SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A-1
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDING MARCH 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
NONE
(Former name, former address and former fiscal year, if changed
since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of March 31, 1999, was 14,334,922.
1
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 4
Consolidated Statement of Income for the three months
ended March 31, 1999 and 1998. 4
Consolidated Balance Sheet as of March 31, 1999
and December 31, 1998. 5
Consolidated Statement of Cash Flows for the three months
ended March 31, 1999 and 1998. 7
Notes to Consolidated Financial Statements. 8
- Statement of Accounting Policies 8
- Capitalization 8
- Rate-Related Regulatory Proceedings 9
- Short-term Credit Arrangements 12
- Income Taxes 14
- Supplementary Information 15
- Fuel Financing Obligations and Other Lease Obligations 16
- Commitments and Contingencies 16
- Capital Expenditure Program 16
- Nuclear Insurance Contingencies 16
- Other Commitments and Contingencies 17
- Connecticut Yankee 17
- Hydro-Quebec 17
- Environmental Concerns 18
- Site Decontamination, Demolition and
Remediation Costs 18
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 18
- Restatement of Financial Results 19
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 20
- Major Influences on Financial Condition 20
- Capital Expenditure Program 21
- Liquidity and Capital Resources 22
- Subsidiary Operations 23
- Results of Operations 23
- Looking Forward 25
SIGNATURES 30
2
This amendment to the Quarterly Report on Form 10-Q of The United
Illuminating Company (the "Company") for the quarter ended March 31, 1999 (the
"Original Form 10-Q") amends and modifies the Original Form 10-Q by restating
Part I: Financial Information, Item I: Financial Statements in order to
supplement and revise the "Consolidated Statement of Income", "Consolidated
Statement of Cash Flows", "Consolidated Balance Sheet", and to add Note (Q),
"Restatement of Financial Results" to the Notes to Consolidated Financial
Statements and by restating Item 2: "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in order to amend and supplement
the section captioned, "Liquidity and Capital Resources".
3
PART I: FINANCIAL INFORMATION
ITEM I: FINANCIAL STATEMENTS
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Thousands except per share amounts)
(Unaudited)
Three Months Ended
March 31,
1999 1998
---- ----
OPERATING REVENUES (NOTE G) $168,667 $162,474
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OPERATING EXPENSES
Operation
Fuel and energy 33,899 40,541
Capacity purchased 9,062 6,222
Other 38,754 33,309
Maintenance 9,446 11,033
Depreciation (Note G) 17,739 20,806
Amortization of cancelled nuclear project,
deferred return and regulatory tax asset 7,026 3,440
Income taxes (Note F) 15,525 11,487
Other taxes (Note G) 14,009 12,959
------------- -------------
Total 145,460 139,797
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OPERATING INCOME 23,207 22,677
------------- -------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 13 30
Other-net (Note G) (469) 445
Non-operating income taxes 891 83
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Total 435 558
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INCOME BEFORE INTEREST CHARGES 23,642 23,235
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INTEREST CHARGES
Interest on long-term debt 12,227 13,523
Interest on Seabrook obligation bonds owned by the company (1,711) (1,818)
Dividend requirement of mandatorily redeemable securities 1,203 1,203
Other interest (Note G) 1,856 844
Allowance for borrowed funds used during construction (448) (129)
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13,127 13,623
Amortization of debt expense and redemption premiums 614 650
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Net Interest Charges 13,741 14,273
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NET INCOME 9,901 8,962
Dividends on preferred stock 51 51
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INCOME APPLICABLE TO COMMON STOCK $9,850 $8,911
============= =============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,042 13,987
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,044 13,997
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $0.70 $0.64
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
4
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
March 31, December 31,
1999 1998*
---- ----
(Unaudited)
Utility Plant at Original Cost
In service $1,888,526 $1,886,930
Less, accumulated provision for depreciation 729,772 714,375
---------------- ----------------
1,158,754 1,172,555
Construction work in progress 29,622 33,695
Nuclear fuel 24,944 20,174
---------------- ----------------
Net Utility Plant 1,213,320 1,226,424
---------------- ----------------
Other Property and Investments 38,507 37,873
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Current Assets
Unrestricted cash and temporary cash investments 15,794 97,689
Restricted cash 26,503 26,812
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 55,469 54,178
Other, less allowance for doubtful accounts
of $775 and $631 51,836 64,240
Accrued utility revenues 21,450 21,079
Fuel, materials and supplies, at average cost 34,040 33,613
Prepayments 12,468 7,424
Other 1,503 154
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Total 219,063 305,189
---------------- ----------------
Deferred Charges
Unamortized debt issuance expenses 9,105 9,421
Other 2,477 1,664
---------------- ----------------
Total 11,582 11,085
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Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 259,452 264,811
Connecticut Yankee 40,861 42,633
Deferred return - Seabrook Unit 1 9,439 12,586
Unamortized redemption costs 23,175 23,468
Unamortized cancelled nuclear projects 10,659 10,952
Uranium enrichment decommissioning cost 1,143 1,177
Other 4,613 4,962
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Total 349,342 360,589
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$1,831,814 $1,941,160
================ ================
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
5
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
March 31, December 31,
1999 1998*
(Unaudited)
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,108 2,046
Capital stock expense (2,182) (2,182)
Unearned employee stock ownership plan equity (9,972) (10,210)
Retained earnings 163,587 163,847
----------------- -----------------
445,547 445,507
Preferred stock - 4,299
Company-obligated mandatorily redeemable securities of
subsidiary holding solely parent debentures 50,000 50,000
Long-term debt
Long-term debt 730,586 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
----------------- -----------------
Net long-term debt 643,173 664,510
----------------- -----------------
Total 1,138,720 1,164,316
----------------- -----------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 30,759 32,711
Pensions accrued 27,412 31,097
Nuclear decommissioning obligation 24,213 23,045
Obligations under capital leases 16,415 16,506
Other 6,358 6,622
----------------- -----------------
Total 105,157 109,981
----------------- -----------------
Current Liabilities
Current portion of preferred stock 4,299 -
Current portion of long-term debt 6,806 66,202
Notes payable 82,172 86,892
Accounts payable 21,202 48,749
Accounts payable - APS utility customers 49,581 54,515
Dividends payable 10,160 10,155
Taxes accrued 23,440 9,015
Interest accrued 14,108 10,203
Obligations under capital leases 354 348
Other accrued liabilities 36,585 39,845
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Total 248,707 325,924
----------------- -----------------
Customers' Advances for Construction 1,866 1,867
----------------- -----------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,433 15,623
Other 3,051 2,065
----------------- -----------------
Total 18,484 17,688
----------------- -----------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities 318,880 321,384
Commitments and Contingencies (Note L)
----------------- -----------------
$1,831,814 $1,941,160
================= =================
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
6
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Three Months Ended
March 31,
1999 1998
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $9,901 $8,962
------------ -----------
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 22,466 21,851
Deferred income taxes (732) (2,251)
Deferred investment tax credits - net (190) (190)
Amortization of nuclear fuel 3,191 1,265
Allowance for funds used during construction (461) (159)
Amortization of deferred return 3,147 3,147
Changes in:
Accounts receivable - net 11,113 4,159
Fuel, material and supplies (427) (3,768)
Prepayments (5,044) (2,968)
Accounts payable (32,481) (14,818)
Interest accrued 3,905 2,528
Taxes accrued 14,425 11,919
Other assets and liabilities (9,818) (2,792)
------------ -----------
Total Adjustments 9,094 17,923
------------ -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 18,995 26,885
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 300 4,015
Long-term debt - 99,780
Notes payable (4,720) 7,369
Securities redeemed and retired:
Long-term debt (86,202) (133,976)
Expense of issue - (800)
Lease obligations (85) (82)
Dividends
Preferred stock (51) (51)
Common stock (10,104) (10,000)
------------ -----------
NET CASH USED IN FINANCING ACTIVITIES (100,862) (33,745)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (5,784) (8,356)
Investment in debt securities 5,447 8,528
------------ -----------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (337) 172
------------ -----------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (82,204) (6,688)
BALANCE AT BEGINNING OF PERIOD 124,501 53,065
------------ -----------
BALANCE AT END OF PERIOD 42,297 46,377
LESS: RESTRICTED CASH 26,503 32,709
------------ -----------
============ ===========
BALANCE: UNRESTRICTED CASH $15,794 $13,668
============ ===========
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $6,306 $10,626
============ ===========
Income taxes $3,700 $2,900
============ ===========
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
7
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, 1998. Such notes are supplemented as
follows:
(A) STATEMENT OF ACCOUNTING POLICIES
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The weighted average AFUDC rate applied in the first three months of 1999
and 1998 was 7.0% and 8.0%, respectively, on a before-tax basis.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $666,000 and $645,000 in the first three
months of 1999 and 1998, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 1999, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$17.4 million and $6.9 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
(B) CAPITALIZATION
(a) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at March 31, 1999, of which 293,374 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 March 31, 1999. No options were exercised during the
first quarter of 1999.
8
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 March 31, 1999, 293,374 shares, with a fair market value of
$12.3 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 $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$105.4 million were free from such limitations at March 31, 1999.
(c) PREFERRED STOCK
On April 8, 1999, the Company called for redemption all 10,370 shares of
its outstanding $100 par value 4.35% Preferred Stock, Series A, all 17,158
shares of its outstanding $100 par value 4.72% Preferred Stock, Series B, all
12,745 shares of its outstanding $100 par value 4.64% Preferred Stock, Series C
and all 2,712 shares of its outstanding $100 par value 5 5/8% Preferred Stock,
Series D. The Company paid a redemption premium of $53,355 in effecting these
redemptions, which were completed on May 14, 1999.
(e) LONG-TERM DEBT
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and interest will be paid semi-annually
beginning on August 1, 1999. In addition, on February 1, 1999, the Company
converted $98.5 million principal amount Business Finance Authority of the State
of New Hampshire Bonds from a weekly reset mode to a multiannual mode. The
interest rate on $27.5 million principal amount of the Bonds is 4.35% for a
three-year period beginning February 1, 1999. The interest rate on $71 million
principal amount of the Bonds is 4.55% for a five-year period. Interest on the
Bonds will be paid semi-annually beginning on August 1, 1999.
On March 8, 1999, the Company prepaid and terminated $20 million of the
remaining $70 million outstanding debt under its $150 million Term Loan
Agreement dated August 29, 1995. On April 16, 1999, the Company prepaid and
terminated the entire remaining $50 million outstanding debt under said $150
million Term Loan Agreement, and the entire $75 million outstanding debt under
its Term Loan Agreement dated October 25, 1996.
(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
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. 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
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the
9
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, and has now reopened its proceeding to consider the amount of the
generation services charge to be included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. 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 prices for electricity at rates in effect on 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
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment 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. On
February 24, 1999, the Federal Energy Regulatory Commission issued an order
authorizing the sale, on March 5, 1999, the DPUC issued a decision approving the
sale; and the sale was completed on April 16, 1999.
The Company has received approximately $277.9 million in cash from this
sale of its operating fossil-fueled generating stations, which amount is subject
to certain post-closing adjustments. The Company realized a small book gain from
the sale proceeds net of taxes and plant investment. However, under the
Restructuring Act, this gain will be offset by a writedown of above-market
generation costs eligible for collection by the Company under the Restructuring
Act's competitive transition assessment, such as regulated plant costs and
tax-related regulatory assets or other costs related to the restructuring
transition, such that there will be no net income effect of the sale. The
Company used the net cash proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) 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
10
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 a separate new division of the Company, using divisional
financial statements and accounting to segregate all revenues, expenses, assets
and liabilities associated with nuclear ownership interests. In a draft decision
dated April 23, 1999, the DPUC tentatively approved the Company's proposal in
this regard.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved 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 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. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999. In a draft decision dated April
23, 1999, the DPUC tentatively approved the proposed corporate restructuring. A
final decision is expected in late May. The proposed corporate restructuring is
also subject to approval by the Company's common stock shareowners and by the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission.
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 power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. 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, as permitted by the Restructuring Act. 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 power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
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.
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 at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order (see below) 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 allow for the
additional standard offer price reduction requirement of 10%, at a minimum,
while providing for the added costs imposed by the restructuring legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.
11
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
FIVE-YEAR RATE PLAN
- -------------------
On December 31, 1996, the DPUC completed a financial and operational
review of the Company and ordered a five-year incentive regulation plan for the
years 1997 through 2001 (the Rate Plan). The DPUC did not change the existing
base rates charged to retail customers, but did provide for retail customer
price reductions of about 5% compared to 1996 and phased-in over 1997-2001; 3%
in 1997 compared to 1996, an additional 1% in 2000 and another 1% in 2001
compared to 1996. The price reductions are accomplished primarily through
reductions of conservation adjustment mechanism revenues, through a surcredit in
each of the five plan years, and through acceptance of the Company's proposal to
modify the operation of the fossil fuel clause mechanism. The Rate Plan also
increased amortization of the Company's conservation and load management program
investments during 1997-1998, and accelerated the amortization recovery of
unspecified assets during 1999-2001 if the Company's return on utility common
stock equity exceeds 10.5%, on an annual basis, after recording the
amortization. The specified accelerated amortizations for 1999-2001, on an
after-tax basis, are $12.1 million, $29.7 million and $32.8 million,
respectively. The Company's authorized return on utility common stock equity
under the Rate Plan is 11.5%, on an annual basis. Earnings above 11.5% are to be
"shared" by utilizing one-third for retail customer price reductions, one-third
for increased amortization of regulatory assets, and one-third retained as
earnings.
The Rate Plan had significant impacts on the Company's 1998 financial
results. Retail customer prices actually decreased by approximately 4.8% in 1998
compared to 1996. Also in 1998, all of the increased amortization of the
Company's conservation and load management program investments prescribed by the
Rate Plan were recorded. No "shared" earnings were recorded in 1998 because
one-time items reduced the Company's return on utility common stock equity to
less than 11.5%, although earnings from operations, excluding one-time items,
would have been above 11.5% and "sharing" would have occurred based on earnings
from operations alone. See "Results of Operations" for a more complete
discussion of these results.
The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan 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 1998 Restructuring Act described above, the Rate
Plan may be reopened and modified. However, aside from implementing an
additional price reduction in 2000 to achieve the minimum aggregate 10% price
reduction compared to 1996 required by the Restructuring Act and the probable
reductions in the accelerated amortizations scheduled in the Rate Plan, the
Company is unable to predict, at this time, in what other respects the Rate Plan
may be modified on account of this legislation.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 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
March 31, 1999, the Company had no short-term borrowings outstanding under this
facility.
On April 16, 1999, the Company repaid and terminated an $80 million
revolving credit agreement prior to its June 7, 1999 due date.
12
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In addition, as of March 31, 1999, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $2.1 million
outstanding under a bank line of credit agreement.
13
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
Three Months Ended
March 31,
1999 1998
---- ----
(000's)
Income tax expense consists of:
Income tax provisions:
Current
Federal $12,337 $10,719
State 3,219 3,126
------------- -------------
Total current 15,556 13,845
------------- -------------
Deferred
Federal (154) (1,551)
State (578) (700)
------------- -------------
Total deferred (732) (2,251)
------------- -------------
Investment tax credits (190) (190)
------------- -------------
Total income tax expense $14,634 $11,404
============= =============
Income tax components charged as follows:
Operating expenses $15,525 $11,487
Other income and deductions - net (891) (83)
------------- -------------
Total income tax expense $14,634 $11,404
============= =============
The following table details the components
of the deferred income taxes:
Seabrook sale/leaseback transaction ($2,082) ($2,181)
Pension benefits 1,525 600
Accelerated depreciation 1,250 1,534
Tax depreciation on unrecoverable plant
investment 1,188 1,212
Unit overhaul and replacement power costs (898) (398)
Conservation and load management (873) (2,007)
Postretirement benefits (433) (102)
Other - net (409) (909)
------------- -------------
Deferred income taxes - net ($732) ($2,251)
============= =============
14
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
Three Months Ended
March 31,
1999 1998
---- ----
(000's)
Operating Revenues
- ------------------
Retail $152,391 $146,545
Wholesale - capacity 1,854 3,426
- energy 11,739 11,389
Other 2,683 1,114
------------- -------------
Total Operating Revenues $168,667 $162,474
============= =============
Sales by Class(MWH's)
- ---------------------
Retail
Residential 533,768 488,329
Commercial 553,798 564,789
Industrial 269,060 265,628
Other 12,199 12,173
------------- -------------
1,368,825 1,330,919
Wholesale 652,746 508,317
------------- -------------
Total Sales by Class 2,021,571 1,839,236
============= =============
Depreciation
- ------------
Plant in Service $14,655 $14,330
Amortization Conservation and
Load Management Costs 2,418 5,657
Nuclear Decommissioning 666 819
------------- -------------
$17,739 $20,806
============= =============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $5,854 $5,621
Local real estate and personal property 6,326 5,482
Payroll taxes 1,829 1,856
------------- -------------
14,009 12,959
Nonoperating and other accounts 134 148
------------- -------------
Total Other Taxes $14,143 $13,107
============= =============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $667 $320
Equity earnings from Connecticut Yankee 181 307
Earnings (Loss) from subsidiary companies (1,206) 195
Miscellaneous other income and (deductions) - net (111) (377)
------------- -------------
Total Other Income and (Deductions) - net ($469) $445
============= =============
Other Interest Charges
- ----------------------
Notes Payable $1,284 $518
Other 572 326
------------- -------------
Total Other Interest Charges $1,856 $844
============= =============
15
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 the financing of 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 May 2000, when it will terminate. At March 31, 1999, no fossil fuel purchases
were being financed under this agreement. On April 16, 1999, the Company sold
all of its operating non-nuclear generation facilities to an unaffiliated
entity. See Note (C) "Rate-Related Regulatory Proceedings". As a result, the
Company will not finance any fuel purchases under this agreement prior to its
termination in May 2000.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $130.8 million, excluding AFUDC, for 1999 through 2003.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the 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 $17.8 million per incident. However, any assessment would be limited to
$2.1 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
$3.1 million.
16
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.
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. 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.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.1
million) and return on investment (approximately $4.5 million) at March 31,
1999, is approximately $30.8 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
Firm Energy Contract, which currently provides for the sale of 9 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, is scheduled to expire in September of 2001, but is subject
to extension in order to remedy deficiencies in deliveries of energy by
Hydro-Quebec. Additionally, the Company is obligated to furnish a guarantee for
its participating share of the debt financing for the Phase II facility. As of
March 31, 1999, the Company's guarantee liability for this debt was
approximately $6.7 million.
17
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water and air quality (particularly "air toxics"
and "global warming"), hazardous waste handling and disposal, toxic substances,
and electric and magnetic fields, the Company may incur substantial capital
expenditures for equipment modifications and additions, monitoring equipment and
recording devices, and it may incur additional operating expenses. Litigation
expenditures may also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful health effects of
electric and magnetic fields. The total amount of these expenditures is not now
determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of March 31, 1999, 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 sold its Bridgeport Harbor Station and New Haven Harbor Station
generating plants in compliance with Connecticut's electric utility industry
restructuring legislation. Environmental assessments performed in connection
with the marketing of these plants indicate that substantial remediation
expenditures will be required in order to bring the plant sites into compliance
with applicable Connecticut minimum standards following their sale. The
purchaser of the plants has agreed to undertake and pay for the major portion of
this remediation. However, the Company will be responsible for remediation of
the portions of the plant sites that will be retained by it.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $497 million (in 1999 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 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 quarter of 1999 was $0.5 million. UI's share of the fund at
March 31, 1999 was approximately $17.4 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $560 million (in 1999 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
18
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
decommissioning trust fund managed by Northeast Utilities (NU). UI's share of
the Millstone Unit 3 decommissioning payments made during the first quarter of
1999 was $0.1 million. UI's share of the fund at March 31, 1999 was
approximately $6.9 million. The current decommissioning cost estimate for the
Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit
commencing in 1997, is $476 million, of which UI's share would be $45 million.
Through March 31, 1999, $93.0 million has been expended for decommissioning. The
projected remaining decommissioning cost is $391 million, of which UI's share
would be $37 million. The decommissioning trust fund for the Connecticut Yankee
Unit is also managed by NU. For the Company's 9.5% equity ownership in
Connecticut Yankee, decommissioning costs of $0.6 million were funded by UI
during the first quarter of 1999, and UI's share of the fund at March 31, 1999
was $24.1 million.
(Q) RESTATEMENT OF FINANCIAL RESULTS
Subsequent to filing its Form 10-Q for the quarter ended March 31, 1999,
the Company reviewed, in consultation with our independent accountants and staff
of the Securities and Exchange Commission, the periods in which it recorded
certain charges and has recorded certain of these charges in earlier periods.
These restatements did not result in any change to retained earnings as
originally reported as of March 31, 1999 and December 31, 1998. However, as a
result of this review, the Company has included in restricted cash as of March
31, 1999 and December 31, 1998 amounts of $23.3 million and $ 23.1 million,
respectively, representing collections by American Payment Systems, Inc. (APS)
agents that are held in APS agent accounts prior to transmittal to the
respective APS customers. In addition, as a result of this review, the Company
has included in other accounts receivable as of March 31, 1999 and December 31,
1998 amounts of $22.1 million and $26.8 million, respectively, representing
amounts collected by APS agents on those days which had not been deposited into
APS bank accounts until a later date. A corresponding restatement of accounts
payable has been recorded to reflect that these receivable amounts are owed to
APS utility customers. The Company had previously presented its consolidated
balance sheet net of these accounts receivable and accounts payable amounts.
19
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
MAJOR INFLUENCES ON FINANCIAL CONDITION
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. See Note (C), "Rate-Related Regulatory
Proceedings", for a discussion of the Restructuring Act and its impact on the
Company.
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. Total operation and maintenance expense, excluding
one-time items and cogeneration capacity purchases, declined by 1.1%, on
average, during the past 5 years. There will be significant changes to operation
and maintenance expense and other expenses in 1999, partly as a result of the
Generation Asset Divestiture described in "Looking Forward" below.
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.
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. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. 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 could have a 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.
20
CAPITAL EXPENDITURE PROGRAM
The Company's 1999-2003 capital expenditure program, excluding allowance
for funds used during construction and its effect on certain capital-related
items, is presently budgeted as follows:
1999 2000 2001 2002 2003 Total
---- ---- ---- ---- ---- -----
(000's)
Generation (1) $4,891 $4,229 $2,435 $1,851 $1,280 $14,686
Distribution and Transmission 16,954 15,761 11,470 11,509 12,816 68,510
Other 6,443 5,238 2,731 2,543 1,949 18,904
------ ------ ------ ------ ------ -------
Subtotal 28,288 25,228 16,636 15,903 16,045 102,100
Nuclear Fuel 2,413 9,298 6,774 2,953 7,302 28,740
------ ------ ------ ------ ------ -------
Total Expenditures $30,701 $34,526 $23,410 $18,856 $23,347 $130,840
======= ======= ======= ======= ======= ========
Rate Base and Other Selected Data:
- ---------------------------------
Depreciation
Book Plant (1) $50,200 $48,120 $48,636 $48,910 $49,531
Conservation Assets 5,048 0 0 0 0
Decommissioning 2,781 2,892 3,007 3,128 3,253
Additional Required Amortization
Regulatory Tax Assets (pre-tax
and after-tax) 12,096 0 0 0 0
Other Regulatory Assets (pre-tax)(2) 0 49,500 54,500 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 0 0 0 0
Estimated Rate Base
(end of period) 849,684
(average) 920,367
(1) Reflects divestiture of operating fossil-fueled generation plant on April
16, 1999. See Note (C), "Rate-Related Regulatory Proceedings", for a
description of this divestiture. Remaining operating generation is
nuclear, excluding nuclear fuel.
(2) Additional amortization of unspecified regulatory assets, as ordered by
the Connecticut Department of Public Utility Control in its December 31,
1996 retail rate order, provided that, as expected, common equity return
on utility investment exceeds 10.5% after recording the additional
amortization. Substantially all of this accelerated amortization may have
to be eliminated in order to achieve the minimum 10% price reduction
(compared to the average fully bundled prices in effect on December 31,
1996), while providing for the added costs imposed by Public Act 98-28, a
statute enacted by Connecticut, designed to restructure the State's
regulated electric utility industry. See Note (C), "Rate-Related
Regulatory Proceedings", for a discussion of this statute.
21
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 1999, the Company had $19.0 million of cash and temporary cash
investments, including the Seabrook operating deposit, but excluding restricted
cash of American Payment Systems, Inc. This was a decrease of $82.4 million from
the corresponding balance at December 31, 1998. The components of this decrease,
which are detailed in the Consolidated Statement of Cash Flows, are summarized
as follows:
(Millions)
Balance, December 31, 1998 $ 101.4
------
Net cash provided by operating activities 18.8
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (90.7)
- Dividend payments (10.2)
Net cash provided by investing activities, excluding
investment in plant 5.5
Cash invested in plant, including nuclear fuel (5.8)
Net Change in Cash (82.4)
-----
Balance, March 31, 1999 $19.0
=====
The Company's capital requirements are presently projected as follows:
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year (1) $101.4 $34.5 $9.0 $42.7 $ -
Internally Generated Funds less Dividends (2) 98.4 59.4 57.4 64.4 72.7
Net Proceeds from Sale of Fossil Generation Plants 160.0 - - - -
----- ----- ---- ----- ----
Subtotal 359.8 93.9 66.4 107.1 72.7
Less:
Capital Expenditures (excluding AFUDC) (2) 30.7 34.5 23.4 18.9 23.3
----- ----- ---- ----- ----
Cash Available to pay Debt Maturities and Redemptions 329.1 59.4 43.0 88.2 49.4
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 145.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
----- ----- ---- ----- -----
External Financing Requirements (Surplus) $(34.5) $(9.0) $(42.7) $12.1 $51.1
===== ===== ====== ===== =====
(1) Includes Seabrook Unit 1 operating deposit, but not restricted cash of
American Payments Systems, Inc. of $23.1 million.
(2) 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 December 31,
1996 price levels by the year 2000. Connecticut's Restructuring Act,
described at Note (C), "Rate-Related Regulatory Proceedings", required
the Company to
22
divest itself of its fossil-fueled generating plants and requires it to
attempt to divest itself of its ownership interests in nuclear-fueled
generating units prior to January 1, 2004. This forecast reflects the net
after-tax proceeds from the divestiture of fossil-fueled generation plants
on April 16, 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.
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 with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
additional short-term and long-term debt. The continued availability of these
methods of financing will be dependent on many factors, including conditions in
the securities markets, economic conditions, and the level of the Company's
income and cash flow.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 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
March 31, 1999, the Company had no 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 UI's regulated electric utility business and provide long-term
rewards to UI's shareowners.
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. It
manages agent networks in 36 states and processed approximately $7.5 billion in
customer payments during 1998, generating operating revenues of approximately
$33.7 million and operating income of approximately $1.7 million. 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 a 33 1/3% owner of Bridgeport Energy, LLC, which is
completing construction of a 500-megawatt merchant wholesale electric generating
facility in Bridgeport, Connecticut.
RESULTS OF OPERATIONS
FIRST QUARTER OF 1999 VS. FIRST QUARTER OF 1998
- -----------------------------------------------
Earnings for the first quarter of 1999 were $9.9 million, or $.70 per share
(on both a basic and diluted basis), up $1.0 million, or $.06 per share, from
the first quarter of 1998. Excluding one-time items, earnings from operations
were $9.3 million, or $.66 per share, up $.02 per share from the first quarter
of 1998.
23
The one-time items recorded in the first quarter of 1999 were:
EPS
------------------------------------------------------------------------------
1999 Quarter 1 Purchased power expense refund $.12
"Sharing" of earnings due to refund $(.08)
------------------------------------------------------------------------------
Retail revenues from operations increased by $6.8 million in the first
quarter of 1999 compared to the first quarter of 1998, as electric sales
increased for reasons detailed below. Retail revenues decreased by $1.0 million
because of "sharing" of earnings required under the current regulatory structure
as applied to the one-time gain recorded in the first quarter of 1999. Retail
fuel and energy expense decreased by $5.0 million, primarily from lower fossil
fuel prices, and there was an increase of $0.2 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $11.6 million or 10.3%. The principal components of
the retail sales margin change for the quarter, year over year, include:
$ millions
------------------------------------------------------------------ -----------
Revenue from:
------------------------------------------------------------------ -----------
Estimate of "real" retail sales growth, up 2.9% 4.3
------------------------------------------------------------------ -----------
Estimate of weather affect on retail sales, up 1.6% 2.4
------------------------------------------------------------------ -----------
Sales decrease from Yale University cogeneration, (1.7)% (2.5)
------------------------------------------------------------------ -----------
Price mix of sales and other 2.5
------------------------------------------------------------------ -----------
"Sharing" due to one-time gain (1.0)
------------------------------------------------------------------ -----------
Fuel and energy, margin effect:
------------------------------------------------------------------ -----------
Sales increase (0.7)
------------------------------------------------------------------ -----------
Nuclear fuel prices to account for previously spent fuel (0.8)
------------------------------------------------------------------ -----------
Fossil fuel price 6.6
------------------------------------------------------------------ -----------
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $2.2 million in the first quarter of 1999 compared to the first quarter of
1998 from lower wholesale capacity sales. Other operating revenues, which
include NEPOOL related transmission revenues, increased by $1.6 million. NEPOOL
transmission revenues are recoveries, for the most part, of NEPOOL transmission
expense and simply reflect new accounting requirements implemented by the
Federal Energy Regulatory Commission (FERC).
It should be noted that on April 16, 1999, the Company completed the sale
of its operating fossil-fueled generating plants and existing wholesale sales
contracts (known as the Generation Asset Divestiture or GAD) that was required
by Connecticut's electric utility industry restructuring legislation. As a
result of GAD, the "geography" of the Company's costs on the income statement,
and hence, the year-over-year variances, will change significantly beginning in
the second quarter. This particularly relates to wholesale revenue, fossil fuel
expense, operations and maintenance expense, depreciation and interest charges.
See "Looking Forward" below for more details.
Operating expenses for operations, maintenance and purchased capacity
charges increased by $6.7 million in the first quarter of 1999 compared to the
first quarter of 1998. The principal components of these expense changes
include:
$ millions
------------------------------------------------------------------ ---------
Capacity expense:
------------------------------------------------------------------ ---------
Connecticut Yankee (0.4)
------------------------------------------------------------------ ---------
Cogeneration and other purchases (see Note) 3.2
------------------------------------------------------------------ ---------
Other O&M expense:
------------------------------------------------------------------ ---------
Seabrook Unit (refueling outage and accruals) 1.9
------------------------------------------------------------------ ---------
Millstone Unit 3 (0.2)
------------------------------------------------------------------ ---------
Fossil generation unit overhaul and outage costs (1.6)
------------------------------------------------------------------ ---------
NEPOOL transmission expense 0.9
------------------------------------------------------------------ ---------
Other miscellaneous 2.9
------------------------------------------------------------------ ---------
24
Note: A cogeneration facility was out of service for about a month in the first
quarter of 1998 but has operated normally in 1999.
Depreciation expense increased by $0.2 million in the first quarter of 1999
compared to the first quarter of 1998.
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year Rate Plan to
reduce the Company's retail prices and accelerate the recovery of certain
"regulatory assets". According to the Rate Plan, under which the Company is
currently operating, "accelerated" amortization of past utility investments is
scheduled for every year that the Rate Plan is in effect, contingent upon the
Company earning a 10.5% return on utility common stock equity. All of the
accelerated amortization for 1998, amounting to $13.1 million (before-tax, $8.5
million after-tax), was recorded against earnings from operations in 1998. One
fourth of the total accelerated amortization for 1999, or $3.3 million
(before-tax, $2.1 million after-tax), was recorded in the first quarter. The
Company has begun amortizing regulatory income tax assets for the 1999 amount,
totaling $12.1 million (after-tax), one-fourth of it, or $3.0 million
(after-tax), in the first quarter.
The Company can also incur additional accelerated amortization expense as a
result of the "sharing" mechanism in the Rate Plan if the Company achieves a
return on utility common stock equity above 11.5%, on an annual basis. Such
"sharing" amortization was recorded in the first quarter of 1999, in the amount
of $0.6 million (after-tax), as a result of the one-time gain recorded in the
first quarter. There was no "sharing" recorded against earnings from operations
in the first quarter of 1998, or in 1999.
Other net income decreased by about $0.9 million in the first quarter of
1999 compared to first quarter of 1998. The Company's largest unregulated
subsidiary, American Payment Systems (APS), earned about $246,000 (before-tax)
in the first quarter of 1999, slightly less than the $284,000 (before-tax)
earned in the first quarter of 1998. Income for Precision Power, Inc. decreased
$0.7 million (before-tax), reflecting increased infrastructure costs as it
prepares to expand its service offerings. The first quarter loss was in line
with expectations outlined in the "Looking Forward" section of Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations in the Company's annual report on Form 10-K for the year ended
December 31, 1998. Income from other unregulated subsidiary activities at United
Resources, Inc. decreased by $0.6 million (before-tax) from start-up costs.
Interest charges continued on their downward trend, decreasing by $0.2
million in the first quarter of 1999 compared to the first quarter of 1998. Most
of the reduction in interest charges anticipated for 1999 compared to 1998 will
come after the GAD, which was completed on April 16, 1999. On April 16, 1999,
the Company used proceeds received from the sale of plant to repay $205 million
of debt. See "Looking Forward" below for more details.
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
INCOME AND EARNINGS NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF
POSSIBLE VALUES.)
Five-year Rate Plan
- -------------------
The reader is referred to Note (C), "Rate-Related Regulatory Proceedings"
above, for a description of the Company's five-year Rate Plan and Connecticut's
electric utility industry restructuring legislation.
25
1999 Earnings
- -------------
1999 will be a year of transition to the January 1, 2000 effective date of
electric utility restructuring legislation passed by the Connecticut legislature
in 1998. The Company has taken one major step toward restructuring by effecting
the sale of its operating fossil fuel generation plants and existing wholesale
sales contracts (known as the Generation Asset Divestiture program, or GAD).
That sale was completed on April 16, 1999. All of the changes resulting from
GAD, described below, will occur beginning April 16.
One result of the GAD will be a reduction in the electric utility rate
base, the basis for measuring return on utility common stock equity. Rate base
is expected to decline from an average of $1,128 million in 1998 to about $920
million in 1999. Offsetting the effect of the decline in total rate base is the
Company's long-standing policy of debt paydown that increases the portion of
rate base financed by equity. The portion of rate base that is financed by
equity is expected to decline from an average of about $431 million in 1998 to
about $410-$420 million in 1999. During 1998, a return of 11.5% on utility
common stock equity would have produced earnings of about $3.43 per share.
Absent the one-time items that reduced earnings in 1998, utility earnings from
operations above $3.43 per share would have given rise to an imputed "sharing"
benefit of an additional $.12 per share. Because of the equity funded rate base
reduction expected in 1999, the allowed 11.5% return would be expected to
produce utility earnings in the $3.35-$3.40 per share range. Currently, the
Company expects to be in a "sharing" position in 1999, to a somewhat greater
extent than was the case for earnings from operations in 1998.
The Company's earnings from its utility business are affected principally
by: retail sales that fluctuate with weather conditions and economic activity,
nuclear generating unit availability and operating costs, and interest rates.
These are all items over which the Company has little control.
The Company's revenues are principally dependent on the level of retail
electricity sales. The two primary factors that affect the volume of these
retail sales are economic conditions and weather. The Company's retail sales for
1998 of 5,452 gigawatt-hours set an all-time record for the Company and were up
1.4% from the 1997 level.
The Company estimates that mild 1998 weather reduced retail kilowatt-hour
sales by about 0.5%, retail revenues by about $3.4 million, and retail sales
margin by about $2.7 million. Weather corrected retail sales for 1998 were
probably in the 5,470-5,500 gigawatt-hour range. On this weather-adjusted basis,
the Company experienced about 1.0-1.5% of "real" sales growth in 1998 over
weather-adjusted 1997 sales, with most of the growth appearing to occur in the
first three quarters of the year.
Aside from "real" economic growth, reductions in retail electricity sales
will occur in 1999 compared to 1998 as a result of a cogeneration unit at Yale
University that produces approximately one half of Yale's annual electricity
requirements (about 1.5% of the Company's total 1998 retail sales). This unit
commenced operations in mid-1998, and has reduced total Company retail
kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The remaining impact
will be reflected in the first half of 1999. Thus, it would require "real"
growth of 0.5% in 1999 compared to 1998 just to maintain the 1998 level of
"real" sales. "Real" growth in kilowatt-hour sales for the first quarter of 1999
compared to the first quarter of 1998 was estimated to be 2.9%, only partially
offset by a 1.7% decrease in sales to Yale University. Retail kilowatt-hour
sales growth of 1.0%, on an annual basis, produces a retail sales margin
improvement of about $5.0 million, before any "sharing" effect considerations.
Prices in individual customer rate classes will not change in 1999 relative
to 1998, exclusive of any "sharing". However, sales growth is occurring in rate
classes with higher than average prices, and the Company expects to have an
increase in retail revenue of about $3.0 million in 1999 compared to 1998 from
this price mix improvement.
Other operating revenues are expected to increase by about $4.0 million in
1999 relative to 1998, due to increased transmission revenues resulting from
NEPOOL restructuring changes; but this should have no net income effect, as the
higher revenues are due to higher transmission operating expense. Other than the
NEPOOL impact, these revenues are expected to decrease by about $2.0 million to
a more normal level. The Company does not
26
anticipate, at this time, any other significant revenue reductions in 1999
compared to 1998, unless the Company is achieving a "sharing" level of earnings.
As a result of the GAD, wholesale capacity revenues will decrease by about
$7.7 million in 1999 compared to 1998, because existing wholesale sales
contracts were part of the GAD. Also as a result of the GAD, the Company's
purchased energy charges will increase in 1999 compared to 1998 by about $40
million, to replace the power previously provided by the Company's fossil-fueled
generation plants. A power supply purchase agreement was part of the GAD and it
will help to ensure that the Company has adequate resources to meet customer
energy demands until July 2000 (the price under this short-term, fixed-price
agreement declines somewhat in 2000 compared to 1999) when all customers will
have a choice of generation suppliers. The Company expects that its projected
1999 energy requirements that are not met by the GAD power supply purchase
agreement will be met at lower prices than those experienced in 1998, primarily
because of lower projected fossil fuel prices and energy prices in general. This
is expected to result in energy cost savings of about $5 million.
Purchased capacity costs should decrease by about $2 million in 1999, due
primarily to the retirement of the Connecticut Yankee nuclear generation plant.
Several other expense categories are expected to be reduced substantially
in 1999 because of the GAD and the Company's other cost reduction efforts,
offsetting the impact of the increase in purchased energy charges. Operation and
maintenance expense is expected to decrease by a net $22 million, reflecting a
decrease of $32 million due to the GAD and other general changes, partly offset
by increases of about $5 million for nuclear unit refueling outages and $1
million for Y2K costs and $4 million due to NEPOOL transmission operating
expense charges The latter would have no net income effect, as the higher
transmission expense should be offset by higher transmission revenues. Total Y2K
costs for 1999 are currently projected at about $3.6 million. Other operation
and maintenance expenses in 1999 should be fairly stable compared to 1998,
unless an event occurs that cannot be predicted at this time.
Consolidated interest costs are now expected to decline by about $12
million in 1999 compared to 1998, to about $40 million, a level that was last
experienced in 1982. This anticipated interest cost reduction will result
largely from utility debt paydown through use of the after-tax cash proceeds
from the GAD sale, partly offset by the impact of the Company's passive
financial investment increase in Bridgeport Energy LLC. The Bridgeport Energy
investment was announced in a news release dated March 30, 1999, and represents
a 33 1/3% stake in an operational combined cycle gas turbine operated on a
merchant basis by Duke Energy in Bridgeport, Connecticut. The Company also
expects to generate substantial cash flow from operations after dividend and
capital spending, which will also be used to reduce debt.
Depreciation, excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to the GAD but also from the
near completion in 1998 of the depreciation of previously capitalized
conservation program expenditures. A significant portion of the decrease in
depreciation related to the GAD will not affect taxable income and will not
increase income taxes, and will therefore supplement the $13 million decrease
with an additional tax benefit, comparing 1999 to 1998, of about $2.5 million,
or $.18 per share.
Accelerated amortization, under the Rate Plan, will increase by about $4
million (on an equivalent after-tax basis) in 1999 compared to 1998, exclusive
of any "sharing" amortization. Property taxes should decrease by about $2
million, due mostly to the GAD. Other operating expenses can be expected to have
some increases and some decreases that should, more or less, offset one another.
In summary, the Company expects substantial net expense reductions as a
result of the GAD and ongoing cost control measures that should more than
compensate for increased charges for purchased power and increased accelerated
amortization costs in 1999. This should allow utility earnings to increase above
an 11.5% return on utility common stock equity into the "sharing" range of the
Rate Plan. The 11.5% return level would allow for utility earnings from
operations of about $3.35-$3.40 per share, while the "shared" earnings from
operations above
27
that level are currently anticipated to increase per share earnings by about
$.20 per share, although the size of this increase will fluctuate with every
event that affects utility operations during the year. The Company expects that
1999 quarterly earnings from operations will follow a pattern similar to that of
1998 on a weather-normalized basis.
Unregulated subsidiaries are expected to occasion a loss of up to $.10 per
share to earnings in 1999. American Payment Systems, Inc. is expected to build
on 1998's contribution to earnings from operations of $.07 per share. However,
this will depend on its ability to expand sales to its utility customers.
Precision Power, Inc. (PPI) increased its organizational infrastructure in 1998,
also in an effort to increase its presence in its principal markets of
distributed power systems and services. At its current level of expense, PPI
would occasion a loss of $.10 to $.15 per share in 1999, if no substantial new
contracts are obtained. PPI may also engage in acquisition activities in 1999
that may have short-term dilutive effects on earnings beyond those indicated
above. For 2000 and beyond, the Company's passive financial investment in
Bridgeport Energy is expected to increase annual earnings from operations by
$.10 to $.15 per share.
As a result of the earnings contributions anticipated from all of its
different business activities described above, the Company expects net earnings
per share from operations to be in the range of $3.45 to $3.65 in 1999. These
estimates are subject to all of the contingencies and uncertainties detailed in
the preceding discussion and the reader is cautioned to read this "Looking
Forward" section in its entirety.
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. This comprehensive program includes all
information technology systems and encompasses systems critical to the
generation, transmission and distribution of electric energy as well as
traditional business 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 have 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. Both external and internal resources are being
utilized to accomplish the testing, remediation and renovation efforts. A total
of 383 affected business processes have been identified and 307 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 June 30, 1999. 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 June 1, 1999, except in a
minority of cases where a business specific need dictates a later date - but not
later than December 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 included its operating
non-nuclear generation facilities in the Year 2000 program up to the date of
their divestiture on April 16, 1999. At that point, all related documentation
was transferred and delivered to Wisvest-Connecticut, LLC, the purchaser of
these generation facilities. See Note (C), "Rate-Related Regulatory Proceedings"
above, for a description of this transaction.
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
28
that the entities that might impact the program most significantly in this
regard are its telecommunications providers, the other participants in the New
England Power Pool (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 effect on electricity delivery and
telemetering. In its efforts to mitigate these risks the Company has taken
several actions. UI has communicated its concerns to its principal
telecommunications provider and a joint effort to design and plan appropriate
testing to insure that all critical telecommunications functions will be
operational has commenced. The Year 2000 Issue is also being addressed at the
regional level by NEPOOL and the ISO. Coordination efforts with NEPOOL to
establish utility testing and readiness are in progress. The Company is a
participant in all of the subcommittees working within NEPOOL/ISO on efforts to
assure operational reliability. 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 (NERC) . The first
NERC directed test was completed on April 9, 1999.
Aside from telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant risk to the success of the Company's Year 2000 compliance
implementation program. In order to minimize these risks, the Company has
commenced its 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. High level contingency planning for essential business
processes has been completed. These plans will be continually reviewed, revised
and modified throughout the remainder of the year as appropriate. 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.
The Company believes that the successful implementation of this program
will cost approximately $6 million for existing information systems and embedded
technology. A total of $4.6 million had been expended as of March 31, 1999. 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.
29
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 11/03/99 Signature /s/ Robert L. Fiscus
-------------- ------------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
30