SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDING SEPTEMBER 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
NONE
(Former name, former address and former fiscal year, if changed
since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of September 30, 1999, was 14,334,922.
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INDEX
Part I. FINANCIAL INFORMATION
Page
Number
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three and nine
months ended September 30, 1999 and 1998. 3
Consolidated Balance Sheet as of September 30, 1999
and December 31, 1998. 4
Consolidated Statement of Cash Flows for the three and
nine months ended September 30, 1999 and 1998. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 8
- Rate-Related Regulatory Proceedings 9
- 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
- Recovery of Stranded Costs 20
- Capital Expenditure Program 21
- Liquidity and Capital Resources 22
- Subsidiary Operations 23
- Results of Operations 23
- Looking Forward 29
Part II. OTHER INFORMATION
Item 1. Legal Proceedings. 33
Item 6. Exhibits and Reports on Form 8-K. 34
SIGNATURES 35
- 2 -
PART I: FINANCIAL INFORMATION
ITEM I: FINANCIAL STATEMENTS
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
OPERATING REVENUES (NOTE G) $199,071 $198,601 $532,271 $520,867
-------------- ------------ ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 51,433 39,701 123,815 113,654
Capacity purchased 8,428 9,124 26,168 24,324
Other 36,560 36,384 112,075 107,787
Maintenance 5,820 10,981 21,279 32,574
Depreciation 12,375 23,247 45,732 64,685
Amortization of cancelled nuclear project,
deferred return and regulatory tax asset 11,444 3,440 24,934 10,319
Income taxes (Note F) 25,910 24,448 57,286 47,128
Other taxes (Note G) 12,918 13,814 38,399 39,083
-------------- ------------ ------------ ------------
Total 164,888 161,139 449,688 439,554
-------------- ------------ ------------ ------------
OPERATING INCOME 34,183 37,462 82,583 81,313
-------------- ------------ ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 347 (35) 614 35
Other-net (Note G) 307 1,798 (2,542) 2,682
Non-operating income taxes 1,155 701 3,794 1,689
-------------- ------------ ------------ ------------
Total 1,809 2,464 1,866 4,406
-------------- ------------ ------------ ------------
INCOME BEFORE INTEREST CHARGES 35,992 39,926 84,449 85,719
-------------- ------------ ------------ ------------
INTEREST CHARGES
Interest on long-term debt 9,829 11,759 32,219 38,161
Interest on Seabrook obligation bonds owned by the company (1,711) (1,817) (5,133) (5,453)
Dividend requirement of mandatorily redeemable securities 1,203 1,203 3,609 3,609
Other interest (Note G) 1,407 2,169 4,083 4,445
Allowance for borrowed funds used during construction (327) (241) (1,098) (505)
-------------- ------------ ------------ ------------
10,401 13,073 33,680 40,257
Amortization of debt expense and redemption premiums 594 617 1,885 1,885
-------------- ------------ ------------ ------------
Net Interest Charges 10,995 13,690 35,565 42,142
-------------- ------------ ------------ ------------
NET INCOME 24,997 26,236 48,884 43,577
Premium (Discount) on preferred stock redemptions - - 53 (21)
Dividends on preferred stock - 50 66 151
-------------- ------------ ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $24,997 $26,186 $48,765 $43,447
============== ============ ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,056 14,028 14,049 14,012
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,058 14,032 14,051 14,018
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $1.78 $1.87 $3.47 $3.10
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72 $2.16 $2.16
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
September 30, December 31,
1999 1998*
---- ----
(Unaudited)
Utility Plant at Original Cost
In service $1,514,999 $1,886,930
Less, accumulated provision for depreciation 528,087 714,375
---------------- ----------------
$986,912 1,172,555
Construction work in progress 34,941 33,695
Nuclear fuel 22,036 20,174
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Net Utility Plant $1,043,889 1,226,424
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Other Property and Investments
Investment in generation facility 88,684 -
Nuclear decommissioning trust fund assets 26,854 23,045
Other 17,602 14,828
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133,140 37,873
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Current Assets
Unrestricted cash and temporary cash investments 18,005 97,689
Restricted cash 35,999 26,812
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 71,914 54,178
Other, less allowance for doubtful accounts of $796 and $631 58,147 64,240
Accrued utility revenues 25,401 21,079
Fuel, materials and supplies, at average cost 7,887 33,613
Prepayments 5,647 7,424
Other 4,341 154
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Total 227,341 305,189
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Deferred Charges
Unamortized debt issuance expenses 8,422 9,421
Other 3,574 1,664
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Total 11,996 11,085
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Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 190,213 264,811
Connecticut Yankee 38,122 42,633
Deferred return - Seabrook Unit 1 3,147 12,586
Unamortized redemption costs 22,589 23,468
Unamortized cancelled nuclear projects 9,073 10,952
Uranium enrichment decommissioning cost 1,074 1,177
Other 20,821 4,962
---------------- ----------------
Total 285,039 360,589
---------------- ----------------
1,701,405 $1,941,160
================ ================
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
September 30, December 31,
1999 1998*
---- ----
(Unaudited)
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,187 2,046
Capital stock expense (2,171) (2,182)
Unearned employee stock ownership plan equity (9,497) (10,210)
Retained earnings 182,255 163,847
--------------- ---------------
464,780 445,507
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 605,623 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
--------------- ---------------
Net long-term debt 518,210 664,510
--------------- ---------------
Total 1,032,990 1,164,316
--------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 27,679 32,711
Pensions accrued (Note H) 24,483 31,097
Nuclear decommissioning obligation 26,854 23,045
Obligations under capital leases 16,227 16,506
Other 5,438 6,622
--------------- ---------------
Total 100,681 109,981
--------------- ---------------
Current Liabilities
Current portion of long-term debt 6,806 66,202
Notes payable 43,134 86,892
Accounts payable 34,080 48,749
Accounts payable - APS utility customers 68,337 54,515
Dividends payable 10,120 10,155
Taxes accrued 38,348 9,015
Interest accrued 14,154 10,203
Obligations under capital leases 368 348
Other accrued liabilities 33,395 39,845
--------------- ---------------
Total 248,742 325,924
--------------- ---------------
Customers' Advances for Construction 1,867 1,867
--------------- ---------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,053 15,623
Deferred gain on sale of property 15,745 4
Other 17,489 2,061
--------------- ---------------
Total 48,287 17,688
--------------- ---------------
Deferred Income Taxes (future tax liabilities owed 268,838 321,384
to taxing authorities)
Commitments and Contingencies (Note L)
--------------- ---------------
$1,701,405 $1,941,160
=============== ===============
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $24,997 $26,236 $48,884 $43,577
------------- ------------ ------------ ------------
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 21,200 24,419 62,918 68,167
Deferred income taxes 3,023 271 6,838 (2,991)
Deferred income taxes - generation asset sale - - (70,222) -
Deferred investment tax credits - net (190) (190) (571) (571)
Amortization of nuclear fuel 1,978 1,641 6,658 4,138
Allowance for funds used during construction (674) (206) (1,712) (540)
Amortization of deferred return 3,146 3,146 9,439 9,439
Changes in:
Accounts receivable - net (22,178) (11,973) (11,643) (22,542)
Fuel, materials and supplies (42) 1,680 170 (9,882)
Prepayments (1,985) (21,711) 1,777 (27,792)
Accounts payable 16,015 (18,168) (847) (20,859)
Interest accrued (2,462) (3,853) 3,951 4,064
Taxes accrued 6,967 14,269 11,777 16,189
Taxes accrued - generation asset sale (17,555) - 17,556 -
Other assets and liabilities 15,933 1,693 (20,800) 2,888
------------- ------------ ------------ ------------
Total Adjustments 23,176 (8,982) 15,289 19,708
------------- ------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 48,173 17,254 64,173 63,285
------------- ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 284 308 853 4,618
Long-term debt - - - 99,780
Notes payable (5,550) (5,630) (43,758) 75,444
Securities redeemed and retired:
Preferred stock - - (4,299) (52)
Long-term debt - - (211,202) (213,976)
Discount (Premium) on preferred stock redemption - - (53) 21
Expense of issue - - - (800)
Lease obligations (88) (86) (259) (252)
Dividends
Preferred stock - (50) (116) (152)
Common stock (10,114) (10,095) (30,329) (30,185)
------------- ------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (15,468) (15,553) (289,163) (65,554)
------------- ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in unregulated businesses (20,156) - (95,248) -
Net cash received from sale of generation assets - - 270,590 -
Plant expenditures, including nuclear fuel (9,770) (9,047) (26,296) (19,616)
Investment in debt securities - - 5,447 8,528
------------- ------------ ------------ ------------
NET CASH (USED IN) PROVIDED BY ACTIVITIES (29,926) (9,047) 154,493 (11,088)
------------- ------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 2,779 (7,346) (70,497) (13,357)
BALANCE AT BEGINNING OF PERIOD 51,225 47,054 124,501 53,065
------------- ------------ ------------ ------------
BALANCE AT END OF PERIOD 54,004 39,708 54,004 39,708
LESS: RESTRICTED CASH 35,999 30,135 35,999 30,135
------------- ------------ ------------ ------------
BALANCE: UNRESTRICTED CASH $18,005 $9,573 $18,005 $9,573
============= ============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $9,919 $13,895 $24,402 $33,345
============= ============ ============ ============
Income taxes $33,900 $12,100 $91,850 $35,150
============= ============ ============ ============
Note: Cash Flows from Operating Activities for the nine months ended September
30, 1999 were reduced by the current income tax effects of the generation
asset sale in the amount of $52,666.
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
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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 and Form 10-K/A-2 for the year ended December 31,
1998. Such notes are supplemented as follows:
(A) STATEMENT OF ACCOUNTING POLICIES
REGULATORY ACCOUNTING
Generally accepted accounting principles for regulated entities allow the
Company to give accounting recognition to the actions of regulatory authorities
in accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". In
accordance with SFAS No. 71, the Company has deferred recognition of costs (a
regulatory asset) or has recognized obligations (a regulatory liability) if it
is probable that such costs will be recovered or obligations relieved in the
future through the ratemaking process. In addition to the Regulatory Assets and
Liabilities separately identified on the Consolidated Balance Sheet, there are
other regulatory assets and liabilities such as conservation and load management
costs and certain deferred tax liabilities. The Company also has obligations
under long-term power contracts, the recovery of which is subject to regulation.
The effects of competition 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 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 the portion of the business that continues to meet the criteria
for application of SFAS No. 71. See Note (C), "Rate-Related Regulatory
Proceedings" for a discussion of the nature, amount and timing of recovery of
the Company's stranded costs associated with the generation portion of its
assets and operations, as well as a discussion of the regulatory decisions that
provide for such recovery. Based on these regulatory decisions, the sale of the
Company's fossil-generation assets in the second quarter of 1999, and the
planned divestiture of its nuclear generation ownership interests by the end of
2003, the Company anticipates that on January 1, 2000 it will cease applying
SFAS No. 71 to the generation portion of its assets and operations. However,
based on the recovery mechanism that allows recovery of all of its stranded
costs through its standard offer rates, the Company does not anticipate any
write-offs in connection with this event. The Company expects to continue to
meet the criteria for application of SFAS No. 71 for the remaining portion of
its assets and operations for the foreseeable future. If a change in accounting
were to occur to the non-generation portion of the Company's operations, 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.
- 7 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The weighted average AFUDC rate applied in the first nine months of 1999
and 1998 was 7.67% and 7.33%, respectively, on a before-tax basis.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $3,000,000 and $1,900,000 in the first nine
months of 1999 and 1998, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At September 30, 1999, the Company's
shares of the trust fund balances, which included accumulated earnings on the
funds, were $19.4 million and $7.4 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 nine months ended September 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 September 30, 1999, of which 279,404 shares were unallocated
shares held by the Company's Employee Stock Ownership Plan ("ESOP") and not
recognized as outstanding for accounting purposes.
In 1990, the Company's Board of Directors and the shareowners approved a
stock option plan for officers and key employees of the Company. The plan
provides for the awarding of options to purchase up to 750,000 shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date of the grant. Options to purchase 3,500 shares of
stock at an exercise price of $30 per share, 7,800 shares of stock at an
exercise price of $39.5625 per share, and 5,000 shares of stock at an exercise
price of $42.375 per share have been granted by the Board of Directors and
remained outstanding at September 30, 1999. No options were exercised during the
first nine 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 September 30, 1999. No options to
purchase shares of the Company's common stock can be exercised without the
approval of the DPUC; and, as of September 30, 1999, the Company had not
requested approval by the DPUC.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of September 30, 1999, 279,404 shares, with a fair market value of
$13.5 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
$124.1 million were free from such limitations at September 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 is payable semi-annually on
August 1 and February 1. 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 is
payable semi-annually on August 1 and February 1.
On March 8, 1999, the Company prepaid and terminated $20 million of the
remaining $70 million outstanding debt under its $150 million Term Loan
Agreement dated August 29, 1995. On April 16, 1999, the Company prepaid and
terminated the entire remaining $50 million outstanding debt under said $150
million Term Loan Agreement, and the entire $75 million outstanding debt under
its Term Loan Agreement dated October 25, 1996.
(C) RATE-RELATED 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.
- 9 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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 and the systems benefits charge from all
Distribution Company customers, except customers taking service under special
contracts pre-dating the Restructuring Act. Also beginning in 2000, a
Distribution Company must collect the conservation and load management program
charge and the renewable energy charge from all Distribution Company customers,
without exception. 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.
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 $15.7 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
- 10 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Company proposed to satisfy, on a functional basis, the Restructuring Act's
requirement that nuclear generating assets be separated from its transmission
and distribution assets. This would be accomplished by transferring the nuclear
generating assets into a separate new division of the Company, using divisional
financial statements and accounting to segregate all revenues, expenses, assets
and liabilities associated with nuclear ownership interests. In a 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. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting this DPUC decision in an appeal taken to the Superior
Court.
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 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
- 11 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
In its decision, dated October 1, 1999, on the Company's standard offer rates,
the DPUC approved elements of the stipulation and settlement proposal, subject
to specified changes. On October 15, 1999, the Company filed its standard offer
rates in compliance with the DPUC's decision, and the Company and Enron
concurrently filed a revised stipulation and settlement proposal. These filings
are being reviewed by the DPUC.
FIVE-YEAR RATE PLAN
- -------------------
On December 31, 1996, the DPUC completed a financial and operational
review of the Company and ordered a five-year incentive regulation plan for the
years 1997 through 2001 (the Rate Plan). The DPUC did not change the existing
base rates charged to retail customers, but did provide for retail customer
price reductions of about 5% compared to 1996 and phased-in over 1997-2001; 3%
in 1997 compared to 1996, an additional 1% in 2000 and another 1% in 2001
compared to 1996. The price reductions are accomplished primarily through
reductions of conservation adjustment mechanism revenues, through a surcredit in
each of the five plan years, and through acceptance of the Company's proposal to
modify the operation of the fossil fuel clause mechanism. The Rate Plan also
increased amortization of the Company's conservation and load management program
investments during 1997-1998, and accelerated the amortization recovery of
unspecified assets during 1999-2001 if the Company's return on utility common
stock equity exceeds 10.5%, on an annual basis, after recording the
amortization. The specified accelerated amortizations for 1999-2001, on an
after-tax basis, are $12.1 million, $29.7 million and $32.8 million,
respectively. The Company's authorized return on utility common stock equity
under the Rate Plan is 11.5%, on an annual basis. Earnings above 11.5% are to be
"shared" by utilizing one-third for retail customer price reductions, one-third
for increased amortization of regulatory assets, and one-third retained as
earnings.
The Rate Plan had significant impacts on the Company's 1998 financial
results. Retail customer prices actually decreased by approximately 4.8% in 1998
compared to 1996. Also in 1998, all of the increased amortization of the
Company's conservation and load management program investments prescribed by the
Rate Plan were recorded. No "shared" earnings were recorded in 1998 because
one-time items reduced the Company's return on utility common stock equity to
less than 11.5%, although earnings from operations, excluding one-time items,
would have been above 11.5% and "sharing" would have occurred based on earnings
from operations alone. See "Results of Operations" for a more complete
discussion of these results.
The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act described above, the Rate
Plan may be reopened and modified. The
- 12 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
DPUC's October 1, 1999 decision in the Company's standard offer rates proceeding
implements an additional price reduction in 2000 to achieve the minimum
aggregate 10% price reduction compared to 1996 required by the Restructuring Act
and reduces the accelerated amortizations scheduled in the Rate Plan. The
Company has filed its standard offer rates in compliance with the DPUC's
decision; and the rates are being reviewed by the DPUC. The Company is unable to
predict, at this time, in what other respects the Rate Plan may be modified in
the future 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 Company expects that this agreement
will be extended to December 2000. The borrowing limit of this facility is $75
million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
September 30, 1999, the Company had $43 million in short-term borrowings
outstanding under this facility.
In addition, as of September 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 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Three Months Ended Nine Months Ended
(F) INCOME TAXES September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
Income tax expense consists of: (000's) (000's) (000's) (000's)
Income tax provisions:
Current
Federal $17,403 $18,331 $93,197 $37,957
State 4,519 5,335 24,250 11,044
------------ ------------ ------------ ------------
Total current 21,922 23,666 117,447 49,001
------------ ------------ ------------ ------------
Deferred
Federal 2,802 184 (48,842) (1,958)
State 221 87 (14,542) (1,033)
------------ ------------ ------------ ------------
Total deferred 3,023 271 (63,384) (2,991)
------------ ------------ ------------ ------------
Investment tax credits (190) (190) (571) (571)
------------ ------------ ------------ ------------
Total income tax expense $24,755 $23,747 $53,492 $45,439
============ ============ ============ ============
Income tax components charged as follows:
Operating expenses $25,910 $24,448 $57,286 $47,128
Other income and deductions - net (1,155) (701) (3,794) (1,689)
------------ ------------ ------------ ------------
Total income tax expense $24,755 $23,747 $53,492 $45,439
============ ============ ============ ============
The following table details the components of the
deferred income taxes:
Tax gain on sale of generation assets $ - $ - $(70,222) $ -
Seabrook sale/leaseback transaction 686 808 (3,478) (3,553)
Pension benefits 579 1,020 2,684 2,003
Accelerated depreciation 1,251 1,535 3,751 4,603
Tax depreciation on unrecoverable plant investment 1,186 1,212 3,560 3,636
Unit overhaul and replacement power costs (240) (361) 1,978 101
Conservation and load management (410) (2,922) (2,155) (6,935)
Postretirement benefits (265) (94) (963) (302)
Displaced worker protection costs 43 - 2,258 -
Other - net 193 (927) (797) (2,544)
------------ ------------ ------------ ------------
Deferred income taxes - net $3,023 $271 ($63,384) ($2,991)
============ ============ ============ ============
- 14 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
(000's) (000's) (000's) (000's)
Operating Revenues
- ------------------
Retail $191,056 $185,982 $498,985 $481,749
Wholesale 3,669 9,236 22,938 32,497
Other 4,346 3,383 10,348 6,621
------------ ------------ ------------- -------------
Total Operating Revenues $199,071 $198,601 $532,271 $520,867
============ ============ ============= =============
Sales by Class(MWH's)
- --------------------
Retail
Residential 604,600 553,475 1,581,672 1,462,288
Commercial 663,457 639,637 1,808,369 1,771,401
Industrial 323,782 312,088 885,041 870,705
Other 11,803 11,874 35,852 35,895
------------ ------------ ------------- -------------
1,603,642 1,517,074 4,310,934 4,140,289
Wholesale 62,040 279,868 920,623 1,043,657
------------ ------------ ------------- -------------
Total Sales by Class 1,665,682 1,796,942 5,231,557 5,183,946
============ ============ ============= =============
Depreciation
- ------------
Plant in Service $11,347 $14,330 $37,918 $42,991
Amortization Conservation and
Load Management Costs (50) 8,272 4,786 19,585
Nuclear Decommissioning 1,078 645 3,028 2,109
------------ ------------- ------------- -------------
$12,375 $23,247 $45,732 $64,685
============ ============ ============= =============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $7,704 $7,154 $19,456 $18,325
Local real estate and personal property 4,062 5,316 14,737 16,217
Payroll taxes 1,152 1,338 4,206 4,535
Other - 6 - 6
------------ ------------ ------------- -------------
12,918 13,814 38,399 39,083
Nonoperating and other accounts 140 105 432 398
------------ ------------ ------------- -------------
Total Other Taxes $13,058 $13,919 $38,831 $39,481
============ ============ ============= =============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $294 $2,134 $1,423 $2,794
Equity earnings from Connecticut Yankee 197 168 521 693
Earnings (Loss) from subsidiary companies 919 (85) (2,601) 287
Miscellaneous other income and (deductions) - net (1,103) (419) (1,885) (1,092)
------------ ------------ ------------- -------------
Total Other Income and (Deductions) - net $307 $1,798 ($2,542) $2,682
============ ============ ============= =============
Other Interest Charges
- ----------------------
Notes Payable $698 $527 $2,341 $1,842
Other 709 1,642 1,742 2,603
------------ ------------ ------------- -------------
Total Other Interest Charges $1,407 $2,169 $4,083 $4,445
============ ============ ============= =============
- 15 -
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 $262.5 million, excluding AFUDC, for 1999 through 2003. See the "Capital
Expenditure Program" section for details.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the two operating nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $17.8 million per incident.
However, any assessment would be limited to $2.1 million per incident per year.
The 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 -
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 $10.4
million) and return on investment (approximately $4.2 million) at September 30,
1999, is approximately $27.7 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
September 30, 1999, the Company's guarantee liability for this debt was
approximately $6.3 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 -
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 September 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-Related Regulatory Proceedings", 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 nine months of 1999 was $2.5 million. UI's share of the fund at
September 30, 1999 was approximately $19.4 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $560 million (in 1999 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during the first nine months of 1999 was $0.5 million. UI's share of the fund at
September 30, 1999 was approximately $7.4 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 September 30, 1999, $148 million has been expended
for decommissioning. The projected remaining decommissioning cost is $328
million, of which UI's share would be $31 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 $1.8
million were funded by UI during the first nine months of 1999, and UI's share
of the fund at September 30, 1999 was $18.7 million.
- 18 -
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 its independent accountants and the 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 nine-month period ended September 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.
NINE MONTHS ENDED
SEPTEMBER 30, 1998
------------------
(thousands, except for
earnings per share)
Income applicable to common stock, as originally reported $40,565
Effect on net income of restatement, increase/(decrease) 2,882
------
Income applicable to common stock, as restated $43,447
------
Earnings per share, as originally reported
- - Basic $2.90
- - Diluted $2.89
Earnings per share, as restated
- - Basic $3.10
- - Diluted $3.10
In addition, as a result of this review, the Company has included in
restricted cash $23.1 million as of December 31, 1998 representing collections
by 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 $26.8 million as of December 31, 1998
representing amounts collected by APS agents on that day 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 customers. The Company had previously presented its consolidated
balance sheet net of these accounts receivable and accounts payable amounts.
- 19 -
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. See Note (C), "Rate-Related Regulatory
Proceedings", for a discussion of the Restructuring Act and its impact on the
Company.
The Company's financial condition will continue to be dependent on the
level of its retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Total operation and maintenance expense, excluding
one-time items and cogeneration capacity purchases, declined by 1.1%, on
average, during the past 5 years. The Company is experiencing 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 Restructuring Act 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 the portion of the business that
continues to meet the criteria for the application of SFAS No. 71. See "Recovery
of Stranded Costs" below for a discussion of the nature, amount and timing of
recovery of stranded costs associated with the generation portion of the
Company's assets and operations. The Company expects to continue to meet the
criteria for application of SFAS No. 71 for the remaining portion of its assets
and operations for the foreseeable future. If a change in accounting were to
occur to the non-generation portion of the Company's operations, 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.
RECOVERY OF STRANDED COSTS
Under the Restructuring Act, the business of generating and supplying
electricity directly to customers will be separated from the business of
delivering electricity to consumers. The latter business, also known as the
transmission and distribution business, will remain with the incumbent
franchised utility companies (including the Company), which will continue to be
regulated by the Department of Public Utility Control (DPUC) as Distribution
Companies. One of the major components of the Restructuring Act is the
collection by a Distribution Company of a competitive transition assessment for
the recovery of "stranded costs" that have been reasonably incurred by, or will
be incurred by, the Distribution Company to meet its public service obligations
as a regulated electric company, and that will not otherwise be recoverable in a
competitive generation and supply market. On March 24, 1999, the Company applied
to the DPUC for a determination of the amount and the timing of the recovery of
the Company's stranded costs as prescribed by 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
- 20 -
purchase power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), $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 fully
recoverable, subject to true-ups on an ongoing basis.
In March 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be beginning January 1, 2000 and, as part
of this proceeding, the Company proposed an approach for the recovery, in its
rates, of its stranded costs. In a decision dated October 1, 1999, the DPUC
approved the full recovery of all of the stranded costs described above through
a competitive transition assessment charge as a component of the Company's
rates. Based on the rates approved in the decision, it is currently anticipated
that all stranded cost recovery should be completed in approximately 12 years.
Based on the decisions in the regulatory proceedings described above, the
sale of the Company's fossil-generation assets in the second quarter of 1999,
and the planned divestiture of its nuclear generation ownership interests by the
end of 2003, the Company anticipates that on January 1, 2000 it will cease
applying SFAS No. 71 to the generation portion of its assets and operations.
However, based on the favorable DPUC decisions that allow full recovery, through
the Company's rates, of all historically incurred stranded costs, the Company
does not anticipate any write-offs in connection with this event.
CAPITAL EXPENDITURE PROGRAM
The Company's 1999-2003 capital expenditure program, excluding allowance
for funds used during construction and its effect on certain capital-related
items, is presently budgeted as follows:
1999 2000 2001 2002 2003 Total
---- ---- ---- ---- ---- -----
(000's)
Nuclear Generation $ 4,003 $ 3,113 $ 3,591 $ - $ - $ 10,707
Distribution and Transmission 24,268 39,387 20,229 12,279 11,343 107,506
Other 4,643 - - - - 4,643
------ ------ ------ ------ ------ -------
Subtotal 32,914 42,500 23,820 12,279 11,343 122,856
Nuclear Fuel 2,235 8,162 7,086 2,744 7,267 27,494
------ ------ ------ ------ ------ -------
Total Utility Expenditures 35,149 50,662 30,906 15,023 18,610 150,350
Total Non-Regulated Businesses 99,949 3,200 3,000 3,000 3,000 112,149
------ ------ ------ ------ ------ -------
Total $135,098 $53,862 $33,906 $18,023 $21,610 $262,499
======== ======= ======= ======= ======= ========
Note: 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.
- 21 -
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 1999, the Company had $20.3 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 $81.1 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 53.6
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (258.7)
- Dividend payments (30.5)
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 (95.3)
Cash invested in plant, including nuclear fuel (26.3)
-----
Net Change in Cash (81.1)
Balance, September 30, 1999 $20.3
====
The Company's capital requirements are presently projected as follows:
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year (1) $ 97.7 $ - $ - $ - $ -
Internally Generated Funds less Dividends (2) 115.6 62.4 70.9 57.5 66.4
Net Proceeds from Sale of Fossil Generation Plants 200.4 - - - -
----- ----- ----- ----- -----
Subtotal 413.7 62.4 70.9 57.5 66.4
Less:
Utility Capital Expenditures (2) 35.1 50.7 30.9 15.0 18.6
Investments in subsidiaries (3) 99.9 3.2 3.0 3.0 3.0
----- ----- ---- ----- -----
Cash Available to pay Debt Maturities and Redemptions 278.7 8.5 37.0 39.5 44.8
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) $(4.1) $41.9 $(36.7) $60.8 $55.7
==== ==== ====== ==== ====
(1) Excludes $3.7 million Seabrook Unit 1 operating deposit and 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 -
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 $87.0 million, Allan
Electric Co., Inc. $8.3 million, Precision Power, Inc. $1.5 million and
United Resources, Inc. $3.1 million.
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 Company expects that this agreement
will be extended to December 2000. The borrowing limit of this facility is $75
million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
September 30, 1999, the Company had $43 million in short-term borrowings
outstanding under this facility.
In addition, as of September 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.
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
THIRD QUARTER OF 1999 VS. THIRD QUARTER OF 1998
Earnings for the third quarter of 1999 were $25.0 million, or $1.78 per
share (on both a basic and diluted basis), down $1.2 million, or $.09 per share,
from the third quarter of 1998. Excluding the one-time item recorded in the
- 23 -
third quarter of 1998, earnings from operations were virtually unchanged. There
were no one-time items recorded in the third quarter of 1999.
The one-time item recorded in the third quarter of 1998 was:
One-time Item $millions EPS
- --------------------------------------------------------------------------------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .14
"Sharing" due to one-time item recorded
in the third quarter $(.05)
"Sharing" revenues (before-tax) $(0.6)
"Sharing" amortization (before-tax) 0.6
- --------------------------------------------------------------------------------
Utility Earnings from Operations
- --------------------------------
Retail revenues from operations increased by $5.1 million in the third
quarter of 1999 compared to the third quarter of 1998, as electric revenues
increased for the reasons detailed below. Retail fuel and energy expense
increased by $13.0 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 $9.0 million. The principal components of the change in retail
sales margin for the quarter, year-over-year, include:
$ millions
- ------------------------------------------------------------------- ------------
Revenue from:
- ------------------------------------------------------------------- ------------
Sharing: year-to-date for 1999 (see note A) (6.3)
- ------------------------------------------------------------------- ------------
Estimate of "real" retail sales growth, up 4.6% 8.7
- ------------------------------------------------------------------- ------------
Estimate of weather effect on retail sales, up 1.3% 2.4
- ------------------------------------------------------------------- ------------
Sales decrease from Yale University cogeneration, (0.2)% (0.3)
- ------------------------------------------------------------------- ------------
Revenue based taxes (0.5)
- ------------------------------------------------------------------- ------------
Fuel and energy, margin effect:
- ------------------------------------------------------------------- ------------
Sales increase (1.9)
- ------------------------------------------------------------------- ------------
Nuclear fuel prices and outage replacement power costs 1.3
- ------------------------------------------------------------------- ------------
Purchased energy prices (see note B) (12.4)
- ------------------------------------------------------------------- ------------
A. The Company's return on regulated utility common stock equity for the
first nine months of 1999 exceeded the 11.5% "sharing" trigger by
about $25 million of pre-tax income. As a result, a book revenue
"sharing" reduction of $8.7 million, including a gross earnings tax
component, was recorded in the third quarter of 1999, approximately
$6.3 million more than the $2.4 million book revenue "sharing"
reduction recorded from operations in the third quarter of 1998.
B. 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 significantly beginning in the second quarter.
This particularly relates to wholesale revenue, retail purchased
energy and fossil fuel expenses, operation and maintenance expense,
depreciation, interest charges and property taxes. 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.
- 24 -
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $4.3 million in the third quarter of 1999 compared to the third quarter of
1998 from lower wholesale sales resulting from the generation asset sale. Other
operating revenues, which include NEPOOL related transmission revenues,
increased by $1.0 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 third quarter of 1999 compared to the
third quarter of 1998. The principal components of these expense changes
include:
$ millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Connecticut Yankee (0.2)
- --------------------------------------------------------------------- ----------
Cogeneration and other purchases (0.5)
- --------------------------------------------------------------------- ----------
Other O&M expense:
- --------------------------------------------------------------------- ----------
Seabrook Unit 1 0.5
- --------------------------------------------------------------------- ----------
Millstone Unit 3 0.6
- --------------------------------------------------------------------- ----------
Fossil generation unit overhaul and outage costs (10.2)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 1.1
- --------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale 1.2
- --------------------------------------------------------------------- ----------
Depreciation expense decreased by $5.0 million in the third quarter of 1999
compared to the third quarter of 1998, due primarily to the generation asset
sale. Property tax expense decreased by $1.3 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 also incurred additional accelerated amortization expense of
$5.0 million (after-tax, about $8.4 million in pre-tax equivalent) in the third
quarter of 1999 as a result of the "sharing" mechanism in the Rate Plan, as the
Company achieved a return on utility common stock equity above 11.5% midway
through the quarter. "Sharing" amortization recorded against earnings from
operations in the third quarter of 1998 was $2.1 million (before-tax, $1.3
million after-tax). See the "Looking Forward" section for a more detailed
explanation of the "sharing" mechanism.
Interest charges continued on their downward trend, decreasing by $4.0
million for the regulated business in the third quarter of 1999 compared to the
third quarter of 1998, partly offset by an increase of $1.4 million in interest
charges for unregulated subsidiaries. Most of the reduction in utility interest
charges anticipated for 1999 compared to 1998 began accruing 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.
Unregulated Business Earnings from Operations
- ---------------------------------------------
Overall, unregulated business income, after parent-allocated interest but
before income taxes, was a loss of about $0.4 million in the third quarter of
1999, compared to a loss of less than $0.3 million in the third quarter of 1998.
American Payment Systems, Inc. (APS) earned about $0.8 million (before-tax) in
the third quarter of 1999,
- 25 -
more than double the $0.39 million earned in the third quarter of 1998.
Precision Power, Inc. (PPI) lost about $1.3 million (before-tax) in the third
quarter of 1999, compared to a loss of about $0.3 million in the third quarter
of 1998, reflecting increased infrastructure costs and lower than anticipated
contract margins.
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. UBE earned about $0.7 million (before-tax) in the third quarter of
1999. Other unregulated subsidiary projects lost about $0.6 million in the third
quarter of 1999, compared to a loss of about $0.3 million in the third quarter
of 1998.
Note: Unregulated business before-tax income is reported as part of "Other net"
income; parent interest charges allocated to the unregulated businesses are
reported as part of "Interest charges"; and related income tax expense is
reported as part of "Non-operating income taxes".
3rd Q 3rd Q 99 3rd Q 99
ended vs. vs.
Sept. 99 3rd Q 98 2nd Q 99
Summary of Unregulated Subsidiaries Pre-tax Income: $millions $millions $millions
- --------------------------------------------------------------------- ------------ ---------- ----------
American Payment Systems, Inc. 0.8 0.4 0.5
- --------------------------------------------------------------------- ------------ ---------- ----------
Precision Power, Inc. (1.3) (1.0) 0.7
- --------------------------------------------------------------------- ------------ ---------- ----------
United Bridgeport Energy 0.7 0.7 1.7
- -------------------------------------------------------------------- ------------ ---------- ----------
United Resources, Inc. Capital Projects (0.6) (0.3) (0.5)
- --------------------------------------------------------------------- ------------ ---------- ----------
FIRST NINE MONTHS OF 1999 VS. FIRST NINE MONTHS OF 1998
Earnings for the first nine months of 1999 were $48.8 million, or $3.47 per
share (on both a basic and diluted basis), up $5.3 million, or $.36 per share,
from the first nine months of 1998 (basic). Excluding one-time items, earnings
from operations were $48.2 million, or $3.43 per share, up $6.0 million, or $.41
per share.
The one-time items reported in the first nine months of 1998 and 1999 were:
One-time Item $millions EPS
- --------------------------------------------------------------------------------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .14
"Sharing" due to one-time item recorded
in the third quarter $(.05)
"Sharing" revenues (before-tax) $(0.6)
"Sharing" amortization (before-tax) 0.6
- --------------------------------------------------------------------------------
Utility Earnings from Operations
- --------------------------------
Retail revenues from operations increased by $17.6 million in the first
nine months of 1999 compared to the first nine months of 1998, as electric
revenues increased for the reasons detailed below. Retail revenues decreased by
$0.3 million because of "sharing" required under the current regulatory
structure as applied to the one-time items recorded in both periods. Retail fuel
and energy expense from operations increased by $13.8 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 $2.6 million,
or 0.5%. The principal components of the retail sales margin change for the nine
months ended September 30, 1999, compared to the nine months ended September 30,
1998, include:
- 26 -
$millions
- -------------------------------------------------------------------- -----------
Revenue from:
- -------------------------------------------------------------------- -----------
Sharing: year-to-date for 1999 (see Note A) (6.3)
- -------------------------------------------------------------------- -----------
Estimate of "real" retail sales growth, up 3.5% 17.5
- -------------------------------------------------------------------- -----------
Estimate of weather effect on retail sales, up 1.4% 7.0
- -------------------------------------------------------------------- -----------
Sales decrease from Yale University cogeneration, (0.9)% (4.1)
- -------------------------------------------------------------------- -----------
Price mix of sales and other 3.4
- -------------------------------------------------------------------- -----------
"Sharing" due to one-time items (0.3)
- -------------------------------------------------------------------- -----------
Revenue based taxes (1.1)
- -------------------------------------------------------------------- -----------
Fuel and energy, margin effect:
- -------------------------------------------------------------------- -----------
Sales increase (3.7)
- -------------------------------------------------------------------- -----------
Nuclear fuel prices and outage replacement power costs (2.7)
- -------------------------------------------------------------------- -----------
Purchased energy prices (see Note B) (7.4)
- -------------------------------------------------------------------- -----------
A. The Company's return on regulated utility common stock equity for the
first nine months of 1999 exceeded the 11.5% "sharing" trigger by
about $25 million of pre-tax income. As a result, a book revenue
"sharing" reduction of $8.7 million, including a gross earnings tax
component, was recorded in the third quarter of 1999, approximately
$6.3 million more than the $2.4 million book revenue "sharing"
reduction recorded from operations in the third quarter of 1998.
B. 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 significantly beginning in the second quarter.
This particularly relates to wholesale revenue, retail purchased
energy and fossil fuel expenses, operation and maintenance expense,
depreciation, interest charges and property taxes. 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 $8.6 million in the first nine months of 1999 compared to the first nine
months of 1998 from lower wholesale sales. Other operating revenues, which
include NEPOOL related transmission revenues, increased by $3.7 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 $7.0 million in the first nine months of 1999 compared to
the first nine of 1998. The principal components of these expense changes
include:
- 27 -
$millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Connecticut Yankee (1.1)
- --------------------------------------------------------------------- ----------
Cogeneration and other purchases (see Note) 2.9
- --------------------------------------------------------------------- ----------
Other O&M expense:
- --------------------------------------------------------------------- ----------
Seabrook Unit 1 (refueling outage costs and accruals) 4.6
- --------------------------------------------------------------------- ----------
Millstone Unit 3 (refueling outage costs and accruals) 1.2
- --------------------------------------------------------------------- ----------
Other expenses at nuclear units (1.0)
- --------------------------------------------------------------------- ----------
Fossil generation unit operating and maintenance costs (18.3)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 2.6
- --------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale 2.1
- --------------------------------------------------------------------- ----------
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 $6.5 million in the first nine months of
1999 compared to the first nine 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. Three-fourths
of the total, or $9.9 million (before-tax, $6.3 million after-tax), was recorded
in the first nine months of 1998. The Company is amortizing regulatory income
tax assets for the 1999 amount, totaling $12.1 million (after-tax, $20 million
pre-tax equivalent), three-fourths of it, or $9.1 million (after-tax, $15.2
million pre-tax equivalent), in the first nine months of 1999.
The Company can also incur additional accelerated amortization expense as a
result of the "sharing" mechanism in the Rate Plan, if the Company achieves a
return on utility common stock equity above 11.5%, which the Company did achieve
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,
$1.0 million in pre-tax equivalent), as a result of the one-time gain recorded
in that quarter. "Sharing" amortization from operations of $5.0 million
(after-tax, $8.4 million of pre-tax equivalent) was recorded in the third
quarter of 1999. "Sharing" amortizations recorded in the first nine months of
1998 were: $0.5 million (before-tax, $0.3 million after-tax) as a result of a
one-time item, and $2.1 million (before-tax, $1.2 million after-tax) from
operations.
Interest charges continued on their downward trend, decreasing by $8.0
million for the regulated business in the first nine months of 1999 compared to
the first nine months of 1998, partly offset by an increase of $2.0 million in
interest charges for unregulated subsidiaries. Most of the reduction in utility
interest charges anticipated for 1999 compared to 1998 began accruing 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.
Unregulated Business Earnings from Operations
- ---------------------------------------------
Overall, unregulated business income, after parent-allocated interest but
before income taxes, was a loss of about $4.3 million in the first nine months
of 1999 compared to income of about $0.3 million in the first nine months of
1998. American Payment Systems, Inc. (APS) earned about $1.4 million
(before-tax) in the first nine months of 1999, reflecting an increase of $0.5
million over the first nine months of 1998. Precision Power, Inc. (PPI) lost
about $4.0 million (before-tax) in the first nine months of 1999, compared to a
loss of about $0.4 million
- 28 -
in the first nine months of 1998, reflecting increased infrastructure costs and
lower than anticipated contract margins.
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. UBE lost about $0.4 million (before-tax) in the first nine months of
1999, as a result of the second quarter shutdown of the first phase generator to
allow for construction of the second phase. Other unregulated subsidiary
projects lost about $1.3 million in the third quarter of 1999, reflecting a
decrease of about $1.1 million compared to the third quarter of 1998.
Note: Unregulated business before-tax income is reported as part of "Other net"
income; parent interest charges allocated to them are reported as part of
"Interest charges"; and related income tax expense is reported as part of
"Non-operating income taxes".
9 mos.
ended 1st 9 mos.
Sept. 99 99 vs. 98
Summary of Unregulated Subsidiaries Pre-tax Income: $millions $millions
- --------------------------------------------------------- ---------- -----------
American Payment Systems, Inc. 1.4 0.5
- --------------------------------------------------------- ---------- -----------
Precision Power, Inc. (4.0) (3.6)
- --------------------------------------------------------- ---------- -----------
United Bridgeport Energy, Inc. (0.4) (0.4)
- --------------------------------------------------------- ---------- -----------
United Resources, Inc. Capital Projects (1.3) (1.1)
- --------------------------------------------------------- ---------- -----------
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 Note (C), "Rate-Related Regulatory Proceedings -
Five-year Rate Plan" 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. Based on this estimate,
the Company commenced recording "sharing" customer price reductions and
additional amortization of regulatory assets in the third quarter of
- 29 -
1999, when it began 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.
An early look at 2000; continued growth of non-regulated business value
- -----------------------------------------------------------------------
On January 1, 2000, the Company will complete the restructuring process
initiated by the Connecticut electric utility industry restructuring legislation
in 1998. The Company's regulated business will become an electricity delivery
business. Many changes will occur in the revenue and cost structure of the
regulated business, although the framework of the current Rate Plan, including
the "sharing" mechanism, will continue through 2001. The regulatory
restructuring decisions have not altered the Company's allowed return of 11.5%
on utility equity, and they have been crafted in a manner that should not
impinge on the Company's ability to achieve that return.
If the Company were to earn 11.5% on equity in the regulated business, that
level of earning should generate $3.25 - $3.35 per share in earnings. Sharing
will be greatly reduced from 1999 levels, due to mandates in the restructuring
legislation; and the Company expects it will contribute no more than $.05 - $.10
per share.
Unregulated businesses are expected to make significant contributions to
earnings in 2000. As a result of management's continued confidence in the
potential of the unregulated businesses, the Company is evaluating further
investments in this area. American Payment Systems and United Bridgeport Energy
should each contribute $.10 - $.15 per share in 2000, while Precision Power
should break even. The other unregulated businesses should, in the aggregate,
lose up to $.05 per share, although investments in other growth initiatives
could increase losses in the near term in anticipation of higher future
earnings. Total earnings for 2000, contingent upon normal weather, current
interest rates, and current expense levels, would now be estimated to fall in
the range of $3.45 to $3.75.
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 has been 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 393 affected business processes have been identified and all 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.
- 30 -
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.
By June 30 1999, the Company's Year 2000 program for all critical business
processes, with the exception of two systems in the Controller's department
(Materials Management and General Ledger), was complete. Those exceptions were
awaiting compliant vendor releases prior to testing. As of October 30, 1999
those two systems, as well as all of UI's remaining business processes, were
determined to be Year 2000 ready. This reflects the completion of Year 2000
readiness acceptance of all identified and prioritized processes by testing,
remediation, retirement or replacement.
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 it is under continuous change due to the electric industry
restructuring in Connecticut. The Year 2000 readiness acceptance was completed
for all priority one systems as of October 30, 1999. Priority two implies that
failure of this software or hardware will present a disruption of service at
current budget levels, but work-arounds 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 may 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, and the Year 2000 readiness acceptance for
the process has now been completed. A stabilization period was put into effect
on October 15, 1999 to minimize any risk of contamination of the current Y2K
ready environment.
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
provides monthly updates to the DPUC on all Y2K progress. The Company also
provided monthly reports to the North American Electric Reliability Council
(NERC) on the Year 2000 compliance 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 is ongoing. 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
also in progress and on schedule. 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 NERC.
Several tests at the ISO and NERC levels were completed successfully, the most
recent being a nationwide NERC test on September 8 and 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
- 31 -
communications systems precludes certainty that all critical system remediation
will be successful. High level contingency planning for essential business
processes has been completed. These plans will be continually reviewed, revised
and modified throughout the remainder of the year as appropriate. As a part of
the contingency planning process, consideration will be given to potential
frequency and duration of interruptions in the generating, financial and
communications infrastructures. Since contingency planning is, by nature, a
speculative process, there can be no assurance that this planning will
completely eliminate the risk of material impacts to the Company's business due
to Year 2000 problems. However, the Company recognizes the importance to its
customers of a reliable supply of electricity, and it intends to devote whatever
resources are necessary to assure that both the program and its implementation
are successful.
The Company believes that the successful implementation of this program
should ultimately cost approximately $6.1 million for existing information
systems and embedded technology. A total of $5.6 million had been expended as of
September 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.
- 32 -
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See the Registrant's Quarterly Report (Form 10-Q) for the fiscal quarter
ended March 31, 1999.
- 33 -
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit
Table Item Exhibit
Number Number Description
---------- ------- -----------
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended
September 30, 1999 and Twelve Months Ended December 31, 1998,
1997, 1996, 1995 and 1994).
(27) 27 Financial Data Schedule
(b) Reports on Form 8-K.
None
- 34 -
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 11/15/99 Signature /s/ Robert L. Fiscus
------------------ ---------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
- 35 -
EXHIBIT INDEX
Exhibit
Table Item Exhibit
Number Number Description
---------- ------- -----------
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended
September 30, 1999 and Twelve Months Ended December 31, 1998,
1997, 1996, 1995 and 1994).
(27) 27 Financial Data Schedule