1,222,174
Construction work in progress 27,202 25,448
Nuclear fuel 22,928 25,990
--------------- ---------------
Net Utility Plant 1,227,527 1,273,612
--------------- ---------------
Other Property and Investments 35,561 32,451
--------------- ---------------
Current Assets
Cash and temporary cash investments 13,329 32,002
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 66,013 57,231
Other 33,000 27,914
Accrued utility revenues 23,945 25,269
Fuel, materials and supplies, at average cost 29,029 19,147
Prepayments 31,189 3,397
Other 143 67
--------------- ---------------
Total 196,648 165,027
--------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 8,924 6,611
Other 3,443 5,727
--------------- ---------------
Total 12,367 12,338
--------------- ---------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 216,453 228,992
Connecticut Yankee 46,666 51,313
Deferred return - Seabrook Unit 1 15,732 25,171
Unamortized redemption costs 21,994 23,027
Unamortized cancelled nuclear projects 11,245 12,125
Uranium enrichment decommissioning cost 1,211 1,312
Other 5,311 6,357
--------------- ---------------
Total 318,612 348,297
--------------- ---------------
$1,790,715 $1,831,725
=============== ===============
</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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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
<CAPTION>
September 30, December 31,
1998 1997*
---- ----
(Unaudited)
<S> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $292,006 $288,730
Paid-in capital 1,978 1,349
Capital stock expense (2,182) (2,182)
Unearned employee stock ownership plan equity (10,447) (11,160)
Retained earnings 172,506 162,226
--------------- ---------------
453,861 438,963
Preferred stock 4,299 4,351
Minority interest in preferred securities 50,000 50,000
Long-term debt
Long-term debt 657,501 746,058
Investment in Seabrook obligation bonds (92,860) (101,388)
--------------- ---------------
Net long-term debt 564,641 644,670
--------------- ---------------
Total 1,072,801 1,137,984
--------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 36,905 40,821
Pensions accrued 34,794 39,149
Nuclear decommissioning obligation 21,568 17,538
Obligations under capital leases 16,596 16,853
Other 6,343 5,507
--------------- ---------------
Total 116,206 119,868
--------------- ---------------
Current Liabilities
Current portion of long-term debt 74,574 100,000
Notes payable 113,195 37,751
Accounts payable 38,750 68,699
Dividends payable 10,150 10,051
Taxes accrued 20,355 4,166
Interest accrued 14,330 10,266
Obligations under capital leases 345 340
Other accrued liabilities 40,313 37,471
--------------- ---------------
Total 312,012 268,744
--------------- ---------------
Customers' Advances for Construction 1,866 1,878
--------------- ---------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,814 16,385
Other 5,053 2,356
--------------- ---------------
Total 20,867 18,741
--------------- ---------------
Deferred Income Taxes (future tax liabilities owed 266,963 284,510
to taxing authorities)
Commitments and Contingencies (Note L)
--------------- ---------------
$1,790,715 $1,831,725
=============== ===============
</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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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $26,236 $23,402 $40,695 $39,654
------------ ----------- ------------ -------------
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 24,419 18,405 68,167 61,460
Deferred income taxes 271 5,609 (5,009) (5,356)
Deferred investment tax credits - net (190) (190) (571) (571)
Amortization of nuclear fuel 1,641 1,785 4,138 4,662
Allowance for funds used during construction (206) (276) (540) (1,457)
Amortization of deferred return 3,146 3,146 9,439 9,439
Changes in:
Accounts receivable - net (10,342) (6,754) (13,868) 16,417
Fuel, materials and supplies 1,680 1,007 (9,882) 1,966
Prepayments (21,711) (3,687) (27,792) (4,278)
Accounts payable (14,096) (517) (29,949) (25,172)
Interest accrued (3,853) (6,529) 4,064 2,608
Taxes accrued 14,269 9,202 16,189 11,103
Other assets and liabilities 1,693 336 2,888 (1,998)
------------ ----------- ------------ -------------
Total Adjustments (3,279) 21,537 17,274 68,823
------------ ----------- ------------ -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 22,957 44,939 57,969 108,477
------------ ----------- ------------ -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 308 (10,390) 4,618 (10,390)
Long-term debt - 98,500 99,780 98,500
Notes payable (5,630) 8,354 75,444 33,030
Securities redeemed and retired:
Preferred stock - (70) (52) (110)
Long-term debt - (55,749) (213,976) (88,334)
Discount on preferred stock redemption - 29 21 48
Expense of issue - (1,500) (800) (1,500)
Lease obligations (86) (80) (252) (234)
Dividends
Preferred stock (50) (51) (152) (155)
Common stock (10,095) (10,153) (30,185) (30,459)
------------ ----------- ------------ -------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (15,553) 28,890 (65,554) 396
------------ ----------- ------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (9,047) (4,215) (19,616) (28,402)
Investment in debt securities - - 8,528 -
------------ ----------- ------------ -------------
NET CASH USED IN INVESTING ACTIVITIES (9,047) (4,215) (11,088) (28,402)
------------ ----------- ------------ -------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (1,643) 69,614 (18,673) 80,471
BALANCE AT BEGINNING OF PERIOD 14,972 17,251 32,002 6,394
------------ ----------- ------------ -------------
BALANCE AT END OF PERIOD $13,329 $86,865 $13,329 $86,865
============ =========== ============ =============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $13,895 $19,819 $33,345 $40,578
============ =========== ============ =============
Income taxes $12,100 $9,000 $35,150 $26,773
============ =========== ============ =============
</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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The consolidated financial statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all adjustments that are, in the opinion of management, necessary to a fair
statement of the results for the periods presented. All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations. The Company believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year ended December 31, 1997. 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 nine months of 1998
and 1997 was 7.33% and 7.83%, respectively, on a before-tax basis.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments. The Company records outstanding checks
as accounts payable until the checks have been honored by the banks.
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 $1.9 million in the first nine months of
each of 1998 and 1997 into the decommissioning trust funds for Seabrook Unit 1
and Millstone Unit 3. At September 30, 1998, the Company's shares of the trust
fund balances, which included accumulated earnings on the funds, were $15.4
million and $6.2 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.
INTEREST RATE AND FUEL PRICE MANAGEMENT
The Company utilizes interest rate and fuel oil price management
instruments to manage interest rate and fuel oil price risk. Interest rate swap
agreements have been entered into that effectively convert the interest rates on
$225 million of variable rate borrowings to fixed rate borrowings. Amounts
receivable or payable under these swap agreements are accrued and charged to
interest expense. The Company enters into basic fuel oil price management
instruments to help minimize fuel oil price risk by fixing the future price for
fuel oil used for generation. Amounts receivable or payable under these
instruments are recognized in income when realized.
As of September 30, 1998, the Company had swap agreements for 1998 for
225,000 barrels of fuel oil at a weighted average price of $15.96 per barrel.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
(A) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at September 30, 1998, of which 307,345 shares were unallocated
shares held by the Company's Employee Stock Ownership Plan ("ESOP") 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. The plan
provides for the awarding of options to purchase up to 750,000 shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date of the grant. 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 September 30, 1998. Options to purchase 14,299 shares of
stock at an exercise price of $30 per share, 54,500 shares of stock at an
exercise price of $30.75 per share, 4,000 shares of stock at an exercise price
of $35.625 per share, and 25,999 shares of stock at an exercise price of
$39.5625 per share were exercised during the first nine months of 1998.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of September 30, 1998, 307,345 shares, with a fair market value of
$16.1 million, had been purchased by the ESOP and had not been committed to be
released or allocated to ESOP participants.
(B) RETAINED EARNINGS RESTRICTION
The indenture under which $166.2 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 $114.3 million were free from such limitations at September 30, 1998.
(C) PREFERRED STOCK
In April 1998, the Company purchased at a discount on the open market, and
canceled, 524 shares of its $100 par value 4.35%, Series A preferred stock. The
shares, having a par value of $52,400 were purchased for $31,440, creating a net
gain of $20,960.
(E) LONG-TERM DEBT
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven-month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On June 8, 1998, the Company repaid a $50 million Term Loan prior to its
August 29, 2000 due date. On June 8, 1998, the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.
(C) RATE-REGULATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility industry. The business of generating and supplying electricity to
consumers will be opened to competition and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of delivering electricity will remain with the incumbent franchised utility
companies (including the Company). Beginning in 2000, each retail consumer of
electricity in Connecticut (excluding consumers served by municipal electric
systems) will be able to choose his, her or its supplier of electricity from
among competing licensed suppliers, for delivery over the wires system of the
franchised electric utility (Distribution Company). Commencing no later than
mid-1999, Distribution Companies will be required to separate on consumers'
bills the charge for electricity generation services from the charge for
delivering the electricity and all other charges. On July 29, 1998, the DPUC
issued the first of what are expected to be several orders relative to this
"unbundling" requirement.
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 and the systems benefits charge represent costs that either have been
or will be reasonably incurred by Distribution Companies to meet their public
service obligations as 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 costs of conservation programs and renewable energy investments are
new charges established in the Restructuring Act. Beginning in 2000, the
Distribution Company must collect the competitive transition assessment, systems
benefits charge, and conservation and load management and renewable investment
charges from all Distribution Company customers. The Distribution Company will
also be required to offer a "standard offer" rate that is, subject to certain
adjustments, at least 10% below its fully bundled price for electricity at
December 31, 1996, as discussed below. The standard offer is required, subject
to certain adjustments, to be the total rate charged under the standard offer,
including transmission and distribution services, the competitive transition
assessment, the systems benefits charge, the conservation and load management
program charge and the renewable energy charge. The Restructuring Act requires
that, in order for a Distribution Company to recover any stranded costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess proceeds used to mitigate its recoverable stranded
costs, and the Company must attempt to divest its ownership interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval, an "unbundling plan" to
separate, on or before October 1, 1999, all of its power plants that will not
have been sold prior to the DPUC's approval of the unbundling plan or will not
be sold prior to 2000.
In May of 1998 the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission, and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.
- 9 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation costs and other costs, such that there will be no net income effect
of the sale. Net cash proceeds from the sale are expected to be in the range of
$160-$165 million. The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special dividend or stock buyback, and for
growth opportunities.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that its unbundling plan for the
Company's nuclear generation ownership interests, 17.5% of Seabrook Station, in
New Hampshire, and 3.685% of Millstone Station Unit No. 3, in Connecticut, is
divestiture by the end of 2003 in accordance with the Restructuring Act. The
divestiture method has not yet been determined. In anticipation of ultimate
divestiture, the Company proposed to satisfy, on a functional basis, the
Restructuring Act's requirement that nuclear generating assets be separated from
its transmission and distribution assets. This would be accomplished by
transferring the nuclear generating assets into separate new divisions of the
Company, using divisional financial statements and accounting to segregate all
revenues, expenses, assets and liabilities associated with each nuclear
ownership interest.
The Company's unbundling plan also proposes to facilitate the clear
functional separation of the Company's ongoing regulated transmission and
distribution operations and functions from all of its unregulated operations and
activities by undergoing a corporate restructuring into a holding company
structure. In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company will be converted into a share of common stock of the holding
company. In connection with the formation of the holding company structure, all
of the Company's interests in all of its operating unregulated subsidiaries will
be transferred to the holding company and, to the extent new unregulated
businesses are subsequently acquired or commenced, they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power adjustment clause be added to its regulated rates, effective
July 1, 2000. This clause, similar to and based on the purchased gas adjustment
clauses used by Connecticut's natural gas local distribution companies, would
work in tandem with the Company's procurement of power supplies to assure that
standard offer customers pay competitive market rates for generation services
even though they do not choose an alternate electricity supplier. The
Distribution Company is also required under the Restructuring Act to provide
back-up service to customers whose electric supplier fails to provide electric
generation services for reasons other than the customers' failure to pay for
such services. The Restructuring Act provides for the Distribution Company to
recover its reasonable costs of providing this back-up service.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The 1997 through 2001 rate plan agreed to between the DPUC and the Company in
1996 anticipated sufficient income in 2000 to accelerate amortization of
regulatory assets of about $50 million, equivalent to about 8% of retail
revenues. Substantially all of this accelerated amortization may have to be
eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The 1996 five-year rate plan includes a provision that it may be reopened
and modified upon the enactment of electric industry restructuring legislation
in Connecticut. However, the Company is unable to predict, at this time, whether
or when or in what respects the 1996 five-year plan will be modified on account
of the enactment of the 1998 Restructuring Act.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The Company expects that this agreement
will be extended to December 1999. The borrowing limit of this facility is $75
million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
September 30, 1998, the Company had $29.3 million of short-term borrowings
outstanding under this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of September 30, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
In addition, as of September 30, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $3.8 million
outstanding under a bank line of credit agreement.
- 11 -
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<CAPTION>
Three Months Ended Nine Months Ended
(F) INCOME TAXES September 30, September 30,
1998 1997 1998 1997
---- ---- ---- ----
(000's) (000's)
<S> <C> <C> <C> <C>
Income tax expense consists of:
Income tax provisions:
Current
Federal $18,331 $11,899 $37,957 $27,346
State 5,335 3,802 11,044 8,789
------------ ------------ ------------ ------------
Total current 23,666 15,701 49,001 36,135
------------ ------------ ------------ ------------
Deferred
Federal 184 4,602 (3,510) (3,397)
State 87 1,007 (1,499) (1,959)
------------ ------------ ------------ ------------
Total deferred 271 5,609 (5,009) (5,356)
------------ ------------ ------------ ------------
Investment tax credits (190) (190) (571) (571)
------------ ------------ ------------ ------------
Total income tax expense $23,747 $21,120 $43,421 $30,208
============ ============ ============ ============
Income tax components charged as follows:
Operating expenses $24,448 $23,101 $47,128 $35,128
Other income and deductions - net (701) (1,981) (3,707) (4,920)
------------ ------------ ------------ ------------
Total income tax expense $23,747 $21,120 $43,421 $30,208
============ ============ ============ ============
The following table details the components
of the deferred income taxes:
Conservation and load management ($2,922) ($931) ($6,935) ($5,022)
Accelerated depreciation 1,535 1,459 4,603 4,378
Tax depreciation on unrecoverable plant investment 1,212 1,232 3,636 3,695
Seabrook sale/leaseback transaction 808 1,486 (3,553) (3,686)
Pension benefits 1,020 1,983 2,003 2,092
Postretirement benefits (94) 187 (302) (105)
Fossil fuel decommissioning reserve (82) (142) (247) (7,144)
Unit overhaul and replacement power costs (361) (287) 101 1,099
Other - net (845) 622 (4,315) (663)
------------ ------------ ------------ ------------
Deferred income taxes - net $271 $5,609 ($5,009) ($5,356)
============ ============ ============ ============
</TABLE>
- 12 -
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
---- ---- ---- ----
(000's) (000's)
<S> <C> <C> <C> <C>
Operating Revenues
- ------------------
Retail $185,982 $177,323 $481,749 $473,848
Wholesale - capacity 2,661 2,483 8,974 7,265
- energy 6,575 15,510 23,523 56,783
Other 3,383 1,247 6,621 2,766
-------------- ------------- ------------- --------------
Total Operating Revenues $198,601 $196,563 $520,867 $540,662
============== ============= ============= ==============
Sales by Class(MWH's)
- --------------------
Retail
Residential 553,475 505,070 1,462,288 1,415,844
Commercial 639,637 613,924 1,771,401 1,697,625
Industrial 312,088 305,492 870,705 867,082
Other 11,874 12,008 35,895 36,256
-------------- ------------- ------------- --------------
1,517,074 1,436,494 4,140,289 4,016,807
Wholesale 279,868 608,754 1,043,657 2,104,892
-------------- ------------- ------------- --------------
Total Sales by Class 1,796,942 2,045,248 5,183,946 6,121,699
============== ============= ============= ==============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $7,154 $6,777 $18,325 $18,005
Local real estate and personal property 5,316 5,451 16,217 17,742
Payroll taxes 1,338 1,284 4,535 4,827
Other 6 0 6 0
-------------- ------------- ------------- --------------
13,814 13,512 39,083 40,574
Nonoperating and other accounts 105 111 398 343
-------------- ------------- ------------- --------------
Total Other Taxes $13,919 $13,623 $39,481 $40,917
============== ============= ============= ==============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $2,134 $458 $2,794 $1,384
Equity earnings from Connecticut Yankee 168 312 693 1,000
Earnings (Loss) from subsidiary companies (85) (75) (4,613) (970)
Miscellaneous other income and (deductions) - net (419) (612) (1,092) 175
-------------- ------------- ------------- --------------
Total Other Income and (Deductions) - net $1,798 $83 ($2,218) $1,589
============== ============= ============= ==============
Other Interest Charges
- ----------------------
Notes Payable $527 $749 $1,842 $1,949
Other 1,642 123 2,603 541
-------------- ------------- ------------- --------------
Total Other Interest Charges $2,169 $872 $4,445 $2,490
============== ============= ============= ==============
</TABLE>
- 13 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for financing up to $37.5 million of fossil fuel purchases. Under this
agreement, the financing entity may acquire and/or store natural gas, coal and
fuel oil for sale to the Company, and the Company may purchase these fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in purchasing and
storing the fuel, plus a charge for maintaining an inventory of the fuel
determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to November 1999. At September 30, 1998, no fossil fuel purchases were being
financed under this agreement.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $149.6 million, excluding AFUDC, for 1998 through 2002.
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 $75.5 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 $75.5 million, or
$3.775 million. The maximum assessment is adjusted at least every five years to
reflect the impact of inflation. With respect to each of the three 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 $23.2 million per incident. However, any
assessment would be limited to $3.1 million per incident per year.
The NRC requires each 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 three
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
$5.0 million.
- 14 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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
and had relied on the Connecticut Yankee Unit for approximately 3.7% of the
Company's 1995 total generating resources. 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 UI. 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. UI expects that it will continue to be allowed
to recover its share of all FERC-approved costs from its customers through
retail rates. The Company's estimate of its remaining share of costs, including
decommissioning, less return of investment (approximately $9.8 million) and
return on investment (approximately $5.6 million) at September 30, 1998, is
approximately $36.9 million. This estimate, which is subject to ongoing review
and revision, has been recorded by the Company as a regulatory asset and an
obligation on the Consolidated Balance Sheet.
On August 31, 1998, a FERC Administrative Law Judge (ALJ) released an
initial decision regarding Connecticut 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
recovery of a portion of the return on Connecticut Yankee's investment in the
unit. 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 this
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 investment. The Company cannot predict, at this time, the
outcome of the FERC proceeding. However, the Company will continue to support
Connecticut Yankee's efforts to contest the ALJ's initial decision.
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. A
ten-year Firm Energy Contract, which provides for the sale of 7 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, became effective on July 1, 1991. Additionally, the Company
is obligated to furnish a guarantee for its participating share of the debt
financing for the Phase II facility. As of September 30, 1998, the Company's
guarantee liability for this debt was approximately $7.0 million.
- 15 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
PROPERTY TAXES
The City of New Haven (the City) and the Company are involved in a dispute
over the amount of personal property taxes owed to the City for tax years
beginning with 1991-1992. On May 8, 1998, the City and the Company reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992 through 1997-1998 and the
Company's personal property tax assessments for the tax year 1998-1999 and
subsequent years. Under the terms of this settlement, the Company will pay the
City $14.025 million, subject to Superior Court approval of the settlement and
conditioned on the Company receiving authorization from the DPUC to recover the
settlement amount from its retail customers. The DPUC denied the Company's
initial application for such authorization and the City has agreed to extend to
November 30, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million, which has been
recognized as a prepayment of property taxes. The Company filed a second
application with the DPUC on July 9, 1998. If the DPUC authorization is not
forthcoming, the $6 million payment will be applied to future tax bills.
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 $8.3 million had been incurred as of September 30, 1998, 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.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities.
Remediation costs, including the repair and/or replacement of approximately 560
linear feet of sheet piling, are currently estimated at $7.5 million. In
addition, the Company is planning to repair and/or replace the remaining
deteriorated sheet piling bordering the English Station property, at an
additional estimated cost of $10 million.
As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company has contracted to sell its Bridgeport Harbor Station and New Haven
Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. Environmental assessments performed
in connection with the marketing of these plants indicate that substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable Connecticut minimum standards following their sale.
The proposed 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 $473 million (in 1998 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $83 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. UI's share of the decommissioning payments made
during the first nine months of 1998 was $1,570,000. UI's share of the fund at
September 30, 1998 was approximately $15.4 million.
- 16 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $557 million (in 1998 dollars), of which the
Company's share would be approximately $21 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). UI's share of the Millstone Unit 3 decommissioning payments made
during the first nine months of 1998 was $365,000. UI's share of the fund at
September 30, 1998 was approximately $6.2 million. The current decommissioning
cost estimate for the Connecticut Yankee Unit, assuming the prompt removal and
dismantling of the unit commencing in 1997, is $456 million, of which UI's share
would be $43 million. Through September 30, 1998, $53.8 million has been
expended for decommissioning. The projected remaining decommissioning cost is
$402.2 million, of which UI's share would be $38.2 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
$1,767,000 were funded by UI during the first nine months of 1998, and UI's
share of the fund at September 30, 1998 was $24.0 million.
- 17 -
<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 retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, has
averaged less than 1.5% during the past 5 years. The Company hopes to continue
to restrict this average to less than the rate of inflation in future years (see
"Looking Forward").
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
and competition within the electric utility industry.
On December 31, 1996, the Connecticut Department of Public Utility Control
(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 DPUC
did not change the existing retail base rates charged to customers; but its
order increased amortization of the Company's conservation and load management
program investments during 1997-1998, and accelerated the recovery of
unspecified regulatory assets during 1999-2001 if the Company's common stock
equity return on utility investment exceeds 10.5% after recording the increased
conservation and load management amortization. The order also reduced the level
of conservation adjustment mechanism revenues in retail prices, provided a
reduction in customer prices through a surcredit in each of the five plan years,
and accepted 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 regulatory assets, and one-third retained as earnings. As a
result of the DPUC's order, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Retail revenues actually decreased by
approximately $30 million, or 4.6%, in 1997 due to customer price reductions.
Also as a result of the order, customer prices are required to be reduced by an
additional 1% in 2000, and another 1% in 2001, compared to 1996. The DPUC's
order has been reopened in 1998, in accordance with its terms, to determine the
regulatory assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC has not yet determined the assets to be subjected to accelerated
recovery in 1999; but a decision in this regard is expected to be issued before
the end of 1998. The DPUC has decided that it will not determine in 1998 the
assets to be subjected to recovery after 1999. The DPUC's 1996 order also
includes a provision that it may be reopened and modified upon the enactment of
electric utility restructuring legislation in Connecticut and, as a consequence
of the restructuring legislation described below, the 1996 order may be reopened
and modified. However, the Company is unable to predict, at this time, whether
or when or in what respects the 1996 order will be modified on account of this
legislation.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility industry. The business of generating and supplying electricity to
consumers will be opened to competition and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of delivering electricity will remain with the incumbent franchised utility
companies (including the Company). Beginning in 2000, each retail consumer of
electricity in Connecticut (excluding consumers served by municipal electric
systems) will be able to choose his, her or its supplier of electricity from
among competing licensed suppliers, for delivery over the wires system of the
franchised electric utility (Distribution Company). Commencing no later than
mid-1999, Distribution Companies will be required to separate on consumers'
bills the charge for electricity generation services from the charge for
delivering the electricity and all other charges. On July 29, 1998, the DPUC
issued the first of what are expected to be several orders relative to this
"unbundling" requirement.
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"
- 18 -
<PAGE>
and a "renewable energy investment charge." The competitive transition
assessment and the systems benefits charge represent costs that either have been
or will be reasonably incurred by Distribution Companies to meet their public
service obligations as 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 costs of conservation programs and renewable energy investments are
new charges established in the Restructuring Act. Beginning in 2000, the
Distribution Company must collect the competitive transition assessment, systems
benefits charge, and conservation and load management and renewable investment
charges from all Distribution Company customers. The Distribution Company will
also be required to offer a "standard offer" rate that is, subject to certain
adjustments, at least 10% below its fully bundled price for electricity at
December 31, 1996, as discussed below. The standard offer is required, subject
to certain adjustments, to be the total rate charged under the standard offer,
including transmission and distribution services, the competitive transition
assessment, the systems benefits charge, the conservation and load management
program charge and the renewable energy charge. The Restructuring Act requires
that, in order for a Distribution Company to recover any stranded costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess proceeds used to mitigate its recoverable stranded
costs, and the Company must attempt to divest its ownership interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval, an "unbundling plan" to
separate, on or before October 1, 1999, all of its power plants that will not
have been sold prior to the DPUC's approval of the unbundling plan or will not
be sold prior to 2000.
In May of 1998 the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission, and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation costs and other costs, such that there will be no net income effect
of the sale. Net cash proceeds from the sale are expected to be in the range of
$160-$165 million. The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special dividend or stock buyback, and for
growth opportunities.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that its unbundling plan for the
Company's nuclear generation ownership interests, 17.5% of Seabrook Station, in
New Hampshire, and 3.685% of Millstone Station Unit No. 3, in Connecticut, is
divestiture by the end of 2003 in accordance with the Restructuring Act. The
divestiture method has not yet been determined. In anticipation of ultimate
divestiture, the Company proposed to satisfy, on a functional basis, the
Restructuring Act's requirement that nuclear generating assets be separated from
its transmission and distribution assets. This would be accomplished by
transferring the nuclear generating assets into separate new divisions of the
Company, using divisional financial statements and accounting to segregate all
revenues, expenses, assets and liabilities associated with each nuclear
ownership interest.
- 19 -
<PAGE>
The Company's unbundling plan also proposes to facilitate the clear
functional separation of the Company's ongoing regulated transmission and
distribution operations and functions from all of its unregulated operations and
activities by undergoing a corporate restructuring into a holding company
structure. In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company will be converted into a share of common stock of the holding
company. In connection with the formation of the holding company structure, all
of the Company's interests in all of its operating unregulated subsidiaries will
be transferred to the holding company and, to the extent new unregulated
businesses are subsequently acquired or commenced, they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power adjustment clause be added to its regulated rates, effective
July 1, 2000. This clause, similar to and based on the purchased gas adjustment
clauses used by Connecticut's natural gas local distribution companies, would
work in tandem with the Company's procurement of power supplies to assure that
standard offer customers pay competitive market rates for generation services
even though they do not choose an alternate electricity supplier. The
Distribution Company is also required under the Restructuring Act to provide
back-up service to customers whose electric supplier fails to provide electric
generation services for reasons other than the customers' failure to pay for
such services. The Restructuring Act provides for the Distribution Company to
recover its reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The DPUC's 1996 order anticipated sufficient income in 2000 to accelerate
amortization of regulatory assets of about $50 million, equivalent to about 8%
of retail revenues. Substantially all of this accelerated amortization may have
to be eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income statement impact of certain costs that are expected to be
recovered in future regulated service rates and to establish regulatory assets
on its balance sheet for such costs. The effects of competition or a change in
the cost-based regulatory structure could cause the operations of the Company,
or a portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. While the Company expects to continue to
meet these criteria in the foreseeable future, if the Company, or a portion of
its assets or operations, were to cease meeting these criteria, accounting
standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs,
would be required in the year in which the criteria are no longer met, if such
deferred costs are not recoverable in that portion of the business that
continues to meet the criteria for the application of SFAS No. 71. If this
change in accounting were to occur, it would have a
- 20 -
<PAGE>
material adverse effect on the Company's earnings and retained earnings in that
year and could have a material adverse effect on the Company's ongoing financial
condition as well.
- 21 -
<PAGE>
CAPITAL EXPENDITURE PROGRAM
The Company's 1998-2002 capital expenditure program, excluding allowance
for funds used during construction (AFUDC) and its effect on certain
capital-related items, is presently budgeted as follows:
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002 TOTAL
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Generation (1) $7,169 $5,553 $4,675 $1,752 $2,771 $21,920
Distribution and Transmission 13,184 16,434 18,557 14,441 14,371 76,987
Other 9,640 8,036 2,410 2,009 2,655 24,750
------ ------ ------ ------ ------ -------
Subtotal 29,993 30,023 25,642 18,202 19,797 123,657
Nuclear Fuel 5,947 2,397 8,569 6,160 2,892 25,965
------ ------ ------ ------ ------ -------
Total Expenditures $35,940 $32,420 $34,211 $24,362 $22,689 $149,622
======= ======= ======= ======= ======= ========
Rate Base and Other Selected Data:
- ---------------------------------
Depreciation
Book Plant (1) 57,442 48,803 46,815 47,403 47,797
Conservation Assets 10,309 5,390 0 0 0
Decommissioning 2,778 2,781 2,892 3,007 3,128
Additional Required
Amortization (pre-tax)(2)
Conservation Assets 13,000 0 0 0 0
Other Regulatory Assets 0 20,300 0 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 12,586 0 0 0
Estimated Rate Base
(end of period) 1,102,455
</TABLE>
(1) Recently enacted legislation to restructure Connecticut's electric utility
industry requires the Company to divest itself of its fossil-fueled
generating plants prior to January 1, 2000 and to attempt to divest itself
of its ownership interests in nuclear-fueled generating units prior to
January 1, 2004. This forecast reflects a proposed divestiture of
fossil-fueled generation plants on April 1, 1999. Remaining Generation is
projected capital expenditures for nuclear generation, excluding nuclear
fuel.
(2) Additional amortization of pre-1997 conservation costs and other
unspecified regulatory assets, as ordered by the DPUC in its December 31,
1996 Order, provided that, as expected, common equity return on utility
investment exceeds 10.5% after recording the additional amortization.
- 22 -
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 1998, the Company had $13.3 million of cash and temporary
cash investments, a decrease of $18.7 million from the balance at December 31,
1997. The components of this decrease, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
--------
Balance, December 31, 1997 $ 32.0
-----
Net cash provided by operating activities 57.9
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (35.2)
- Dividend payments (30.3)
Net cash provided by investing activities, excludin
investment in plant 8.5
Cash invested in plant, including nuclear fuel (19.6)
-----
Net Change in Cash (18.7)
-----
Balance, September 30, 1998 $13.3
=====
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year $ 32.0 $ - $ - $ - $ -
Internally Generated Funds less Dividends 112.0 144.0 67.0 67.0 69.0
Net Proceeds from Sale of Fossil Generation Plant - 160.0 - - -
----- ----- ---- ---- -----
Subtotal 144.0 304.0 67.0 67.0 69.0
Less:
Capital Expenditures 35.9 32.4 34.2 24.4 22.7
----- ----- ---- ---- -----
Cash Available to pay Debt Maturities and Redemptions 108.1 271.6 32.8 42.6 46.3
Less:
Maturities and Mandatory Redemptions 104.2 69.6 0.4 0.3 100.3
Optional Redemptions 113.8 145.0 50.0 - -
----- ----- ---- ---- -----
External Financing Requirements (Surplus) $109.9 $(57.0) $17.6 $(42.3) $54.0
===== ===== ==== ===== ====
</TABLE>
Note:Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections, including the implementation of the legislative
mandate to achieve a 10% price reduction from 1996 average price levels by
the year 2000. Recently enacted legislation to restructure Connecticut's
electric utility industry will require the Company to divest itself of its
fossil-fueled generating plants prior to January 1, 2000 and to attempt to
divest itself of its ownership interests in nuclear-fueled generating units
prior to January 1, 2004. This forecast reflects the estimated net
after-tax proceeds (approximately $160 million) from a proposed divestiture
of fossil-fueled generation plants on April 1, 1999. 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.
- 23 -
<PAGE>
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement and an $80 million revolving credit
agreement, described below, the Company expects to be able to satisfy its
external financing needs by issuing additional short-term and long-term debt,
and by issuing preferred stock or common stock, if necessary. The continued
availability of these methods of financing will be dependent on many factors,
including conditions in the securities markets, economic conditions, and the
level of the Company's income and cash flow. On October 19, 1998, the Company
filed with the Connecticut Department of Public Utility Control an application
for approval of the issuance and sale of a maximum of $100 million of
medium-term Notes. The Company proposes to use the net proceeds of this proposed
financing to repay Notes in the principal amount of $66.2 million that will
mature in January of 1999, to repay short-term bank borrowings, and for general
corporate purposes.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The Company expects that this agreement
will be extended to December 1999. The borrowing limit of this facility is $75
million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
September 30, 1998, the Company had $29.3 million of short-term borrowings
outstanding under this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of September 30, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
SUBSIDIARY OPERATIONS
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional buildings, and is participating
in the development of district heating and cooling facilities in the downtown
New Haven area, including the energy center for an office tower and
participation as a 52% partner in the energy center for a city hall and office
tower complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial buildings,
government buildings and industrial facilities. URI's fourth subsidiary, United
Bridgeport Energy, Inc., is participating in a merchant wholesale electric
generating facility being constructed on land leased from UI at its Bridgeport
Harbor Station generating plant.
- 24 -
<PAGE>
RESULTS OF OPERATIONS
THIRD QUARTER OF 1998 VS. THIRD QUARTER OF 1997
- -----------------------------------------------
Earnings for the third quarter of 1998 were $26.2 million, or $1.87 per
share (on both a basic and diluted basis), up $2.8 million, or $.19 per share,
from the third quarter of 1997. Excluding one-time items, earnings from
operations were $24.9 million, or $1.78 per share, up $.15 per share from the
third quarter of 1997. The one-time items were:
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Quarter 3 Gain from subleasing office space $ .05
- --------------------------------------------------------------------------------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .09
- --------------------------------------------------------------------------------
Retail operating revenues increased by about $8.7 million in the third
quarter of 1998 compared to the third quarter of 1997, offset by a $4.8 million
increase in cost of production (retail fuel and energy expense) and a small
increase in revenue-based taxes, for a retail sales margin increase of $3.5
million. The principal components of the retail sales margin change include:
$ millions
- --------------------------------------------------------------------------------
Revenues from:
- --------------------------------------------------------------------------------
Sharing: year-to-date estimate for 1998 (see Note A) (3.0)
- --------------------------------------------------------------------------------
Other price changes 1.6
- --------------------------------------------------------------------------------
Estimate of "real" retail sales growth, up 4.0% 6.0
- --------------------------------------------------------------------------------
Estimate of weather effect on retail sales, up 2.8% 4.9
- --------------------------------------------------------------------------------
Sales decrease from Yale University cogeneration, (1.1)% (0.9)
- --------------------------------------------------------------------------------
Fuel expense from:
- --------------------------------------------------------------------------------
Sales increase (2.1)
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 (see Note B) (2.5)
- --------------------------------------------------------------------------------
Fossil fuel price and other (0.1)
- --------------------------------------------------------------------------------
Revenue-based taxes (0.4)
- --------------------------------------------------------------------------------
Note A: On December 31, 1996, the Connecticut Department of Public
Utility Control (DPUC) issued an order (the Order) that implemented a
five-year regulatory framework that would reduce the Company's retail
prices and accelerate the recovery of certain "regulatory assets,"
beginning with deferred conservation costs. The Company is operating
under the terms of this order in 1998. The Order requires a "sharing"
of income if regulated return on equity exceeds 11.5 percent. (See the
discussion on the "Five-year rate plan" in the Looking Forward section
for information regarding the sharing mechanism.) The Company's latest
estimate for 1998 results indicates that it will be likely that some
sharing will be required in 1998, and the Company accrued a revenue
reduction of $3.0 million ($1.7 million after-tax) in the third quarter
of 1998.
Note B: Saltwater contamination caused a shutdown of the Bridgeport
Harbor Unit 3 generating unit on May 22, 1998. The unit returned to
full service on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale expense) changed
only slightly in the third quarter of 1998 compared to the third quarter of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $2.2 million.
Operating expenses for operations, maintenance and purchased capacity
charges increased by $0.1 million in the third quarter of 1998 compared to the
third quarter of 1997. The principal components of these expense changes
include:
- 25 -
<PAGE>
$ millions
-------------------------------------------------------------------------------
Capacity:
- --------------------------------------------------------------------------------
Connecticut Yankee Unit, cogeneration and other purchases 0.8
- --------------------------------------------------------------------------------
Other O&M:
- --------------------------------------------------------------------------------
Seabrook Unit (1.0)
- --------------------------------------------------------------------------------
Millstone Unit 3 (1.6)
- --------------------------------------------------------------------------------
Fossil generation unit overhauls and outage costs 2.7
- --------------------------------------------------------------------------------
Pension investment performance and changes to actuarial
assumptions and methodologies (1.2)
- --------------------------------------------------------------------------------
Personnel reductions (1.5)
- --------------------------------------------------------------------------------
Environmental remediation costs 2.9
- --------------------------------------------------------------------------------
Other (1.0)
- --------------------------------------------------------------------------------
Depreciation expense increased slightly in the third quarter of 1998
compared to the third quarter of 1997.
The Company expects that all of the required accelerated amortization for
1998 will be recorded against earnings from operations and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings from utility operations. Therefore, $3.3 million of accelerated
amortization, reflecting one quarter of the 1998 accelerated amortization
requirement of the five-year rate plan implemented in 1997, was recorded in the
third quarter of 1998. In addition, as part of the sharing mechanism, the
Company accrued an additional amortization of $2.6 million ($1.7 million
after-tax) in the third quarter of 1998. The sharing amounts, both revenue and
amortization, that were recorded in the third quarter, represent roughly three
quarters of the current sharing estimate for the year 1998. The final sharing
amount for the year will be subject to change, upward or downward, in the fourth
quarter based on final actual results for the year.
Other net income increased slightly in the third quarter of 1998 compared
to the third quarter of 1997.
Interest charges continued on their downward trend, decreasing by $3.4
million in the third quarter of 1998 compared to the third quarter of 1997, as a
result of the Company's refinancing program and strong cash flow.
NINE MONTHS OF 1998 VS. NINE MONTHS OF 1997
- -------------------------------------------
Earnings for the first nine months of 1998 were $40.6 million, or $2.90 per
share ($2.89 per share on a diluted basis...the difference being about $.003 per
share), up $1.0 million, or $.08 per share, from the first nine months of 1997.
Excluding one-time items and accelerated amortization due to one-time items,
earnings from operations were $42.1 million, or $3.02 per share, up $.44 per
share from the first nine months of 1997. The one-time items were:
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Quarter 2 Cumulative deferred tax benefits associated with future
Decommissioning of fossil fuel generating plants $.48
- --------------------------------------------------------------------------------
1997 Quarter 2 Accelerated amortization associated with one-time item $(.29)
- --------------------------------------------------------------------------------
1997 Quarter 3 Gain from subleasing office space $ .05
- --------------------------------------------------------------------------------
1998 Quarter 2 Subsidiary reserve for agent collection shortfalls
and other potentially uncollectible receivables $(.21)
- --------------------------------------------------------------------------------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .09
- --------------------------------------------------------------------------------
Retail operating revenues increased by about $7.9 million in the first nine
months of 1998 compared to the first nine months of 1997, offset by an $8.0
million increase in cost of production (retail fuel and energy expense) and a
small increase in revenue-based taxes, for a retail sales margin decrease of
$0.4 million. The principal components of the retail sales margin change
include:
- 26 -
<PAGE>
$ millions
- --------------------------------------------------------------------------------
Revenues from:
- --------------------------------------------------------------------------------
DPUC rate order, excluding sharing (2.7)
- --------------------------------------------------------------------------------
Sharing: year-to-date estimate for 1998 (see Note A) (3.0)
- --------------------------------------------------------------------------------
Other price changes (1.3)
- --------------------------------------------------------------------------------
Estimate of "real" retail sales growth, up 3.1% 14.8
- --------------------------------------------------------------------------------
Estimate of weather effect on retail sales, up 0.5 % 2.9
- --------------------------------------------------------------------------------
Sales decrease from Yale University cogeneration, (0.6) % (2.8)
- --------------------------------------------------------------------------------
Fuel expense from:
- --------------------------------------------------------------------------------
Sales increase (3.3)
- --------------------------------------------------------------------------------
Reduced nuclear unit availability (1.1)
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 (see Note B) (3.7)
- --------------------------------------------------------------------------------
Fossil fuel price and other 0.1
- --------------------------------------------------------------------------------
Revenue-based taxes (0.3)
- --------------------------------------------------------------------------------
Note A: On December 31, 1996, the Connecticut Department of Public
Utility Control (DPUC) issued an order (the Order) that implemented a
five-year regulatory framework that would reduce the Company's retail
prices and accelerate the recovery of certain "regulatory assets,"
beginning with deferred conservation costs. The Company is operating
under the terms of this order in 1998. The Order requires a "sharing"
of income if regulated return on equity exceeds 11.5 percent. (See the
discussion on the "Five-year rate plan" in the Looking Forward section
for information regarding the sharing mechanism.) The Company's latest
estimate for 1998 results indicates that it will be likely that some
sharing will be required in 1998, and the Company accrued a revenue
reduction of $3.0 million ($1.7 million after-tax) in the third quarter
of 1998.
Note B: Saltwater contamination caused a shutdown of the Bridgeport
Harbor Unit 3 generating unit on May 22, 1998. The unit returned to
full service on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale expense) increased
slightly in the first nine months of 1998 compared to the first nine months of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $3.9 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $10.3 million in the first nine months of 1998 compared to
the first nine months of 1997. The principal components of these expense changes
include:
$ millions
- --------------------------------------------------------------------------------
Capacity:
- --------------------------------------------------------------------------------
Connecticut Yankee Unit, preparing for decommissioning (3.4)
- --------------------------------------------------------------------------------
Cogeneration and other purchases (2.5)
- --------------------------------------------------------------------------------
Other O&M:
- --------------------------------------------------------------------------------
Seabrook Unit (5.0)
- --------------------------------------------------------------------------------
Millstone Unit 3 (2.3)
- --------------------------------------------------------------------------------
Fossil generation unit overhauls and outage costs 9.0
- --------------------------------------------------------------------------------
Pension investment performance and changes to actuarial
assumptions and methodologies (4.1)
- --------------------------------------------------------------------------------
Personnel reductions (4.5)
- --------------------------------------------------------------------------------
Other 2.5
- --------------------------------------------------------------------------------
Depreciation expense increased by $0.7 million in the first nine months of
1998 compared to the first nine months of 1997.
- 27 -
<PAGE>
All of the accelerated amortization in 1997 was recorded in the second
quarter of that year as a result of a one-time gain recorded in that quarter.
The Company expects that all of the required accelerated amortization for 1998
will be recorded against earnings from operations and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings from utility operations. Therefore, $9.8 million of accelerated
amortization, reflecting three quarters of the 1998 accelerated amortization
requirements of the five-year rate plan implemented in 1997, was recorded in the
first nine months of 1998. In addition, as part of the sharing mechanism, the
Company accrued an additional amortization of $2.6 million ($1.7 million
after-tax) in the third quarter of 1998. The sharing amounts, both revenue and
amortization, that were recorded in the third quarter represent roughly three
quarters of the current sharing estimate for the year 1998. The final sharing
amount for the year will be subject to change, upward or downward, in the fourth
quarter based on final actual results for the year.
Other net income decreased by about $0.5 million in the first nine months
of 1998 compared to the first nine months of 1997. The Company's largest
unregulated subsidiary, American Payment Systems (APS), earned about $0.5
million (after-tax) in the first nine months of 1998, before one-time charges,
compared to a loss of $0.2 million (after-tax) in the first nine months of 1997.
This was more than offset by the absence of other non-utility income accruals
made in 1997, and a reduction in interest income.
Interest charges continued on their downward trend, decreasing by $8.9
million in the first nine months of 1998 compared to the first nine months of
1997, as a result of the Company's refinancing program and strong cash flow.
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 and restructuring legislation
- -------------------------------------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework that would reduce the Company's retail prices and accelerate the
recovery of certain "regulatory assets," beginning with deferred conservation
costs. The Company is operating under the terms of this order in 1998. 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 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 any income that would produce a return above
the 11.5% level: one-third would be applied to customer bill reductions,
one-third would be applied to additional amortization of regulatory assets, and
one-third would be retained by shareowners. The Order includes a provision that
it may be reopened and modified upon the enactment of electric utility
restructuring legislation in Connecticut and, as a consequence of the 1998
restructuring legislation described below, the Order may be reopened and
modified. However, the Company is unable to predict, at this time, whether or
when or in what respects the Order will be modified on account of this
legislation.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's electric
utility industry. The business of generating and supplying electricity to
consumers will be opened to competition and will be separated from the business
of delivering electricity to consumers, beginning in the year 2000. The business
of delivering electricity will remain with the incumbent franchised utility
companies (including the Company). Beginning in 2000, each retail consumer of
electricity in Connecticut (excluding consumers served by municipal electric
systems) will be able to choose his, her or its supplier of electricity from
among competing licensed suppliers, for delivery over the wires system of the
franchised electric utility (Distribution Company). Commencing no later than
mid-1999, Distribution Companies will be required to separate on consumers'
bills the charge for electricity generation services from the charge for
delivering the electricity and all other charges. On July 29, 1998, the DPUC
issued the first of what are expected to be several orders relative to this
"unbundling" requirement.
- 28 -
<PAGE>
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 and the systems benefits charge represent costs that either have been
or will be reasonably incurred by Distribution Companies to meet their public
service obligations as 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 costs of conservation programs and renewable energy investments are
new charges established in the Restructuring Act. Beginning in 2000, the
Distribution Company must collect the competitive transition assessment, systems
benefits charge, and conservation and load management and renewable investment
charges from all Distribution Company customers. The Distribution Company will
also be required to offer a "standard offer" rate that is, subject to certain
adjustments, at least 10% below its fully bundled price for electricity at
December 31, 1996, as discussed below. The standard offer is required, subject
to certain adjustments, to be the total rate charged under the standard offer,
including transmission and distribution services, the competitive transition
assessment, the systems benefits charge, the conservation and load management
program charge and the renewable energy charge. The Restructuring Act requires
that, in order for a Distribution Company to recover any stranded costs
associated with its power plants, its fossil-fueled plants must be sold prior to
2000 with any net excess proceeds used to mitigate its recoverable stranded
costs, and the Company must attempt to divest its ownership interest in its
nuclear-fueled power plants prior to 2004. By October 1, 1998, each Distribution
Company was required to file, for the DPUC's approval, an "unbundling plan" to
separate, on or before October 1, 1999, all of its power plants that will not
have been sold prior to the DPUC's approval of the unbundling plan or will not
be sold prior to 2000.
In May of 1998 the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission, and other federal and state agencies. A petition seeking
the DPUC's approval was filed on October 30, 1998.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of
regulated plant costs, including tax-related regulatory assets, displaced worker
relocation costs and other costs, such that there will be no net income effect
of the sale. Net cash proceeds from the sale are expected to be in the range of
$160-$165 million. The Company anticipates using these proceeds to reduce debt,
possibly to reduce equity through a special dividend or stock buyback, and for
growth opportunities.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that its unbundling plan for the
Company's nuclear generation ownership interests, 17.5% of Seabrook Station, in
New Hampshire, and 3.685% of Millstone Station Unit No. 3, in Connecticut, is
divestiture by the end of 2003 in accordance with the Restructuring Act. The
divestiture method has not yet been determined. In anticipation of ultimate
divestiture, the Company proposed to satisfy, on a functional basis, the
Restructuring Act's requirement that nuclear generating assets be separated from
its transmission and distribution assets. This would be
- 29 -
<PAGE>
accomplished by transferring the nuclear generating assets into separate new
divisions of the Company, using divisional financial statements and accounting
to segregate all revenues, expenses, assets and liabilities associated with each
nuclear ownership interest.
The Company's unbundling plan also proposes to facilitate the clear
functional separation of the Company's ongoing regulated transmission and
distribution operations and functions from all of its unregulated operations and
activities by undergoing a corporate restructuring into a holding company
structure. In the holding company structure proposed, the Company will become a
wholly-owned subsidiary of a holding company, and each share of the common stock
of the Company will be converted into a share of common stock of the holding
company. In connection with the formation of the holding company structure, all
of the Company's interests in all of its operating unregulated subsidiaries will
be transferred to the holding company and, to the extent new unregulated
businesses are subsequently acquired or commenced, they will also be financed
and owned by the holding company. An application for the DPUC's approval of this
corporate restructuring was filed on November 13, 1998.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the service provider to each customer
who does not choose an alternate power supply provider. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power adjustment clause be added to its regulated rates, effective
July 1, 2000. This clause, similar to and based on the purchased gas adjustment
clauses used by Connecticut's natural gas local distribution companies, would
work in tandem with the Company's procurement of power supplies to assure that
standard offer customers pay competitive market rates for generation services
even though they do not choose an alternate electricity supplier. The
Distribution Company is also required under the Restructuring Act to provide
back-up service to customers whose electric supplier fails to provide electric
generation services for reasons other than the customers' failure to pay for
such services. The Restructuring Act provides for the Distribution Company to
recover its reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
state and federal environmental and antitrust agencies, and the Company's common
stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The 1997 through 2001 rate plan agreed to between the DPUC and the Company in
1996 anticipated sufficient income in 2000 to accelerate amortization of
regulatory assets of about $50 million, equivalent to about 8% of retail
revenues. Substantially all of this accelerated amortization may have to be
eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
1998 Earnings
- -------------
The Company's earnings from its utility business are greatly affected by:
retail sales that fluctuate with weather conditions and economic activity,
fossil fuel prices, nuclear generating unit availability and operating costs,
and interest rates. These are all items over which the Company has little
control, although the Company engages in economic development activities to
increase sales, and hedges its exposure to volatility in fuel costs and interest
rates.
The Company's revenues are principally dependent on the level of retail
sales. The two primary factors that affect retail sales volume are economic
conditions and weather. The Company estimates that mild 1997 weather
- 30 -
<PAGE>
reduced retail kilowatt-hour sales by about 0.5 percent for the year. Because
much of the mild 1997 weather occurred in the summer months when prices are
higher than average, the revenue impact was exacerbated. It is estimated that
mild weather may have reduced revenues by as much as $5.2 million for the year,
and sales margin (revenue less fuel expense and revenue-based taxes) by as much
as $4.2 million. Weather corrected retail sales for 1997 were probably in the
5,375-5,425 gigawatthour range. On this basis, the Company experienced about
1.0-1.5 percent of "real" sales growth in 1997 (i.e. exclusive of weather and
leap year factors) over "normal" 1996 sales, with almost all of the growth
occurring in the last half of the year. Growth in "real" sales in the first nine
months of 1998 compared to the first nine months of 1997 was probably in the
2.0-2.5 percent range, which increased revenues by $10-$12 million and sales
margin by $8-$10 million. This indicates the potential for further real growth
in the fourth quarter, although perhaps at a lower rate reflecting the high
growth in the fourth quarter of 1997. Such 1998 growth may be tempered by other
factors, however, some of which are noted below.
Reductions in revenues could occur for several other reasons. A contract
has been signed with Yale University, the Company's largest customer, which has
constructed a cogeneration unit that will produce approximately one half of its
annual electricity requirements (about 1.5 percent of the Company's total 1997
retail sales). This unit commenced operations in mid-1998, and it has reduced
the Company's retail kilowatthour sales by about 0.6 percent in the first nine
months of 1998 compared to the first nine months of 1997. Real retail sales
growth more than offset this reduction. Other potential causes of revenue
reductions, e.g. special contracts, customer rate migration, and termination of
the fossil fuel adjustment clause, all appear to be having minor effects on
revenue.
Under the current DPUC Order, retail revenues will be reduced, from what
they would otherwise be, if the Company is in the "sharing" range above an 11.5%
return on common stock equity. Currently, the Company anticipates a revenue
reduction of about $3.7 million in 1998 under the sharing mechanism, $3.0
million of which was accrued in the third quarter. The overall average retail
price anticipated for 1998 is about 11.5 cents per kilowatt-hour, slightly below
the average 1997 price but almost 5 percent below the average 1996 price.
Improvements in wholesale sales margin (wholesale revenue less wholesale
fuel and energy expense) will be dependent on the capacity and energy needs of
the region, on the availability of generating units, on the addition of new
generation sources, and on how the capacity and energy markets perform under the
new New England Power Pool (NEPOOL) open competition system, designed to meet
Federal Energy Regulatory Commission (FERC) open access orders, when it is
implemented. Implementation of this system is currently expected on or about
December 1, 1998, but this date is subject to NEPOOL information system
development and testing and further orders from the FERC. No significant
wholesale sales margin improvement is expected by the Company from wholesale
capacity, transmission and energy sales during 1998.
Another major factor affecting the Company's 1998 earnings will be the
Company's ability to control operating expenses. The Company offered voluntary
early retirement programs and a voluntary severance program to union, nonunion
and management employees in 1996. A portion of the resulting personnel cost
savings occurred in 1996 and 1997, but the largest increment in annual savings
will be realized in 1998. Annual savings of about $6 million from personnel
reductions are estimated, and this amount was validated by results of the first
nine months.
The Company is expecting other significant expense declines in 1998
compared to 1997 from a number of sources. From the nuclear generating units, it
is expected that operation and maintenance expenses associated with the Seabrook
and Connecticut Yankee units should decline by a total of about $9 million. They
have decreased by $8 million in the first nine months of 1998 compared to the
first nine months of 1997.
Millstone Unit 3 was taken out of service on March 30, 1996. A
comprehensive Nuclear Regulatory Commission (NRC) inquiry into the conformity of
the unit and its operations with all applicable NRC regulations and standards
was completed and the unit was allowed to resume operation beginning on July 4,
1998. It achieved full power production on July 15, 1998. The Company
anticipates that operating costs should ramp down to more normal levels for an
efficient and safe nuclear unit of this class, and expects a reduction of about
$3 million in these costs in 1998 compared to 1997. Also, net fuel expense
should decline by $350,000 per month for every month of operation, net of the
replacement fuel provision of about $130,000 per month...for a total reduction
of about $1.7
- 31 -
<PAGE>
million for 1998 compared to 1997. Operation and maintenance expense decreased
by $2.3 million in the first nine months of 1998 compared to the first nine
months of 1997, and fuel expense decreased by $0.7 million.
Pension and health benefit expenses, excluding one-time items, are expected
to decrease by about $2.5 million in 1998 compared to 1997. NEPOOL expenses are
expected to increase by about $1.0 million, and expenses associated with the
"Year 2000 Issue" could reach as much as $5.0-$6.0 million in the 1998-99 period
(see "Year 2000 Issue"). The latter is the result of receiving more current and
detailed information from embedded technology vendors. Other operation and
maintenance expenses may increase or decrease by amounts that cannot be
predicted at this time.
Interest costs are expected to decline by about $10 million in 1998
compared to 1997 to about $52 million, a level that was last experienced in
1984. This interest cost reduction is largely a result of debt refinancings and
debt paydown. Interest charges for the first nine months of 1998 compared to the
first nine months of 1997 decreased by $8.9 million.
Other factors should increase costs. Other operation and maintenance
expense should increase by about $9 million in 1998 compared to 1997 reflecting
increased fossil-fueled generating unit scheduled maintenance. Environmental
remediation added $2.9 million of other operation and maintenance costs, as
recorded in the third quarter of 1998. Such costs cannot be anticipated. Base
depreciation, excluding accelerated amortization, should increase about $2.0
million in 1998. Accelerated amortization, per the Order, but excluding any
sharing amortization, will increase by about $7 million (reflecting a $3.3
million per quarter increase, except for a $3.1 million decrease in the second
quarter compared to 1997, as all of the $6.4 million amortization for 1997 was
recorded as an offset to a one-time gain in the second quarter.) Other operating
expenses will have some increases and some decreases that should more or less
offset one another.
In summary, the Company expects substantial net expense reductions that
should more than compensate for the loss of one-time items realized in 1997 (all
of them utility related), cover the increase in accelerated conservation and
load management amortization, and allow utility earnings to increase above an
11.5% return on common stock equity into the "sharing" range of the Order. The
11.5% return level would produce utility earnings of about $3.40-$3.45 per
share, while "shared" earnings could add an additional $.05-$.10 per share.
Non-utility earnings, before one-time items, should increase approximately $.05
per share in 1998 compared to 1997, due principally to the anticipated breakeven
operation of the non-regulated subsidiaries. The Company expects that 1998
quarterly earnings from operations will follow a pattern similar to that of 1997
on a weather-normalized basis.
Other
- -----
The City of New Haven (the City) and the Company are involved in a dispute
over the amount of personal property taxes owed to the City for tax years
beginning with 1991-1992. On May 8, 1998, the City and the Company reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992 through 1997-1998 and the
Company's personal property tax assessments for the tax year 1998-1999 and
subsequent years. Under the terms of this settlement, the Company will pay the
City $14.025 million, subject to Superior Court approval of the settlement and
conditioned on the Company receiving authorization from the DPUC to recover the
settlement amount from its retail customers. The DPUC denied the Company's
initial application for such authorization and the City has agreed to extend to
November 30, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million, which has been
recognized as a prepayment of property taxes. The Company filed a second
application with the DPUC on July 9, 1998. If the DPUC authorization is not
forthcoming, the $6 million payment will be applied to future tax bills.
1999 and on
- -----------
Looking forward to 1999, the Company expects to maintain earnings from
utility operations in the "sharing range" of the Order, just as it expects for
1998. The sharing mechanism is in effect if utility earnings exceed 11.5 percent
on common stock equity invested in utility assets, equivalent to an earnings
level of about $3.45 per share in
- 32 -
<PAGE>
1999. Earnings levels in 1999 may also be affected by how the Company decides to
deploy the net cash proceeds of approximately $160 million from its recently
proposed fossil plant sale.
The Company's sales margin should continue to improve from modest sales
growth, offset by the full effect of the Yale University cogeneration unit for
the entire year of 1999. The Company does not forecast significant sales growth
for 1999. Although sales growth has been exceptional in 1998 compared to 1997,
there is no basis for believing that such growth will continue into next year.
Utility related operating expenses are expected to decrease slightly, offset by
the additional $7 million of accelerated amortization expense required for 1999
under the Order. The Company does not expect any significant operating cost
reductions in 1999 from the proposed sale of its fossil plants.
In summary, the Company expects modest improvements in pre-tax income in
1999 from utility operations, which, under the sharing arrangement, only affects
net income by one-third of the total improvement. The subsidiary, American
Payment Systems (APS), should continue to show improvement over 1998
performance. APS should earn between $.08-$.12 per share from operations
compared to $.05 per share expected in 1998. Precision Power, Inc. is expected
to continue losses equivalent to $.05-$.15 per share, depending on its level of
business expansion and pursuit of new ventures; comparable to an expected loss
of $.05 per share in 1998.
Year 2000 Issue
- ---------------
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct
deficiencies in its computer systems. Critical systems have been defined as
those business processes, including embedded technology, which if not remediated
may have a significant impact on safety, customers, revenue or regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged and is asking for assurance of their Year 2000
compliance.
An inventory and assessment of the Company's computer system applications,
hardware, software and embedded technologies has been completed, and recommended
solutions to all identified risks and exposures have been generated. A testing,
remediation, renovation, replacement and retirement program has been in progress
since early 1998. A total of 362 business processes have been identified and 174
of them have been verified as Year 2000 compliant through testing, remediation,
replacement or retirement. The remediation methodology utilized has been Fixed
Windowing and totally independent platforms have been installed for testing all
of the applications. Necessary upgrades to mainframe hardware and software are
expected to be completed and tested by the end of 1998. A parallel program for
desktop hardware and application software on all platforms is currently
projected to be completed and tested, for all critical systems, by March 31,
1999. Requests for documented compliance information have been sent to all
critical suppliers, data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed.
The Company believes that the successful implementation of this program
should ultimately cost no more than $6 million for existing information systems
and embedded technology. Approximately $2.2 million will be spent by the end of
1998. As systems testing progresses and more embedded technology vendor product
information is forthcoming, business decisions made and testing results
verified, the need for increased expenditures, if necessary, will be determined.
The Company believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.
While failure to achieve Year 2000 compliance by any one of a number of
critical suppliers and data sharers could have some adverse effect on the
success of the Company's implementation program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications providers, the other participants in NEPOOL, and the
Independent System Operator (ISO) that operates the NEPOOL bulk power supply
system. Year 2000 compliance failures by any of these entities could have a
material
- 33 -
<PAGE>
effect on electricity delivery and telemetering. UI has communicated its
concerns to its principal telecommunications provider, in an effort to design
and plan appropriate testing to insure that all critical telecommunications
functions will be operational. This issue is also being addressed at the
regional level by NEPOOL and the ISO. The Company is also actively involved with
NEPOOL/ISO in the planning effort for integrated contingency planning, as
directed by the North American Electric Reliability Council.
Aside from telecommunications and NEPOOL/ISO concerns, vendor patches
releases and/or replacement equipment or software availability pose the most
significant risks to the success of the Company's Year 2000 compliance
implementation program. In order to minimize these risks, the Company will be
actively involved in contingency planning. While the Company's knowledge and
experience in electric system recovery planning and execution has been
demonstrated in the past, the Company recognizes the need for, and importance
of, Year 2000-specific contingency planning, because the complex interaction of
today's computing and communications systems precludes certainty that all
critical system remediation will be successful. At this time, contingency
planning for essential business functions is under investigation in most areas,
but specific needs have not been fully identified. These plans will be developed
in the first quarter of 1999, after the majority of business processes are
scheduled to be tested and within the timeframe when the ISO/NEPOOL process is
due to develop region-wide contingency plans for operations. As a part of the
contingency planning process, consideration will be given to potential frequency
and duration of interruptions in the generating, financial and communications
infrastructures. Since contingency planning is, by nature, a speculative
process, there can be no assurance that this planning will completely eliminate
the risk of material impacts to the Company's business due to Year 2000
problems. However, the Company recognizes the importance to its customers of a
reliable supply of electricity, and it intends to devote whatever resources are
necessary to assure that both the program and its implementation are successful.
- 34 -
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. On March 7, 1997, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1997-1998, which notices purport to increase said
assessed value by approximately 54% over the valuations declared by the Company
and are expected to generate tax claims of approximately $3.7 million. The
Company has vigorously contested each of these actions by the City's tax
assessor. In January 1996, the Connecticut Superior Court granted the Company's
motion for summary judgment against the City relative to the earliest tax year
at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had
no statutory authority to revalue personal property listed and valued on the
Company's tax list for the tax year 1991-1992. This Superior Court decision,
which would also have been applicable to and defeated the assessor's valuation
increases for the two subsequent tax years, 1992-1993 and 1993-1994, was
appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed
the Superior Court's decisions in this and two other companion cases involving
other taxpayers, ruling that the tax assessor had a three-year period in which
to audit and revalue personal property listed and valued on the Company's tax
list for the tax year 1991-1992. On May 8, 1998, the City and the Company
reached a comprehensive settlement of all of the Company's contested personal
property tax assessments and tax bills for the tax years 1991-1992 through
1997-1998 and the Company's personal property tax assessments for the tax year
1998-1999 and subsequent years. Under the terms of this settlement, the Company
will pay the City $14.025 million, subject to Superior Court approval of the
settlement and conditioned on the Company receiving authorization from the DPUC
to recover the settlement amount from its retail customers. The DPUC denied the
Company's initial application for such authorization and the City has agreed to
extend to November 30, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million, which has been
recognized as a prepayment of property taxes. The Company filed a second
application with the DPUC on July 9, 1998. If the DPUC authorization is not
forthcoming, the $6 million payment will be applied to future tax bills.
- 35 -
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(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
September 30, 1998 and Twelve Months Ended December 31, 1997,
1996, 1995, 1994 and 1993).
(27) 27 Financial Data Schedule
</TABLE>
(b) Reports on Form 8-K.
None
- 36 -
<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 11/13/98 Signature /s/ Robert L. Fiscus
----------------- ---------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
- 37 -
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(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
September 30, 1998 and Twelve Months Ended December 31, 1997,
1996, 1995, 1994 and 1993).
(27) 27 Financial Data Schedule
</TABLE>
<TABLE>
EXHIBIT 12
PAGE 1 OF 2
THE UNITED ILLUMINATING COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS)
<CAPTION>
TWELVE
MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPT. 30,
-----------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $40,481 $46,795 $50,393 $39,096 $45,791 $46,832
Federal income taxes 22,342 34,551 41,951 35,252 30,186 40,684
State income taxes 4,645 6,216 12,976 8,506 8,651 11,366
Fixed charges 97,928 88,093 83,994 80,097 78,016 69,424
----------- ----------- ----------- ----------- ----------- ------------
Earnings available for fixed charges $165,396 $175,655 $189,314 $162,951 $162,644 $168,306
=========== =========== =========== =========== =========== ============
FIXED CHARGES
Interest on long-term debt $80,030 $73,772 $63,431 $66,305 $63,063 $52,743
Other interest 12,260 10,301 16,723 9,534 10,881 12,723
Interest on nuclear fuel burned 928 - - - - -
One third of rental charges 4,710 4,020 3,840 4,258 4,072 3,959
----------- ----------- ----------- ----------- ----------- ------------
$97,928 $88,093 $83,994 $80,097 $78,016 $69,425
=========== =========== =========== =========== =========== ============
RATIO OF EARNINGS TO FIXED
CHARGES 1.69 1.99 2.25 2.03 2.08 2.42
=========== =========== =========== =========== =========== ============
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12
PAGE 2 OF 2
THE UNITED ILLUMINATING COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS
(IN THOUSANDS)
<CAPTION>
TWELVE
MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPT. 30,
---------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $40,481 $46,795 $50,393 $39,096 $45,791 $46,832
Federal income taxes 22,342 34,551 41,951 35,252 30,186 40,684
State income taxes 4,645 6,216 12,976 8,506 8,651 11,366
Fixed charges 97,928 88,093 83,994 80,097 78,016 69,424
----------- ----------- ---------- ---------- ----------- -----------
Earnings available for combined fixed
charges and preferred stock
dividend requirements $165,396 $175,655 $189,314 $162,951 $162,644 $168,306
=========== =========== ========== ========== =========== ===========
FIXED CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS
Interest on long-term debt $ 80,030 $ 73,772 $ 63,431 $ 66,305 $ 63,063 $52,743
Other interest 12,260 10,301 16,723 9,534 10,881 12,723
Interest on nuclear fuel burned 928 - - - - -
One third of rental charges 4,710 4,020 3,840 4,258 4,072 3,959
Preferred stock dividend requirements (1) 7,197 6,223 2,778 699 379 427
----------- ----------- ---------- ---------- ----------- -----------
$105,125 $94,316 $86,772 $80,796 $78,395 $69,852
=========== =========== ========== ========== =========== ===========
RATIO OF EARNINGS TO FIXED
CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS 1.57 1.86 2.18 2.02 2.07 2.41
=========== =========== ========== ========== =========== ===========
</TABLE>
(1) Preferred Stock Dividends increased to reflect the pre-tax earnings required
to cover such dividend requirements.
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,227,527
<OTHER-PROPERTY-AND-INVEST> 35,561
<TOTAL-CURRENT-ASSETS> 196,648
<TOTAL-DEFERRED-CHARGES> 330,979
<OTHER-ASSETS> 0
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0
4,299
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0
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<TOT-CAPITALIZATION-AND-LIAB> 1,790,715
<GROSS-OPERATING-REVENUE> 520,867
<INCOME-TAX-EXPENSE> 47,128
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<OTHER-INCOME-NET> 1,524
<INCOME-BEFORE-INTEREST-EXPEN> 82,837
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<NET-INCOME> 40,695
151
<EARNINGS-AVAILABLE-FOR-COMM> 40,565
<COMMON-STOCK-DIVIDENDS> 30,284
<TOTAL-INTEREST-ON-BONDS> 39,718
<CASH-FLOW-OPERATIONS> 57,969
<EPS-PRIMARY> 2.90
<EPS-DILUTED> 2.89
</TABLE>
