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 JUNE 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
------------- ----------------
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 June 30, 1999, was 14,334,922.
1
<PAGE>
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 4
Consolidated Statement of Income for the three and six months
ended June 30, 1999 and 1998. 4
Consolidated Balance Sheet as of June 30, 1999 and
December 31, 1998. 5
Consolidated Statement of Cash Flows for the three and six
months ended June 30, 1999 and 1998. 7
Notes to Consolidated Financial Statements. 8
- Statement of Accounting Policies 8
- Capitalization 8
- Rate-Related Regulatory Proceedings 10
- Short-term Credit Arrangements 13
- 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 16
- Connecticut Yankee 16
- Hydro-Quebec 17
- Environmental Concerns 17
- 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 28
SIGNATURES 34
2
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This amendment to the Quarterly Report on Form 10-Q of The United
Illuminating Company (the "Company") for the quarter ended June 30, 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 Notes (F) and (G) to
the Notes to Consolidated Financial Statements, 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 sections captioned, "Liquidity and Capital Resources" and "Results of
Operations".
3
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<TABLE>
<CAPTION>
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 Six Months Ended
June 30, June 30,
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
OPERATING REVENUES (NOTE G) $164,533 $159,792 $333,200 $322,266
-------------- ------------ ------------ -------------
OPERATING EXPENSES
Operation
Fuel and energy 38,483 33,412 72,382 73,953
Capacity purchased 8,678 8,978 17,740 15,200
Other 36,761 38,094 75,515 71,403
Maintenance 6,013 10,560 15,459 21,593
Depreciation 15,618 20,632 33,357 41,438
Amortization of cancelled nuclear project,
deferred return and regulatory tax asset 6,464 3,439 13,490 6,879
Income taxes (Note F) 15,851 11,193 31,376 22,680
Other taxes (Note G) 11,472 12,310 25,481 25,269
-------------- ------------ ------------ -------------
Total 139,340 138,618 284,800 278,415
-------------- ------------ ------------ -------------
OPERATING INCOME 25,193 21,174 48,400 43,851
-------------- ------------ ------------ -------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 254 40 267 70
Other-net (Note G) (2,380) 439 (2,849) 884
Non-operating income taxes 1,748 905 2,639 988
-------------- ------------ ------------ -------------
Total (378) 1,384 57 1,942
-------------- ------------ ------------ -------------
INCOME BEFORE INTEREST CHARGES 24,815 22,558 48,457 45,793
-------------- ------------ ------------ -------------
INTEREST CHARGES
Interest on long-term debt 10,163 12,879 22,390 26,402
Interest on Seabrook obligation bonds owned by the company (1,711) (1,818) (3,422) (3,636)
Dividend requirement of mandatorily redeemable securities 1,203 1,203 2,406 2,406
Other interest (Note G) 820 1,432 2,676 2,276
Allowance for borrowed funds used during construction (323) (135) (771) (264)
-------------- ------------ ------------ -------------
10,152 13,561 23,279 27,184
Amortization of debt expense and redemption premiums 677 618 1,291 1,268
-------------- ------------ ------------ -------------
Net Interest Charges 10,829 14,179 24,570 28,452
-------------- ------------ ------------ -------------
NET INCOME 13,986 8,379 23,887 17,341
Premium (Discount) on preferred stock redemptions 53 (21) 53 (21)
Dividends on preferred stock 15 50 66 101
-------------- ------------ ------------ -------------
INCOME APPLICABLE TO COMMON STOCK $13,918 $8,350 $23,768 $17,261
============== ============ ============ =============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,049 14,021 14,045 14,004
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,050 14,024 14,047 14,011
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $0.99 $0.60 $1.69 $1.23
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72 $1.44 $1.44
</TABLE>
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
4
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<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
June 30, December 31,
1999 1998*
---- ----
(Unaudited)
<S> <C> <C>
Utility Plant at Original Cost
In service $1,512,288 $1,886,930
Less, accumulated provision for depreciation 517,889 714,375
---------------- ---------------
994,399 1,172,555
Construction work in progress 30,495 33,695
Nuclear fuel 23,823 20,174
---------------- ---------------
Net Utility Plant 1,048,717 1,226,424
---------------- ---------------
Other Property and Investments
Investment in generation facility 75,439 -
Nuclear decommissioning trust fund assets 25,973 23,045
Other 18,215 14,828
---------------- ---------------
119,627 37,873
---------------- ---------------
Current Assets
Unrestricted cash and temporary cash investments 23,180 97,689
Restricted cash 28,045 26,812
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 59,790 54,178
Other, less allowance for doubtful accounts
of $864 and $545 48,093 64,240
Accrued utility revenues 25,892 21,079
Fuel, materials and supplies, at average cost 7,846 33,613
Prepayments 3,662 7,424
Other 409 154
---------------- ---------------
Total 196,917 305,189
---------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 8,704 9,421
Other 1,962 1,664
---------------- ---------------
Total 10,666 11,085
---------------- ---------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 199,845 264,811
Connecticut Yankee 39,397 42,633
Deferred return - Seabrook Unit 1 6,293 12,586
Unamortized redemption costs 22,900 23,468
Unamortized cancelled nuclear projects 10,366 10,952
Uranium enrichment decommissioning cost 1,108 1,177
Other 20,279 4,962
---------------- ---------------
Total 300,188 360,589
---------------- ---------------
$1,676,115 $1,941,160
================ ===============
</TABLE>
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
5
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<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
June 30, December 31,
1999 1998*
---- ----
(Unaudited)
<S> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,140 2,046
Capital stock expense (2,171) (2,182)
Unearned employee stock ownership plan equity (9,735) (10,210)
Retained earnings 167,378 163,847
--------------- ---------------
449,618 445,507
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 605,604 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
--------------- ---------------
Net long-term debt 518,191 664,510
--------------- ---------------
Total 1,017,809 1,164,316
--------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 29,151 32,711
Pensions accrued (Note H) 25,948 31,097
Nuclear decommissioning obligation 25,973 23,045
Obligations under capital leases 16,322 16,506
Other 6,185 6,622
--------------- ---------------
Total 103,579 109,981
--------------- ---------------
Current Liabilities
Current portion of long-term debt 6,806 66,202
Notes payable 48,684 86,892
Accounts payable 36,740 48,749
Accounts payable - APS utility customers 49,662 54,515
Dividends payable 10,115 10,155
Taxes accrued 48,936 9,015
Interest accrued 16,616 10,203
Obligations under capital leases 361 348
Other accrued liabilities 27,869 39,845
--------------- ---------------
Total 245,789 325,924
--------------- ---------------
Customers' Advances for Construction 1,867 1,867
--------------- ---------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,242 15,623
Deferred gain on sale of property 15,708 4
Other 8,679 2,061
--------------- ---------------
Total 39,629 17,688
--------------- ---------------
Deferred Income Taxes (future tax liabilities owed 267,442 321,384
to taxing authorities)
Commitments and Contingencies (Note L)
--------------- ---------------
$1,676,115 $1,941,160
=============== ===============
</TABLE>
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
6
<PAGE>
<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $13,986 $8,379 $23,887 $17,341
-------------- ------------- ------------ --------------
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 19,252 21,897 41,718 43,748
Deferred income taxes 4,547 (1,011) 3,815 (3,262)
Deferred income taxes - generation asset sale (70,222) - (70,222) -
Deferred investment tax credits - net (191) (191) (381) (381)
Amortization of nuclear fuel 1,489 1,232 4,680 2,497
Allowance for funds used during construction (577) (175) (1,038) (334)
Amortization of deferred return 3,146 3,146 6,293 6,293
Changes in:
Accounts receivable - net (578) (14,727) 10,535 (10,569)
Fuel, materials and supplies 639 (7,794) 212 (11,562)
Prepayments 8,806 (3,113) 3,762 (6,081)
Accounts payable 15,619 12,127 (16,862) (2,691)
Interest accrued 2,508 5,389 6,413 7,917
Taxes accrued (9,615) (10,000) 4,810 1,920
Taxes accrued - generation asset sale 35,111 - 35,111 -
Other assets and liabilities (26,915) 3,987 (36,733) 1,195
-------------- ------------- ------------ --------------
Total Adjustments (16,981) 10,767 (7,887) 28,690
-------------- ------------- ------------ --------------
NET CASH PROVIDED BY OPERATING ACTIVITIES (2,995) 19,146 16,000 46,031
-------------- ------------- ------------ --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 269 295 569 4,310
Long-term debt - - - 99,780
Notes payable (33,488) 73,705 (38,208) 81,074
Securities redeemed and retired:
Preferred stock (4,299) (52) (4,299) (52)
Long-term debt (125,000) (80,000) (211,202) (213,976)
Discount (Premium) on preferred stock redemption (53) 21 (53) 21
Expense of issue - - - (800)
Lease obligations (86) (84) (171) (166)
Dividends
Preferred stock (65) (51) (116) (102)
Common stock (10,111) (10,090) (20,215) (20,090)
-------------- ------------- ------------ --------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (172,833) (16,256) (273,695) (50,001)
-------------- ------------- ------------ --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in unregulated businesses (75,092) - (75,092) -
Net cash received from sale of generation assets 270,590 - 270,590 -
Plant expenditures, including nuclear fuel (10,742) (2,213) (16,526) (10,569)
Investment in debt securities - - 5,447 8,528
-------------- ------------- ------------ --------------
NET CASH PROVIDED BY (USED IN) ACTIVITIES 184,756 (2,213) 184,419 (2,041)
-------------- ------------- ------------ --------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 8,928 677 (73,276) (6,011)
BALANCE AT BEGINNING OF PERIOD 42,297 46,377 124,501 53,065
-------------- ------------- ------------ --------------
BALANCE AT END OF PERIOD 51,225 47,054 51,225 47,054
LESS: RESTRICTED CASH 28,045 34,675 28,045 34,675
------------ --------------
============== ============= ============ ==============
BALANCE: UNRESTRICTED CASH $23,180 $12,379 $23,180 $12,379
============== ============= ============ ==============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $8,177 $8,824 $14,483 $19,450
============== ============= ============ ==============
Income taxes $54,250 $20,150 $57,950 $23,050
============== ============= ============ ==============
</TABLE>
Note: Cash Flows from Operating Activities for the three and six months
ended June 30, 1999 were reduced by the current income tax effects
of the generation asset sale in the amount of $35,111.
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
7
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The consolidated financial statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all adjustments that are, in the opinion of management, necessary for a fair
presentation 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 six months of
1999 and 1998 was 7.0% and 8.0% on a before-tax basis.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $1,950,000 and $1,290,000 in the first six
months of 1999 and 1998, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 1999, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$18.7 million and $7.3 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
COMPREHENSIVE INCOME
Comprehensive income for the six months ended June 30, 1999 and 1998 is
equal to net income as reported.
(B) CAPITALIZATION
(a) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at June 30, 1999, of which 286,389 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
8
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
exercise price of $39.5625 per share, and 5,000 shares of stock at an exercise
price of $42.375 per share have been granted by the Board of Directors and
remained outstanding at June 30, 1999. No options were exercised during the
first six months of 1999.
On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the awarding of options to purchase up to 650,000 shares of the Company's
common stock over periods of from one to ten years following the dates when the
options are granted. The exercise price of each option cannot be less than the
market value of the stock on the date of the grant. On June 28, 1999, the
Company's shareowners approved the plan. Options to purchase 137,000 shares of
stock at an exercise price of $43 7/32 per share have been granted by the Board
of Directors and remained outstanding at June 30, 1999. No options were
exercisable during the second quarter of 1999.
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 June 30, 1999, 286,389 shares, with a fair market value of $12.2
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
$109.2 million were free from such limitations at June 30, 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.
9
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(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 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," a "conservation and load management program charge" and a
"renewable energy investment charge". The competitive transition assessment will
recover stranded 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. 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 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 during 1996, as discussed below. The standard offer is
required, subject to certain adjustments, to be the total rate charged under the
standard offer, including the generation services component, transmission and
distribution charge, the competitive transition assessment, the systems benefits
charge, the 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
generating 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.
10
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company received approximately $277.9 million in cash from this sale
of its operating fossil-fueled generating stations. The Company realized a
before-tax book gain of $86.5 million, or $16.2 million after-tax, from the sale
of these plant investments. 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 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 decision dated May 19, 1999,
the DPUC 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 decision dated May 19, 1999,
the DPUC approved the proposed corporate restructuring. 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.
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act.
Under the Restructuring Act, 35% of the Company's customers will be able
to choose their power supply providers on and after January 1, 2000, and all of
the Company's customers will be able to choose their power supply providers as
of July 1, 2000. On and after January 1, 2000 and through December 31, 2003, the
Company will be required to offer fully-bundled "standard offer" electric
service, under regulated rates, to all customers who do not choose an alternate
power supply provider. The standard offer rates will include the fully-bundled
price of generation, transmission and distribution services, the competitive
transition assessment, the systems benefits charge and the conservation, load
management and renewable energy charges. The fully-bundled standard offer rates
must
11
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
be at least 10% below the average fully-bundled prices in 1996. The Company has
already delivered about 4.8% of this decrease, in bill reductions through 1998.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be. In April, May and June of 1999, the
Company filed descriptive material, data and supporting testimony with the DPUC
setting forth the Company's overall approach for determining the components of
its standard offer rates, and for continuation of the five-year Rate Plan
ordered by the DPUC in its 1996 financial and operational review of the Company
(see below) through the four-year standard offer period. On July 27, 1999, the
Company and Enron Capital & Trade Resources Corp. (Enron) filed with the DPUC a
joint stipulation and settlement proposal to resolve simultaneously all of the
issues in the Company's standard offer rate proceeding. The proposal includes an
arrangement between the Company and Enron with respect to the generation
services needed by the Company to meet its standard offer obligations for the
four-year standard offer period, and an assumption by Enron of the Company's
long-term purchased power contract obligations. The stipulation and settlement
proposal also provides for the Company's standard offer rates at a fully-bundled
level that complies with the 10% reduction required by the Restructuring Act,
including the generation services component of these rates, the Company's
stranded costs for purposes of future recovery, the competitive transition
assessment, systems benefits charge, delivery (transmission and distribution)
charges, and conservation, load management and renewable energy charges. The
Company also requests that a purchased power adjustment clause authorized by the
Restructuring Act be put in place to adjust standard offer rates for limited
purposes, and that the Company's five-year Rate Plan, as modified and
supplemented by the stipulation and settlement proposal, be continued during the
four-year standard offer period. UI believes that the global stipulation and
settlement proposal (i) effectuates the Company's standard offer power
procurement in a manner that will assure the Company's customers reliable
standard offer generation services, (ii) provides a fair standard offer power
supply component that will enable retail generation suppliers to compete to
serve end-use customers, (iii) buys out the Company's power purchase agreements
on a satisfactory basis, (iv) resolves a potentially contentious adjudication of
the Company's recoverable stranded costs, and (v) clears the way for the Company
to focus on the energy delivery business, including the new complexities
associated with the onset of retail competition.
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
12
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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
June 30, 1999, the Company had $46 million in short-term borrowings outstanding
under this facility.
In addition, as of June 30, 1999, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $2.6 million
outstanding under a bank line of credit agreement.
13
<PAGE>
<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Three Months Ended Six Months Ended
(F) INCOME TAXES June 30, June 30,
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Income tax expense consists of: (000's) (000's) (000's) (000's)
Income tax provisions:
Current
Federal $63,457 $8,907 $75,794 $19,626
State 16,512 2,583 19,731 5,709
------------ ------------ ------------ ------------
Total current 79,969 11,490 95,525 25,335
------------ ------------ ------------ ------------
Deferred
Federal (51,490) (591) (51,644) (2,142)
State (14,185) (420) (14,763) (1,120)
------------ ------------ ------------ ------------
Total deferred (65,675) (1,011) (66,407) (3,262)
------------ ------------ ------------ ------------
Investment tax credits (191) (191) (381) (381)
------------ ------------ ------------ ------------
Total income tax expense $14,103 $10,288 $28,737 $21,692
============ ============ ============ ============
Income tax components charged as follows:
Operating expenses $15,851 $11,193 $31,376 $22,680
Other income and deductions - net (1,748) (905) (2,639) (988)
------------ ------------ ------------ ------------
Total income tax expense $14,103 $10,288 $28,737 $21,692
============ ============ ============ ============
The following table details the components of the deferred
income taxes:
Tax gain on sale of generation assets ($70,222) - ($70,222) -
Seabrook sale/leaseback transaction (2,082) (2,180) (4,164) (4,361)
Pension benefits 580 383 2,105 983
Accelerated depreciation 1,250 1,534 2,500 3,068
Tax depreciation on unrecoverable plant investment 1,186 1,212 2,374 2,424
Unit overhaul and replacement power costs 3,116 860 2,218 462
Conservation and load management (872) (2,006) (1,745) (4,013)
Postretirement benefits (265) (106) (698) (208)
Displaced worker protection costs 2,215 - 2,215 -
Other - net (581) (708) (990) (1,617)
------------ ------------ ------------ ------------
Deferred income taxes - net ($65,675) ($1,011) ($66,407) ($3,262)
============ ============ ============ ============
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
---- ---- ---- ----
(000's) (000's) (000's) (000's)
<S> <C> <C> <C> <C>
Operating Revenues
- ------------------
Retail $155,538 $149,222 $307,929 $295,767
Wholesale 5,676 8,446 19,269 23,261
Other 3,319 2,124 6,002 3,238
------------ ------------ ------------ -------------
Total Operating Revenues $164,533 $159,792 $333,200 $322,266
============ ============ ============ =============
Sales by Class(MWH's)
- --------------------
Retail
Residential 443,304 420,484 977,072 908,813
Commercial 591,114 566,975 1,144,912 1,131,764
Industrial 292,199 292,989 561,259 558,617
Other 11,850 11,848 24,049 24,021
------------ ------------ ------------ -------------
1,338,467 1,292,296 2,707,292 2,623,215
Wholesale 205,837 255,472 858,583 763,789
------------ ------------ ------------ -------------
Total Sales by Class 1,544,304 1,547,768 3,565,875 3,387,004
============ ============ ============ =============
Depreciation
- ------------
Plant in Service $11,916 $14,331 $26,571 $28,661
Amortization Conservation and
Load Management Costs 2,418 5,656 4,836 11,313
Nuclear Decommissioning 1,284 645 1,950 1,464
------------ ------------ ------------ -------------
$15,618 $20,632 $33,357 $41,438
============ ============ ============ =============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $5,898 $5,550 $11,752 $11,171
Local real estate and personal property 4,349 5,419 10,675 10,901
Payroll taxes 1,225 1,341 3,054 3,197
------------ ------------ ------------ -------------
11,472 12,310 25,481 25,269
Nonoperating and other accounts 158 145 292 293
------------ ------------ ------------ -------------
Total Other Taxes $11,630 $12,455 $25,773 $25,562
============ ============ ============ =============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $462 $340 $1,129 $660
Equity earnings from Connecticut Yankee 143 218 324 525
Earnings (Loss) from subsidiary companies (2,314) 177 (3,520) 372
Miscellaneous other income and (deductions) - net (671) (296) (782) (673)
------------ ------------ ------------ -------------
Total Other Income and (Deductions) - net ($2,380) $439 ($2,849) $884
============ ============ ============ =============
Other Interest Charges
- ----------------------
Notes Payable $359 $797 $1,643 $1,315
Other 461 635 1,033 961
------------ ------------ ------------ -------------
Total Other Interest Charges $820 $1,432 $2,676 $2,276
============ ============ ============ =============
</TABLE>
15
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company had a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases. 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 no longer has a need to acquire fossil
fuel. The Company and the financial institution agreed to terminate this
agreement as of May 31,1999.
(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.
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
16
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $10.2
million) and return on investment (approximately $4.4 million) at June 30, 1999,
is approximately $29.1 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
June 30, 1999, the Company's guarantee liability for this debt was approximately
$6.5 million.
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water quality, hazardous waste handling and
disposal, toxic substances, and electric and magnetic fields, the Company may
incur substantial capital expenditures for equipment modifications and
additions, monitoring equipment and recording devices, and it may incur
additional operating expenses. 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.
17
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 June 30, 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 $10.0 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 six months of 1999 was $1.2 million. UI's share of the fund at
June 30, 1999 was approximately $18.7 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $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 decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during the first six months of 1999 was $244,000. UI's share of the fund at June
30, 1999 was approximately $7.3 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 June 30, 1999, $123 million has been expended for
decommissioning. The projected remaining decommissioning cost is $353 million,
of which UI's share would be $34 million. The decommissioning trust fund for the
Connecticut Yankee Unit is also managed by NU. For the Company's 9.5% equity
ownership in Connecticut Yankee, decommissioning costs of $1.2 million were
funded by UI during the first six months of 1999, and UI's share of the fund at
June 30, 1999 was $21.6 million.
18
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(Q) RESTATEMENT OF FINANCIAL RESULTS
Subsequent to filing its Form 10-Q for the quarter ended June 30,1999, 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, as a result, 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 June 30, 1999 and December 31, 1998. As a result of
this review, net income and earnings per share originally reported for the
quarter and six month to date periods ended June 30, 1998 have been restated as
follows to reflect the restatement of a $2.9 million (after-tax) charge,
originally recorded in the second quarter of 1998 related to the recording of
additional reserves for uncollectible amounts related to American Payment
Systems, Inc. (APS) agent collections, to prior periods.
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, 1998 June 30, 1998
-------------------------------------
<S> <C> <C>
Income applicable to common stock, as originally reported $5,468 $14,379
Effect on net income of restatement, increase/(decrease) 2,882 2,882
------------- ---------------
Income applicable to common stock, as restated $8,350 $17,261
------------- ---------------
Earnings per share, as originally reported
- Basis $0.39 $1.03
- Diluted $0.39 $1.03
Earnings per share, as restated
- Basis $0.59 $1.23
- Diluted $0.59 $1.23
</TABLE>
In addition, as a result of this review, the Company has included in
restricted cash as of June 30, 1999 and December 31, 1998 amounts of $24.8
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 June 30,
1999 and December 31, 1998 amounts of $22.9 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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 Total
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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 during 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
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 1999, the Company had $26.4 million of cash and temporary cash
investments, including the Seabrook Unit 1 operating deposit, but excluding
restricted cash of American Payments Systems, Inc., a decrease of $75.0 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 14.3
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (253.5)
- Dividend payments (20.3)
Net cash provided by investing activities, excluding
investment in plant 5.5
Net cash provided from sale of generation assets 270.6
Cash invested in unregulated generation facility (75.1)
Cash invested in plant, including nuclear fuel (16.5)
----
Net Change in Cash (75.0)
Balance, June 30, 1999 $26.4
====
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year (1) $101.4 $ - $ - $46.0 $ 1.3
Internally Generated Funds less Dividends (2) 91.4 82.6 84.7 89.5 91.5
Net Proceeds from Sale of Fossil Generation Plants 200.4 - - - -
----- ------ ----- ----- ----
Subtotal 393.2 82.6 84.7 135.5 92.8
Less:
Utility Capital Expenditures (2) 30.7 34.5 23.4 18.9 23.3
Investments in subsidiaries (3) 110.0 15.0 15.0 15.0 15.0
----- ----- ----- ----- -----
Cash Available to pay Debt Maturities and Redemptions 252.5 33.1 46.3 101.6 54.5
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 125.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
----- ----- ----- ----- -----
External Financing Requirements (Surplus) (2) $22.1 $17.3 $(46.0) $(1.3) $46.0
==== ==== ====== ===== ====
</TABLE>
(1) Includes Seabrook Unit 1 operating deposit, but not restricted cash of
American Payment 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
<PAGE>
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.
(3) Investment for 1999 in United Bridgeport Energy $85.0 million, Allan
Electric Co., Inc. $8.0 million, Precision Power, Inc. $14.0 million and
United Resources, Inc. $4.0 million. Forward estimates are targets
necessary to meet earnings growth goals.
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
June 30, 1999, the Company had $46 million in 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. 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. and its subsidiaries, provide
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
owns and operates a 500-megawatt merchant wholesale electric generating facility
in Bridgeport, Connecticut.
RESULTS OF OPERATIONS
SECOND QUARTER OF 1999 VS. SECOND QUARTER OF 1998
- -------------------------------------------------
Earnings for the second quarter of 1999 were $13.9 million, or $.99 per
share (on both a basic and diluted basis), up $5.6 million, or $.39 per share,
from the second quarter of 1998. There were no one-time items recorded in the
second quarter of 1999 or 1998.
Retail revenues from operations increased by $6.3 million in the second
quarter of 1999 compared to the second quarter of 1998, as electric revenues
increased for the reasons detailed below. Retail fuel and energy
23
<PAGE>
expense increased by $6.3 million, primarily from higher purchased power prices
as a result of the Company's transition from a producer to a purchaser of its
customers' energy requirements. Overall, retail sales margin from operations
decreased by $0.7 million. The principal components of the change in retail
sales margin for the quarter, year-over-year, include:
$millions
--------------------------------------------------------------------- --------
Revenue from:
--------------------------------------------------------------------- --------
Estimate of "real" retail sales growth, up 3.0% 4.6
--------------------------------------------------------------------- --------
Estimate of weather effect on retail sales, up 1.4% 2.2
--------------------------------------------------------------------- --------
Sales decrease from Yale University cogeneration, (0.8)% (1.2)
--------------------------------------------------------------------- --------
Price mix of sales and other 0.7
--------------------------------------------------------------------- --------
Fuel and energy, margin effect:
--------------------------------------------------------------------- --------
Sales increase (1.1)
--------------------------------------------------------------------- --------
Nuclear fuel prices and refueling outage replacement costs (3.1)
--------------------------------------------------------------------- --------
Replacement power for fossil unit outage in 1998 1.7
--------------------------------------------------------------------- --------
Fossil fuel and purchased energy prices (3.7)
--------------------------------------------------------------------- --------
On April 16, 1999, the Company completed the sale of its operating
fossil-fueled generating plants and existing wholesale sales contracts that
was required by Connecticut's electric utility industry restructuring
legislation. As a result, the "geography" of the Company's costs on the
income statement and, hence, the year-over-year variances, have changed and
will change significantly beginning in the second quarter. This
particularly relates to wholesale revenue, retail purchased energy and
fossil fuel expenses, operation and maintenance expense, depreciation and
interest charges. For example, the increased purchased energy costs
included in the table above are more than offset by some of the decline in
miscellaneous operation and maintenance expense, due principally to the
sale of generating plants, shown in the table below, and to decreases in
depreciation and property taxes. See the "Looking Forward" section for more
details.
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $1.6 million in the second quarter of 1999 compared to the second quarter of
1998 from lower wholesale capacity sales resulting from the generation asset
sale. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $1.2 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.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $6.2 million in the second quarter of 1999 compared to the
second quarter of 1998. The principal components of these expense changes
include:
24
<PAGE>
$millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Connecticut Yankee (0.1)
- --------------------------------------------------------------------- ----------
Cogeneration and other purchases (0.2)
- --------------------------------------------------------------------- ----------
Other O&M expense:
- --------------------------------------------------------------------- ----------
Seabrook Unit 1 (refueling outage and accruals) 2.5
- --------------------------------------------------------------------- ----------
Millstone Unit 3 (refueling outage and accruals) 0.5
- --------------------------------------------------------------------- ----------
Other expenses at nuclear units (0.8)
- --------------------------------------------------------------------- ----------
Fossil generation unit overhaul and outage costs (4.3)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 0.6
- --------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale (4.4)
- --------------------------------------------------------------------- ----------
Depreciation expense decreased by $1.7 million in the second quarter of
1999 compared to the second quarter of 1998, due primarily to the generation
asset sale. Property tax expense decreased by $1.1 million due to this sale.
On December 31, 1996, the Connecticut Department of Public Utility Control
issued an order that implemented a five-year Rate Plan to reduce the Company's
retail prices and accelerate the recovery of certain "regulatory assets".
According to the Rate Plan, under which the Company is currently operating,
"accelerated" amortization of past utility investments is scheduled for every
year that the Rate Plan is in effect, contingent upon the Company earning a
10.5% return on utility common stock equity. All of the scheduled 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, or $3.3 million (before-tax, $2.1 million after-tax), was recorded in
each quarter. The Company is amortizing regulatory income tax assets for the
1999 amount, totaling $12.1 million (after-tax, about $20 million in pre-tax
equivalent), one-fourth of it, or $3.0 million (after-tax, about $5 million in
pre-tax equivalent), in each 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%, which the Company expects to
achieve from operations midway through the third quarter of 1999. There was no
"sharing" recorded against earnings from operations in the second quarters of
1998 or 1999. See the "Looking Forward" section for a more detailed explanation
of the "sharing" mechanism.
Unregulated subsidiary income, reported as "Other net" income, decreased by
about $2.9 million in the second quarter of 1999 compared to second quarter of
1998. American Payment Systems, Inc. (APS), earned about $280,000 (before-tax)
in the second quarter of 1999, almost one-third more than the $214,000
(before-tax) earned in the second quarter of 1998. The income of Precision
Power, Inc. (PPI) decreased $1.9 million (before-tax), reflecting increased
infrastructure costs as it prepares to expand its service offerings. The second
quarter PPI loss was in line with expectations outlined in the "Looking Forward"
section of the Company's 1998 Form 10-K. On May 11, 1999, the Company's
unregulated subsidiary, United Resources, Inc., increased its 4% passive
investment, through United Bridgeport Energy, Inc., in Bridgeport Energy LLC
(BE) to 33 1/3%. The second phase of BE's merchant wholesale electric generating
project went into commercial operation in July 1999, adding 180 megawatts of
generation capacity for a total of 520 megawatts. As a result of the shutdown of
the first phase generator to allow for construction of the second phase, the
Company experienced a loss of about $1 million from project operations and
financing in the second quarter of 1999. The Company's investment in the project
is expected to produce positive income in the second half of the year.
<TABLE>
<CAPTION>
2nd Q 99 2nd Q 99
vs. vs.
Summary of Unregulated Subsidiaries Pre-tax Income: $millions 2nd Q 98 1st Q 99
- --------------------------------------------------------------------- ---------- ---------
<S> <C> <C>
American Payment Systems, Inc. 0.1 - -
- --------------------------------------------------------------------- ---------- ---------
Precision Power, Inc. (1.9) (1.2)
- --------------------------------------------------------------------- ---------- ---------
United Bridgeport Energy (1.1) (1.1)
- --------------------------------------------------------------------- ---------- ---------
United Resources, Inc. Capital Projects - - 0.6
- --------------------------------------------------------------------- ---------- ---------
</TABLE>
25
<PAGE>
Interest charges continued on their downward trend, decreasing by $3.8
million for the regulated business in the second quarter of 1999 compared to the
second quarter of 1998, partly offset by an increase of $0.6 million in interest
charges for unregulated subsidiaries. Most of the reduction in utility interest
charges anticipated for 1999 compared to 1998 is coming after the generation
asset sale, which was completed on April 16, 1999. On April 16, 1999, the
Company used proceeds received from the sale to pay off $205 million of debt.
See the "Looking Forward" section for more details.
FIRST SIX MONTHS OF 1999 VS. FIRST SIX MONTHS OF 1998
- -----------------------------------------------------
Earnings for the first six months of 1999 were $23.8 million, or $1.69 per
share (on both a basic and diluted basis), up $6.5 million, or $.46 per share,
from the first six months of 1998. Excluding a one-time item recorded in the
first quarter of 1999, earnings from operations were $23.2 million, or $1.65 per
share, up $5.9 million, or $.42 per share.
There were no one-time items recorded in the first six months of 1998. The
one-time item reported in the first six months of 1999 was:
One-time Items EPS
- -------------------------------------------------------------------------------
1999 Quarter 1 Purchased power expense refund $ .12
"Sharing" due to one-time refund $(.08)
- -------------------------------------------------------------------------------
Retail revenues from operations increased by $13.1 million in the first six
months of 1999 compared to the first six months of 1998, as electric revenues
increased for the reasons detailed below. Retail revenues decreased by $1.0
million because of "sharing" 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 increased by $1.3 million, primarily from higher purchased
power prices as a result of the Company's transition from a producer to a
purchaser of its customers' energy requirements, and the need to purchase
additional energy to replace power lost from nuclear plant refueling outages.
Overall, retail sales margin 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% 8.8
- --------------------------------------------------------------------- ----------
Estimate of weather effect on retail sales, up 1.5% 4.6
- --------------------------------------------------------------------- ----------
Sales decrease from Yale University cogeneration, (1.3)% (3.7)
- --------------------------------------------------------------------- ----------
Price mix of sales and other 3.4
- --------------------------------------------------------------------- ----------
"Sharing" due to one-time gain (1.0)
- --------------------------------------------------------------------- ----------
Fuel and energy, margin effect:
- --------------------------------------------------------------------- ----------
Sales increase (1.8)
- --------------------------------------------------------------------- ----------
Nuclear fuel prices and outage replacement costs (4.0)
- --------------------------------------------------------------------- ----------
Replacement power for fossil unit outage in 1998 1.7
- --------------------------------------------------------------------- ----------
Fossil fuel price 2.8
- --------------------------------------------------------------------- ----------
On April 16, 1999, the Company completed the sale of its operating fossil
fueled generating plants and existing wholesale sales contracts that was
required by Connecticut's electric utility industry restructuring legislation.
As a result, the "geography" of the Company's costs on the income statement and,
hence, the year-over-year variances, have changed and will change significantly
beginning in the second quarter. This particularly relates to wholesale revenue,
retail purchased energy and fossil fuel expense, operations and maintenance
expense, depreciation and interest charges. See the "Looking Forward" section
for more details.
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $3.8 million in the first six months of 1999 compared to the first six months
of 1998 from lower wholesale capacity sales. Other operating
26
<PAGE>
revenues, which include NEPOOL related transmission revenues, increased by $2.8
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.
Operating expenses for operations, maintenance and purchased capacity
charges increased by $0.5 million in the first six months of 1999 compared to
the first six of 1998. The principal components of these expense changes
include:
$millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Connecticut Yankee (0.5)
- --------------------------------------------------------------------- ----------
Cogeneration and other purchases (see Note) 3.0
- --------------------------------------------------------------------- ----------
Other O&M expense:
- --------------------------------------------------------------------- ----------
Seabrook Unit 1 (refueling outage and accruals) 4.1
- --------------------------------------------------------------------- ----------
Millstone Unit 3 (refueling outage and accruals) 1.0
- --------------------------------------------------------------------- ----------
Other expenses at nuclear units (1.1)
- --------------------------------------------------------------------- ----------
Fossil generation unit overhaul and outage costs (6.3)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 1.5
- --------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale (1.2)
- --------------------------------------------------------------------- ----------
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 decreased by $1.5 million in the first six months of
1999 compared to the first six months of 1998, due primarily to the generation
asset sale.
On December 31, 1996, the Connecticut Department of Public Utility Control
issued an order that implemented a five-year Rate Plan to reduce the Company's
retail prices and accelerate the recovery of certain "regulatory assets."
According to the Rate Plan, under which the Company is currently operating,
"accelerated" amortization of past utility investments is scheduled for every
year that the Rate Plan is in effect, contingent upon the Company earning a
10.5% return on utility common stock equity. All of the scheduled 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, or $3.3 million (before-tax, $2.1 million after-tax), was recorded in
each quarter. The Company is amortizing regulatory income tax assets for the
1999 amount, totaling $12.1 million (after-tax, $20 million pre-tax equivalent),
one-fourth of it, or $3.0 million (after-tax, $5 million pre-tax equivalent), in
each 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%, which the Company expects to
achieve midway through the third quarter of 1999. 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 that quarter. There
was no "sharing" recorded against earnings from operations in the first six
months of 1998 or 1999.
"Other net" income decreased by about $3.7 million in the first six months
of 1999 compared to the first six months of 1998. The Company's largest
unregulated subsidiary, American Payment Systems, Inc. (APS), earned about $0.5
million from operations (before-tax) in the first six months of 1999, unchanged
from the first six months of 1998. The income of Precision Power, Inc. (PPI)
decreased $2.6 million (before-tax), reflecting increased infrastructure costs
as it continues to prepare to expand its service offerings. The six-month PPI
loss was in line with expectations outlined in the "Looking Forward" section of
the Company's 1998 Form 10-K. On May 11, 1999, the Company's unregulated
subsidiary, United Resources, Inc., increased its 4% passive investment, through
United Bridgeport Energy, Inc., in Bridgeport Energy LLC (BE) to 33 1/3%. The
second phase of BE's merchant wholesale electric generating project went into
commercial operation in July 1999, adding 180 megawatts of generation capacity
for a total of 520 megawatts. As a result of the shutdown of the first phase
generator to allow for construction of the second phase, the Company experienced
a loss of about $1 million from project operations
27
<PAGE>
and financing in the second quarter of 1999. The Company's investment in the
project is expected to produce positive income in the second half of the year.
1st 6 mos.
Summary of Unregulated Subsidiaries Pre-tax Income: $millions 99 vs. 98
- --------------------------------------------------------------------- ----------
American Payment Systems, Inc. - -
- --------------------------------------------------------------------- ----------
Precision Power, Inc. (2.6)
- --------------------------------------------------------------------- ----------
United Bridgeport Energy, Inc. (1.1)
- --------------------------------------------------------------------- ----------
United Resources, Inc. Capital Projects - -
- --------------------------------------------------------------------- ----------
Interest charges continued on their downward trend, decreasing by $4.0
million for the regulated business in the second quarter of 1999 compared to the
second quarter of 1998, partly offset by an increase of $0.6 million in interest
charges for unregulated subsidiaries. Most of the reduction in utility interest
charges anticipated for 1999 compared to 1998 is coming after the generation
asset sale, which was completed on April 16, 1999. On April 16, 1999, the
Company used proceeds received from the sale of plant to pay off $205 million of
debt. See the "Looking Forward" section 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
- -------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework to reduce the Company's retail prices and accelerate the recovery of
certain "regulatory assets," beginning with deferred conservation costs. The
Company operated under the terms of this Order in 1998. The Order's schedule of
price reductions and accelerated amortizations was based on a DPUC pro-forma
financial analysis that anticipated the Company would be able to implement such
changes and earn an allowed annual return on common stock equity invested in
utility assets of 11.5% over the period 1997 through 2001. The Order established
a set formula to share (see "Sharing Implementation" below) any utility income
that would produce a return above the 11.5% level: one-third to be applied to
customer price reductions, one-third to be applied to additional amortization of
regulatory assets, and one-third to be retained by shareowners. Utility income
is inclusive of earnings from operations and one-time items. The Order remains
in effect through 2001, although it does include a provision that it may be
modified as a result of the restructuring legislation passed by the Connecticut
legislature in 1998. Please see the "Looking Forward" section of the Company's
1998 Form 10-K for a more extensive description of the five-year Rate Plan.
Sharing Implementation
- ----------------------
The Company estimates that its return on regulated utility common stock
equity invested in utility assets of 11.5%, that is, the level that triggers
"sharing" of additional utility earnings, will require utility common stock
equity income (after-tax) of about $47 million for 1999. The Company will record
"sharing" customer price reductions and additional amortization of regulatory
assets once it begins earning above that level of income for 1999. Based on the
traditional quarterly earnings pattern, the Company realizes about half of its
pre-sharing utility earnings in the third quarter. The Company will not likely
ever exceed the sharing level of utility earnings before the third quarter of
any year that "sharing" is in effect. Assuming the sharing level of utility
earnings is exceeded in the third quarter of a particular year, then all
positive utility earnings recorded in the fourth quarter of that year will be
subject to sharing. This methodology will ensure stable, year-over-year earnings
comparisons based on actual utility financial results and will be unlikely to
result in any sharing reversals in the fourth quarter that are unrelated to
income in the fourth quarter.
28
<PAGE>
1999 Earnings
- -------------
1999 will be a year of transition to the January 1, 2000 effective date of
electric utility restructuring under legislation passed by the Connecticut
legislature in 1998. The Company has taken one major step toward restructuring
by proceeding with the sale of its fossil-fueled generation plants and existing
wholesale sales contracts (known as the Generation Asset Divestiture or GAD).
That sale was completed on April 16, 1999. All of the changes resulting from
GAD, described below, began occurring on 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 an average
of about $920 million in 1999. This would result in a similar percentage
reduction in the Company's utility common stock equity, except that the
Company's longstanding policy of debt paydown will partially offset it by
increasing the portion of rate base financed by equity. The portion of rate base
that is financed by equity is, then, 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 produced earnings of about $3.43
per share. Because of the reduced equity portion of rate base expected in 1999,
the allowed return is expected to produce utility earnings in the $3.35-$3.40
per share range.
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
has and 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 reduced total Company retail
kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The impact of the
Yale sales decline continued through the first six months of 1999, decreasing
the Company's sales compared to the first six months of 1998 by 1.3%, and will
continue somewhat in the third quarter of 1999, decreasing the Company's sales
by as much as 1.0% in that quarter. The overall impact of Yale cogeneration on
the Company's 1999 sales will be a reduction of about 0.5%-1.0% compared to
1998. Thus, it will require "real" growth of this much, for the year, to merely
offset the decrease due to Yale. "Real" growth in kilowatt-hour sales for the
first six months of 1999 compared to the first six months of 1998 was estimated
to be 2.9%, only partially offset by the 1.3% decrease due to Yale. Retail
kilowatt-hour sales growth of 1.0% produces a margin improvement of about $5.0
million on an annual basis, 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 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 as a result of NEPOOL
related transmission revenues by about $4.0 million, due to NEPOOL restructuring
changes; but this will 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 anticipate, at this time,
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any other significant revenue reductions in 1999 retail revenues 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 fuel
and 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 adequate resources to meet customer energy demands under a
short-term fixed price agreement until July 2000 (the price 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 decreases in decommissioning costs for the retired 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, $1 million
for Y2K costs, and $4 million due to NEPOOL transmission charges The latter will
have no net income effect, as the higher transmission expense will be covered 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, partly offset by the increase in the Company's passive financial
investment 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 wholesale electric generating plant
operated on a merchant basis by Duke Energy. The Company also expects to
generate substantial cash flow from operations after dividend and capital
spending, which will also be used to pay down debt.
Depreciation, excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to the GAD but also to the near
completion in 1998 of depreciation of previously capitalized conservation
program expenditures. A significant portion of the depreciation being recorded
for the GAD assets was not tax deductible and did not affect taxable income.
Therefore, a significant portion of the decrease in depreciation related to the
GAD will not increase income taxes, and will therefore supplement the $13
million depreciation decrease with an additional tax benefit, comparing 1999 to
1998, of about $2.5 million, or $.18 per share.
Accelerated amortization, pursuant to 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
experience 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 replacement power and increased accelerated
amortization costs in 1999. Such performance should allow utility earnings to
increase above an 11.5% return on utility common stock equity into the "sharing"
range of the Order. Currently, the Company expects its regulated business to
earn, for the entire year of 1999, about $15 million to $17 million (after-tax)
above the 11.5% return "sharing" threshold of about $47 million set by
regulators ($3.35-$3.40 per share). These earnings would
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result in about $9 million in customer price reductions, and $9 million in
offsets to stranded costs (pre-tax). Given current expectations, the retained
portion of shared earnings would add about $.35-$.40 per share, resulting in
earnings from operations for the regulated business of about $3.70-$3.80 for the
year. The Company expects to achieve the sharing threshold of earnings and to
begin sharing in the third quarter of the year, assuming normal weather
patterns. In that case, all utility business earnings in the fourth quarter can
be expected to be subject to sharing. 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 experience losses of $.10-$.15 per
share 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's Connecticut
operations will lose $.15 per share in 1999 if no substantial new contracts are
obtained. PPI recently acquired Allen Electric Co., Inc., a similar enterprise
in New Jersey, which is expected to be accretive slightly this year and is
expected to earn $.07-$.10 per share annually going forward. For 2000 and
beyond, the Company's passive financial investment in Bridgeport Energy is
expected to increase UI's annual earnings per share from operations by $.10 to
$.15.
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 $3.55 to $3.70 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 the "Looking
Forward" section in its entirety.
Year 2000
- ---------
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 350 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 were
completed and tested by June 30, 1999. This included a "destructive" mainframe
test performed at an independent site in Ponca City, Oklahoma.
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.
As of August 3, 1999 there were 36 business processes remaining to be
determined as Year 2000 ready. The summary of remaining business processes by
department and priority level is as follows:
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Priority 1 Priority 2 Priority 3 Priority 4 Total
Customer Services 1 20 8 1 30
Support Services 0 0 1 0 1
Controller's Department 2 0 0 0 2
--------------------------------------------------------
Total 3 20 9 1 33
========================================================
Priority one processes are those defined as affecting safety,
reliability, regulatory compliance or having a significant financial impact. The
priority one Customer Services process relates to the Customer Information
System that has been 100% tested but is under continuous change due to the
electric industry restructuring in Connecticut. The Controller's department has
two systems awaiting modification and testing, the accounts payable system and
the general ledger system. All priority one systems are to be complete by
December 31, 1999. Priority two implies that failure of this software or
hardware will present a disruption of service at current budget levels, but
work-arounds with negative implications for current service or cost levels are
available, if needed. Priority three implies that failure of this software or
hardware may present an inconvenience to occasional work requirements or an
impediment to achievement of higher service or lower cost levels, but
alternative work-arounds can be pursued if deemed necessary at some future date.
Priority four implies that failure of this software or hardware will produce a
nuisance or confusion but will not present any direct negative business
consequence. As of August 3, 1999, the Company had completed the assessment and
remediation phases of its program for these non-priority one business processes,
which are in various stages of the testing and approval process and are
projected to be completed by September 1, 1999.
UI has successfully complied with all regulatory requirements. Most
recently, UI successfully completed a Connecticut Department of Public Utility
Control audit along with eight other utilities in the state. The Company also
provides monthly reports to the North American Electric Reliability Council on
the Year compliance 2000 status of its transmission, distribution,
telecommunication and system control and data acquisition assets.
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. While failure to achieve Year 2000 compliance by any one of a number
of critical suppliers and data sharers could have some adverse effect on the
success of the Company's implementation program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications providers, the other participants in 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 successfully
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 been
and will be actively involved in contingency planning. While the Company's
knowledge and experience in electric system recovery planning and execution has
been demonstrated in the past, the Company recognizes the need for, and
importance of, Year 2000-specific contingency planning, because the complex
interaction of today's computing and communications systems precludes certainty
that all critical system remediation will be successful. 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
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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
should ultimately cost approximately $6.1 million for existing information
systems and embedded technology. A total of $5.2 million had been expended as of
June 30, 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.
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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
34
