SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDING JUNE 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
NONE
(Former name, former address and former fiscal year, if changed since
last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of June 30, 1998, was 14,334,922.
- 1 -
INDEX
Part I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three and six months
ended June 30, 1998 and 1997. 3
Consolidated Balance Sheet as of June 30, 1998 and
December 31, 1997. 4
Consolidated Statement of Cash Flows for the three and six
months ended June 30, 1998 and 1997. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 8
- Rate-Related Regulatory Proceedings 9
- Short-term Credit Arrangements 10
- Income Taxes 11
- Supplementary Information 12
- Fuel Financing Obligations and Other Lease Obligations 13
- Commitments and Contingencies 13
- Capital Expenditure Program 13
- Nuclear Insurance Contingencies 13
- Other Commitments and Contingencies 14
- Connecticut Yankee 14
- Hydro-Quebec 14
- Property Taxes 14
- Site Decontamination, Demolition and Remediation Costs 15
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 15
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 16
- Major Influences on Financial Condition 16
- Capital Expenditure Program 18
- Liquidity and Capital Resources 19
- Subsidiary Operations 20
- Results of Operations 20
- Looking Forward 23
Part II. OTHER INFORMATION
Item 1. Legal Proceedings. 29
Item 4. Submission of Matters to a Vote of Security Holders. 29
Item 5. Other Information. 30
Item 6. Exhibits and Reports on Form 8-K. 31
SIGNATURES 32
- 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 Six Months Ended
June 30, June 30,
1998 1997 1998 1997
---- ---- ---- ----
OPERATING REVENUES (NOTE G) $159,792 $163,774 $322,266 $344,099
------------- ------------- ------------- ------------
OPERATING EXPENSES
Operation
Fuel and energy 33,412 39,020 73,953 93,941
Capacity purchased 8,978 10,922 15,200 21,839
Other 38,094 39,619 71,403 76,909
Maintenance 10,560 10,659 21,593 19,894
Depreciation 20,632 23,614 41,438 40,706
Amortization of cancelled nuclear project and deferred return 3,439 3,439 6,879 6,879
Income taxes (Note F) 11,193 712 22,680 12,027
Other taxes (Note G) 12,310 13,097 25,269 27,062
------------- ------------- ------------- ------------
Total 138,618 141,082 278,415 299,257
------------- ------------- ------------- ------------
OPERATING INCOME 21,174 22,692 43,851 44,842
------------- ------------- ------------- ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 40 138 70 342
Other-net (Note G) (4,461) 725 (4,016) 1,506
Non-operating income taxes 2,923 1,522 3,006 2,939
------------- ------------- ------------- ------------
Total (1,498) 2,385 (940) 4,787
------------- ------------- ------------- ------------
INCOME BEFORE INTEREST CHARGES 19,676 25,077 42,911 49,629
------------- ------------- ------------- ------------
INTEREST CHARGES
Interest on long-term debt 12,879 15,876 26,402 32,248
Interest on Seabrook obligation bonds owned by the company (1,818) (1,691) (3,636) (3,382)
Other interest (Note G) 1,432 852 2,276 1,618
Allowance for borrowed funds used during construction (135) (353) (264) (839)
------------- ------------- ------------- ------------
12,358 14,684 24,778 29,645
Amortization of debt expense and redemption premiums 618 648 1,268 1,326
------------- ------------- ------------- ------------
Net Interest Charges 12,976 15,332 26,046 30,971
------------- ------------- ------------- ------------
MINORITY INTEREST IN PREFERRED SECURITIES 1,203 1,203 2,406 2,406
------------- ------------- ------------- ------------
NET INCOME 5,497 8,542 14,459 16,252
Discount on preferred stock redemptions (21) - (21) (19)
Dividends on preferred stock 50 52 101 103
------------- ------------- ------------- ------------
INCOME APPLICABLE TO COMMON STOCK $5,468 $8,490 $14,379 $16,168
============= ============= ============= ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,021 14,101 14,004 14,101
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,024 14,101 14,011 14,101
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $0.39 $0.61 $1.03 $1.15
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72 $1.44 $1.44
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 3 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
June 30, December 31,
1998 1997*
---- ----
(Unaudited)
Utility Plant at Original Cost
In service $1,874,934 $1,867,145
Less, accumulated provision for depreciation 676,595 644,971
--------------- ---------------
1,198,339 1,222,174
Construction work in progress 19,496 25,448
Nuclear fuel 24,536 25,990
--------------- ---------------
Net Utility Plant 1,242,371 1,273,612
--------------- ---------------
Other Property and Investments 34,350 32,451
--------------- ---------------
Current Assets
Cash and temporary cash investments 14,972 32,002
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 57,724 57,231
Other 30,947 27,914
Accrued utility revenues 27,007 25,269
Fuel, materials and supplies, at average cost 30,709 19,147
Prepayments 9,478 3,397
Other 136 67
--------------- ---------------
Total 170,973 165,027
--------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 9,221 6,611
Other 3,766 5,727
--------------- ---------------
Total 12,987 12,338
--------------- ---------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 220,401 228,992
Connecticut Yankee 48,223 51,313
Deferred return - Seabrook Unit 1 18,878 25,171
Unamortized redemption costs 22,321 23,027
Unamortized cancelled nuclear projects 11,538 12,125
Uranium enrichment decommissioning cost 1,245 1,312
Other 5,661 6,357
--------------- ---------------
Total 328,267 348,297
--------------- ---------------
$1,788,948 $1,831,725
=============== ===============
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 4 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
June 30, December 31,
1998 1997*
---- ----
(Unaudited)
Capitalization (Note B)
Common stock equity
Common stock $292,006 $288,730
Paid-in capital 1,908 1,349
Capital stock expense (2,182) (2,182)
Unearned employee stock ownership plan equity (10,685) (11,160)
Retained earnings 156,420 162,226
--------------- ---------------
437,467 438,963
Preferred stock 4,299 4,351
Minority interest in preferred securities 50,000 50,000
Long-term debt
Long-term debt 657,490 746,058
Investment in Seabrook obligation bonds (92,860) (101,388)
--------------- ---------------
Net long-term debt 564,630 644,670
--------------- ---------------
Total 1,056,396 1,137,984
--------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 38,631 40,821
Pensions accrued 37,305 39,149
Nuclear decommissioning obligation 20,206 17,538
Obligations under capital leases 16,683 16,853
Other 6,037 5,507
--------------- ---------------
Total 118,862 119,868
--------------- ---------------
Current Liabilities
Current portion of long-term debt 74,574 100,000
Notes payable 118,825 37,751
Accounts payable 52,846 68,699
Dividends payable 10,145 10,051
Taxes accrued 6,086 4,166
Interest accrued 18,183 10,266
Obligations under capital leases 344 340
Other accrued liabilities 42,123 37,471
--------------- ---------------
Total 323,126 268,744
--------------- ---------------
Customers' Advances for Construction 1,864 1,878
--------------- ---------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 16,004 16,385
Other 2,057 2,356
--------------- ---------------
Total 18,061 18,741
--------------- ---------------
Deferred Income Taxes (future tax liabilities owed 270,639 284,510
to taxing authorities)
Commitments and Contingencies (Note L)
--------------- ---------------
$1,788,948 $1,831,725
=============== ===============
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 5 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
---- ---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $5,497 $8,542 $14,459 $16,252
------------ ----------- ------------ -------------
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 21,897 24,701 43,748 43,055
Deferred income taxes (3,029) (7,737) (5,280) (10,965)
Deferred investment tax credits - net (191) (191) (381) (381)
Amortization of nuclear fuel 1,232 1,309 2,497 2,877
Allowance for funds used during construction (175) (491) (334) (1,181)
Amortization of deferred return 3,146 3,146 6,293 6,293
Changes in:
Accounts receivable - net (9,865) 10,494 (3,526) 23,171
Fuel, materials and supplies (7,794) 1,034 (11,562) 959
Prepayments (3,113) (2,623) (6,081) 591
Accounts payable 10,198 (5,512) (15,853) (24,655)
Interest accrued 5,389 6,743 7,917 9,137
Taxes accrued (9,999) (8,628) 1,920 1,901
Other assets and liabilities 3,987 (4,258) 1,195 (3,516)
------------ ----------- ------------ -------------
Total Adjustments 11,683 17,987 20,553 47,286
------------ ----------- ------------ -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 17,180 26,529 35,012 63,538
------------ ----------- ------------ -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 295 - 4,310 -
Long-term debt - - 99,780 -
Notes payable 73,705 (18,948) 81,074 24,676
Securities redeemed and retired:
Preferred stock (52) - (52) (40)
Long-term debt (80,000) - (213,976) (32,585)
Discount on preferred stock redemption 21 - 21 19
Expense of issue - - (800) -
Lease obligations (84) (78) (166) (154)
Dividends
Preferred stock (51) (52) (102) (104)
Common stock (10,090) (10,153) (20,090) (20,306)
------------ ----------- ------------ -------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (16,256) (29,231) (50,001) (28,494)
------------ ----------- ------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (2,213) (9,735) (10,569) (24,187)
Investment in debt securities - - 8,528 -
------------ ----------- ------------ -------------
NET CASH USED IN INVESTING ACTIVITIES (2,213) (9,735) (2,041) (24,187)
------------ ----------- ------------ -------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (1,289) (12,437) (17,030) 10,857
BALANCE AT BEGINNING OF PERIOD 16,261 29,688 32,002 6,394
------------ ----------- ------------ -------------
BALANCE AT END OF PERIOD $14,972 $17,251 $14,972 $17,251
============ =========== ============ =============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $8,824 $9,754 $19,450 $20,759
============ =========== ============ =============
Income taxes $20,150 $14,073 $23,050 $17,773
============ =========== ============ =============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 6 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The consolidated financial statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all adjustments that are, in the opinion of management, necessary to a fair
statement of the results for the periods presented. All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations. The Company believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year ended December 31, 1997. Such notes are supplemented as
follows:
(A) STATEMENT OF ACCOUNTING POLICIES
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The weighted average AFUDC rate applied in the first six months of 1998 and
1997 was 8.0% on a before-tax basis.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments. The Company records outstanding checks
as accounts payable until the checks have been honored by the banks.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $1,290,000 and $1,285,000 in the first six
months of 1998 and 1997, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At June 30, 1998, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$14.3 million and $5.9 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
INTEREST RATE AND FUEL PRICE MANAGEMENT
The Company utilizes interest rate and fuel oil price management
instruments to manage interest rate and fuel oil price risk. Interest rate swap
agreements have been entered into that effectively convert the interest rates on
$225 million of variable rate borrowings to fixed rate borrowings. Amounts
receivable or payable under these swap agreements are accrued and charged to
interest expense. The Company enters into basic fuel oil price management
instruments to help minimize fuel oil price risk by fixing the future price for
fuel oil used for generation. Amounts receivable or payable under these
instruments are recognized in income when realized.
As of June 30, 1998, the Company had swap agreements for 1998 for 650,000
barrels of fuel oil at a weighted average price of $15.88 per barrel and had
call options for 200,000 barrels of fuel oil at a weighted average price of
$18.52 per barrel.
- 7 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
(A) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at June 30, 1998, of which 314,330 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 June 30, 1998. Options to purchase 14,299 shares of
stock at an exercise price of $30 per share, 54,500 shares of stock at an
exercise price of $30.75 per share, 4,000 shares of stock at an exercise price
of $35.625 per share, and 25,999 shares of stock at an exercise price of
$39.5625 per share were exercised during the first six months of 1998.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of June 30, 1998, 314,330 shares, with a fair market value of $15.9
million, had been purchased by the ESOP and had not been committed to be
released or allocated to ESOP participants.
(B) RETAINED EARNINGS RESTRICTION
The indenture under which $166.2 million principal amount of Notes are
issued places limitations on the payment of cash dividends on common stock and
on the purchase or redemption of common stock. Retained earnings in the amount
of $98.3 million were free from such limitations at June 30, 1998.
(C) PREFERRED STOCK
In April 1998, the Company purchased at a discount on the open market, and
canceled, 524 shares of its $100 par value 4.35%, Series A preferred stock. The
shares, having a par value of $52,400 were purchased for $31,440, creating a net
gain of $20,960.
(E) LONG-TERM DEBT
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven-month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
- 8 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On June 8, 1998, the Company repaid a $50 million Term Loan prior to its
August 29, 2000 due date. On June 8, 1998, the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.
(C) RATE-REGULATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28, a massive and complex
statute designed to restructure the State's electric utility industry. The
business of generating and supplying electricity to consumers will be opened to
competition and will be separated from the business of delivering electricity to
consumers, beginning in the year 2000. The business of delivering electricity
will remain with the incumbent franchised utility companies (including the
Company). Beginning in 2000, each retail consumer of electricity in Connecticut
(excluding consumers served by municipal electric systems) will be able to
choose his, her or its supplier of electricity from among competing suppliers,
for delivery over the wire system of the franchised electric utility
(Distribution Company). Commencing no later than mid-1999, Distribution
Companies will be required to separate on consumers' bills the charge for
electricity generation services from the charge for delivering the electricity
and all other charges. On July 29, 1998, the DPUC issued the first of what are
expected to be several orders relative to this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will 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, above-market investments in power plants (stranded costs), and the
costs of conservation programs. They will be recovered by the Distribution
Companies from all consumers of electricity on a going-forward basis, commencing
in 2000. Because it is expected that many fossil-fueled power plants may have
market values in excess of their net historic costs, the restructuring
legislation requires that, in order for a Distribution Company to recover the
stranded costs associated with its power plants, its fossil-fueled plants must
be sold prior to 2000 and the 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.
On May 20, 1998, the Company announced that it would commence the process
of selling, through a two-stage bidding process, all of its nonnuclear
generation assets in compliance with the statute. The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven, Connecticut, two long-term contracts for the purchase of power from
refuse-to-energy facilities located in Bridgeport and Shelton, Connecticut, one
long-term contract for the purchase of power from a hydroelectric generating
station located in Derby, Connecticut, and the Company's 5.45% participating
share in the Hydro-Quebec transmission intertie facility linking New England and
Quebec, Canada. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective purchasers of the
assets. The Company has commenced the second stage of the process, during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare final, binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
- 9 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The 1997 through 2001 rate plan agreed to between the DPUC and the Company in
1996 anticipated sufficient income in 2000 to accelerate amortization of
regulatory assets of about $50 million, equivalent to about 8% of retail
revenues. Substantially all of this accelerated amortization may have to be
eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the 1996 five-year rate
plan, beginning in the year 2000.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
June 30, 1998, the Company had $35 million of short-term borrowings outstanding
under this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of June 30, 1998, the
Company had $80 million of short-term borrowings outstanding under this
facility.
In addition, as of June 30, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $3.8 million
outstanding under a bank line of credit agreement.
- 10 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Three Months Ended Six Months Ended
(F) INCOME TAXES June 30, June 30,
1998 1997 1998 1997
---- ---- ---- ----
(000's) (000's)
Income tax expense consists of:
Income tax provisions:
Current
Federal $8,907 $5,381 $19,626 $15,447
State 2,583 1,737 5,709 4,987
------------ ------------ ------------ ------------
Total current 11,490 7,118 25,335 20,434
------------ ------------ ------------ ------------
Deferred
Federal (2,143) (5,945) (3,694) (7,999)
State (886) (1,792) (1,586) (2,966)
------------ ------------ ------------ ------------
Total deferred (3,029) (7,737) (5,280) (10,965)
------------ ------------ ------------ ------------
Investment tax credits (191) (191) (381) (381)
------------ ------------ ------------ ------------
Total income tax expense $8,270 ($810) $19,674 $9,088
============ ============ ============ ============
Income tax components charged as follows:
Operating expenses $11,193 $712 $22,680 $12,027
Other income and deductions - net (2,923) (1,522) (3,006) (2,939)
------------ ------------ ------------ ------------
Total income tax expense $8,270 ($810) $19,674 $9,088
============ ============ ============ ============
The following table details the components
of the deferred income taxes:
Seabrook sale/leaseback transaction ($2,180) ($2,586) ($4,361) ($5,172)
Conservation and load management (2,006) (3,161) (4,013) (4,091)
Accelerated depreciation 1,534 1,460 3,068 2,919
Tax depreciation on unrecoverable plant investment 1,212 1,231 2,424 2,463
Pension benefits 383 52 983 109
Unit overhaul and replacement power costs 860 2,589 462 1,386
Postretirement benefits (106) (148) (208) (292)
Fossil fuel decommissioning reserve (83) (7,002) (165) (7,002)
Other - net (2,643) (172) (3,470) (1,285)
------------ ------------ ------------ ------------
Deferred income taxes - net ($3,029) ($7,737) ($5,280) ($10,965)
============ ============ ============ ============
- 11 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
Three Months Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
---- ---- ---- ----
(000's) (000's)
Operating Revenues
- ------------------
Retail $149,222 $146,044 $295,767 $296,525
Wholesale - capacity 2,887 2,525 6,313 4,782
- energy 5,559 14,195 16,948 41,273
Other 2,124 1,010 3,238 1,519
--------------- --------------- --------------- ---------------
Total Operating Revenues $159,792 $163,774 $322,266 $344,099
=============== =============== =============== ===============
Sales by Class(MWH's)
- ---------------------
Retail
Residential 420,484 412,503 908,813 910,774
Commercial 566,975 543,243 1,131,764 1,083,701
Industrial 292,989 292,456 558,617 561,590
Other 11,848 11,971 24,021 24,248
--------------- --------------- --------------- ---------------
1,292,296 1,260,173 2,623,215 2,580,313
Wholesale 255,472 565,903 763,789 1,496,138
--------------- --------------- --------------- ---------------
Total Sales by Class 1,547,768 1,826,076 3,387,004 4,076,451
=============== =============== =============== ===============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $5,550 $5,496 $11,171 $11,228
Local real estate and personal property 5,419 6,154 10,901 12,291
Payroll taxes 1,341 1,447 3,197 3,543
--------------- --------------- --------------- ---------------
12,310 13,097 25,269 27,062
Nonoperating and other accounts 145 139 293 232
--------------- --------------- --------------- ---------------
Total Other Taxes $12,455 $13,236 $25,562 $27,294
=============== =============== =============== ===============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $340 $306 $660 $926
Equity earnings from Connecticut Yankee 218 242 525 688
Earnings (Loss) from subsidiary companies (4,723) (362) (4,528) (895)
Miscellaneous other income and (deductions) - net (296) 539 (673) 787
--------------- --------------- --------------- ---------------
Total Other Income and (Deductions) - net ($4,461) $725 ($4,016) $1,506
=============== =============== =============== ===============
Other Interest Charges
- ----------------------
Notes Payable $797 $623 $1,315 $1,200
Other 635 229 961 418
--------------- --------------- --------------- ---------------
Total Other Interest Charges $1,432 $852 $2,276 $1,618
=============== =============== =============== ===============
- 12 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for financing up to $37.5 million of fossil fuel purchases. Under this
agreement, the financing entity may acquire and/or store natural gas, coal and
fuel oil for sale to the Company, and the Company may purchase these fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in purchasing and
storing the fuel, plus a charge for maintaining an inventory of the fuel
determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to August 1999. At June 30, 1998, approximately $12.5 million of fossil fuel
purchases were being financed under this agreement.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $167.7 million, excluding AFUDC, for 1998 through 2002.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $75.5 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $75.5 million, or
$3.775 million. The maximum assessment is adjusted at least every five years to
reflect the impact of inflation. With respect to each of the three nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $23.2 million per incident. However, any
assessment would be limited to $3.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$5.0 million.
- 13 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee
and had relied on the Connecticut Yankee Unit for approximately 3.7% of the
Company's 1995 total generating resources. The power purchase contract under
which the Company has purchased its 9.5% entitlement to the Connecticut Yankee
Unit's power output permits Connecticut Yankee to recover 9.5% of all of its
costs from UI. Connecticut Yankee has filed revised decommissioning cost
estimates and amendments to the power contracts with its owners with the Federal
Energy Regulatory Commission (FERC). The estimate of the sum of future payments
for the closing, decommissioning and recovery of the remaining investment in the
Connecticut Yankee Unit was approximately $606 million at December 31, 1997.
Based on regulatory precedent, Connecticut Yankee believes it will continue to
collect from its owners its decommissioning costs, the unrecovered investment in
the Connecticut Yankee Unit and other costs associated with the permanent
shutdown of the Connecticut Yankee Unit. UI expects that it will continue to be
allowed to recover all FERC-approved costs from its customers through retail
rates. The Company's estimate of its remaining share of costs, including
decommissioning, less return of investment (approximately $9.6 million) and
return on investment (approximately $5.7 million) at June 30, 1998, is
approximately $38.6 million. This estimate, which is subject to ongoing review
and revision, has been recorded by the Company as a regulatory asset and an
obligation on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
ten-year Firm Energy Contract, which provides for the sale of 7 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, became effective on July 1, 1991. Additionally, the Company
is obligated to furnish a guarantee for its participating share of the debt
financing for the Phase II facility. As of June 30, 1998, the Company's
guarantee liability for this debt was approximately $7.1 million.
PROPERTY TAXES
The City of New Haven (the City) and the Company are involved in a dispute over
the amount of personal property taxes owed to the City for tax years beginning
with 1991-1992. On May 8, 1998, the City and the Company reached a comprehensive
settlement of all of the Company's contested personal property tax assessments
and tax bills for the tax years 1991-1992 through 1997-1998 and the Company's
personal property tax assessments for the tax year 1998-1999 and subsequent
years. Under the terms of this settlement, the Company will pay the City $14.025
million, subject to Superior Court approval of the settlement and conditioned on
the Company receiving authorization from the DPUC to recover the settlement
amount from its retail customers. The DPUC denied the Company's initial
application for such authorization and, on June 30, 1998, the City agreed to
extend to August 31, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $5 million. The Company
filed a second application with the DPUC on July 9, 1998. If the DPUC
authorization is not forthcoming, the $5 million payment will be applied to
future tax bills.
- 14 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of June 30, 1998, and that the
value of the property following remediation will not exceed $6.0 million. As a
result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and deactivated generation facilities. Remediation will include the
repair and/or replacement of approximately 560 linear feet of sheet piling. The
total cost of the remediation and sheet piling repair is presently estimated at
$15 million.
As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company has commenced the process of selling its Bridgeport and New Haven
generating stations in compliance with Connecticut's electric utility industry
restructuring legislation. It is anticipated that environmental remediation of
contaminants will be required at each of the generating station sites following
its sale.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $473 million (in 1998 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $83 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during the first six months of 1998 was $1,046,000. UI's share of the fund at
June 30, 1998 was approximately $14.3 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 $557 million (in 1998 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during the first six months of 1998 was $244,000. UI's share of the fund at June
30, 1998 was approximately $5.9 million. The current decommissioning cost
estimate for the Connecticut Yankee Unit, assuming the prompt removal and
dismantling of the unit commencing in 1997, is $456 million, of which UI's share
would be $43 million. Through June 30, 1998, $38.4 million has been expended for
decommissioning. The projected remaining decommissioning cost is $417.6 million,
of which UI's share would be $39.7 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 $1,178,000 were funded
by UI during the first six months of 1998, and UI's share of the fund at June
30, 1998 was $25.4 million.
- 15 -
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, has
averaged less than 1.5% during the past 5 years. The Company hopes to continue
to restrict this average to less than the rate of inflation in future years (see
"Looking Forward").
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and regulations
and competition within the electric utility industry.
On December 31, 1996, the DPUC completed a financial and operational
review of the Company and ordered a five-year incentive regulation plan for the
years 1997 through 2001. The DPUC did not change the existing retail base rates
charged to customers; but its order increased amortization of the Company's
conservation and load management program investments during 1997-1998, and
accelerated the recovery of unspecified regulatory assets during 1999-2001 if
the Company's common stock equity return on utility investment exceeds 10.5%
after recording the increased conservation and load management amortization. The
order also reduced the level of conservation adjustment mechanism revenues in
retail prices, provided a reduction in customer prices through a surcredit in
each of the five plan years, and accepted the Company's proposal to modify the
operation of the fossil fuel clause mechanism. The Company's authorized return
on utility common stock equity during the period is 11.5%. Earnings above 11.5%,
on an annual basis, are to be utilized one-third for customer price reductions,
one-third to increase amortization of regulatory assets, and one-third retained
as earnings. As a result of the DPUC's order, customer prices were required to
be reduced, on average, by 3% in 1997 compared to 1996. Retail revenues actually
decreased by approximately $30 million, or 4.6%, in 1997 due to customer price
reductions. Also as a result of the order, customer prices are required to be
reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996.
By its terms, the DPUC's 1996 order should be reopened in 1998 to determine the
regulatory assets to be subjected to accelerated recovery in 1999, 2000 and
2001.
In April 1998, Connecticut enacted Public Act 98-28, a massive and complex
statute designed to restructure the State's electric utility industry. The
business of generating and supplying electricity to consumers will be opened to
competition and will be separated from the business of delivering electricity to
consumers, beginning in the year 2000. The business of delivering electricity
will remain with the incumbent franchised utility companies (including the
Company). Beginning in 2000, each retail consumer of electricity in Connecticut
(excluding consumers served by municipal electric systems) will be able to
choose his, her or its supplier of electricity from among competing suppliers,
for delivery over the wire system of the franchised electric utility
(Distribution Company). Commencing no later than mid-1999, Distribution
Companies will be required to separate on consumers' bills the charge for
electricity generation services from the charge for delivering the electricity
and all other charges. On July 29, 1998, the DPUC issued the first of what are
expected to be several orders relative to this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will 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, above-market investments in power plants (stranded costs), and the
costs of systems benefits and conservation programs. They will be recovered by
the Distribution Companies from all consumers of electricity on a going-forward
basis, commencing in 2000. Because it is expected that many fossil-fueled power
plants may have market values in excess of their net historic costs, the
restructuring legislation requires that, in order for a Distribution Company to
recover the stranded costs associated
- 16 -
with its power plants, its fossil-fueled plants must be sold prior to 2000 and
the 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.
On May 20, 1998, the Company announced that it would commence the process
of selling, through a two-stage bidding process, all of its nonnuclear
generation assets in compliance with the statute. The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven, Connecticut, two long-term contracts for the purchase of power from
refuse-to-energy facilities located in Bridgeport and Shelton, Connecticut, one
long-term contract for the purchase of power from a hydroelectric generating
station located in Derby, Connecticut, and the Company's 5.45% participating
share in the Hydro-Quebec transmission intertie facility linking New England and
Quebec, Canada. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective purchasers of the
assets. The Company has commenced the second stage of the process, during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare final, binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The DPUC's 1996 order anticipated sufficient income in 2000 to accelerate
amortization of regulatory assets of about $50 million, equivalent to about 8%
of retail revenues. Substantially all of this accelerated amortization may have
to be eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the 1996 order, beginning in
the year 2000.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income statement impact of certain costs that are expected to be
recovered in future regulated service rates and to establish regulatory assets
on its balance sheet for such costs. The effects of competition or a change in
the cost-based regulatory structure could cause the operations of the Company,
or a portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. While the Company expects to continue to
meet these criteria in the foreseeable future, if the Company, or a portion of
its assets or operations, were to cease meeting these criteria, accounting
standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs,
would be required in the year in which the criteria are no longer met, if such
deferred costs are not recoverable in that portion of the business that
continues to meet the criteria for the application of SFAS No. 71. If this
change in accounting were to occur, it would have a 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.
- 17 -
CAPITAL EXPENDITURE PROGRAM
The Company's 1998-2002 capital expenditure program, excluding allowance
for funds used during construction (AFUDC) and its effect on certain
capital-related items, is presently budgeted as follows:
1998 1999 2000 2001 2002 TOTAL
---- ---- ---- ---- ---- -----
(000's)
Production (1) $7,800 $14,000 $4,500 $2,000 $2,500 $30,800
Distribution and Transmission 26,100 23,000 21,500 15,000 15,000 100,600
Other 3,300 3,400 1,000 1,000 1,000 9,700
------ ------ ------ ------ ------ ------
SUBTOTAL 37,200 40,400 27,000 18,000 18,500 141,100
Nuclear Fuel 8,300 800 8,500 6,000 3,000 26,600
------ ---- ------ ------ ------ -------
Total Expenditures $45,500 $41,200 $35,500 $24,000 $21,500 $167,700
======= ======= ======= ======= ======= ========
Rate Base and Other Selected Data:
- ---------------------------------
Depreciation
Book Plant 57,200 58,200 45,900 46,700 47,300
Conservation Assets 10,309 5,390 0 0 0
Decommissioning 2,700 2,800 2,900 3,000 3,100
Additional Required
Amortization (pre-tax)(2)
Conservation Assets 13,000 0 0 0 0
Other Regulatory Assets 0 20,300 0 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 12,586 0 0 0
Estimated Rate Base
(end of period) 1,106,000
(1) Reflects divestiture of fossil fueled generation plant in 1999. Remaining
Production is nuclear generation plant, excluding nuclear fuel.
(2) Additional amortization of pre-1997 conservation costs and other
unspecified regulatory assets, as ordered by the DPUC in its December 31,
1996 Order, provided that, as expected, common equity return on utility
investment exceeds 10.5% after recording the additional amortization.
Note: Capital Expenditures and their effect on certain capital-related items
are estimates subject to change due to future events and conditions that
may be substantially different than those used in developing the
projections. In particular, the recently enacted legislation to
restructure Connecticut's electric utility industry will require the
Company to divest itself of its fossil-fueled generating plants prior to
January 1, 2000 and to attempt to divest itself of its ownership
interests in nuclear-fueled generating units prior to January 1, 2004.
- 18 -
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 1998, the Company had $15.0 million of cash and temporary cash
investments, a decrease of $17.0 million from the balance at December 31, 1997.
The components of this decrease, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
Balance, December 31, 1997 $ 32.0
------
Net cash provided by operating activities 35.0
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (29.8)
- Dividend payments (20.2)
Net cash provided by investing activities, excluding
investment in plant 8.5
Cash invested in plant, including nuclear fuel (10.5)
-----
Net Change in Cash (17.0)
-----
Balance, June 30, 1998 $15.0
=====
The Company's capital requirements are presently projected as follows:
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year $ 32.0 $ - $ - $ - $ -
Internally Generated Funds less Dividends 114.0 120.0 89.0 90.0 95.0
----- ----- ----- ---- -----
Subtotal 146.0 120.0 89.0 90.0 95.0
Less:
Capital Expenditures 45.5 41.2 35.5 24.0 21.5
----- ----- ----- ---- -----
Cash Available to pay Debt Maturities and Redemptions 100.5 78.8 53.5 66.0 73.5
Less:
Maturities and Mandatory Redemptions 104.2 69.6 70.4 75.3 100.3
Optional Redemptions 113.8 - - - -
----- ----- ---- ---- -----
External Financing Requirements (Surplus) $117.5 $(9.2) $16.9 $9.3 $26.8
===== ===== ===== ==== =====
Note:Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections, including the implementation of the legislative
mandate to achieve a 10% price reduction from 1996 average price levels by
the year 2000. 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. In particular, the recently enacted
legislation to restructure Connecticut's electric utility industry will
require the Company to divest itself of its fossil-fueled generating plants
prior to January 1, 2000 and to attempt to divest itself of its ownership
interests in nuclear-fueled generating units prior to January 1, 2004.
- 19 -
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement and an $80 million revolving credit
agreement, described below, the Company expects to be able to satisfy its
external financing needs by issuing additional short-term and long-term debt,
and by issuing preferred stock or common stock, if necessary. The continued
availability of these methods of financing will be dependent on many factors,
including conditions in the securities markets, economic conditions, and the
level of the Company's income and cash flow.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
June 30, 1998, the Company had $35 million of short-term borrowings outstanding
under this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of June 30, 1998, the
Company had $80 million of short-term borrowings outstanding under this
facility.
SUBSIDIARY OPERATIONS
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. Another
subsidiary of URI, Thermal Energies, Inc., is participating in the development
of district heating and cooling facilities in the downtown New Haven area,
including the energy center for an office tower and participation as a 52%
partner in the energy center for a city hall and office tower complex. A third
URI subsidiary, Precision Power, Inc., provides power-related equipment and
services to the owners of commercial buildings, government buildings and
industrial facilities. URI's fourth subsidiary, United Bridgeport Energy, Inc.,
is participating in a merchant wholesale electric generating facility being
constructed on land leased from UI at its Bridgeport Harbor Station generating
plant.
RESULTS OF OPERATIONS
SECOND QUARTER OF 1998 VS. SECOND QUARTER OF 1997
- -------------------------------------------------
Earnings for the second quarter of 1998 were $5.5 million, or $.39 per
share (on both a basic and diluted basis), down $3.0 million, or $.22 per share,
from the second quarter of 1997. Excluding one-time items, earnings from
operations were $8.4 million, or $.60 per share, up $.18 per share from the
second quarter of 1997. The one-time items were:
- 20 -
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Quarter 2 Cumulative deferred tax benefits associated with future
decommissioning of fossil fuel generating plants $ .48
- --------------------------------------------------------------------------------
1997 Quarter 2 Accelerated amortization associated with one-time item $(.29)
- --------------------------------------------------------------------------------
1998 Quarter 2 Subsidiary reserve for agent collection shortfalls
and other potentially uncollectible receivables $(.21)
- --------------------------------------------------------------------------------
Retail operating revenues increased by about $3.2 million in the second
quarter of 1998 compared to the second quarter of 1997, offset by a $2.6 million
increase in retail fuel expense, for a retail sales margin (retail revenues less
retail fuel expense and revenue-based taxes) increase of $0.6 million. The
principal components of the retail margin change include:
$ millions
- --------------------------------------------------------------------------------
Revenues from: DPUC rate order 0.2
- --------------------------------------------------------------------------------
Other price changes (0.6)
- --------------------------------------------------------------------------------
Sales volume-weather/workday related -
- --------------------------------------------------------------------------------
Sales decrease from Yale University cogeneration (0.5)% (0.6)
- --------------------------------------------------------------------------------
Other "real" sales changes, up 3.1% 4.2
- --------------------------------------------------------------------------------
Fuel expense from: Sales increase (1.0)
- --------------------------------------------------------------------------------
Reduced nuclear unit availability -
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 (see Note) (1.2)
- --------------------------------------------------------------------------------
Fossil fuel price and other (0.4)
- --------------------------------------------------------------------------------
Note: Saltwater contamination caused a shutdown of the Bridgeport Harbor
Unit 3 generating unit on May 22, 1998. The unit is undergoing repairs and is
expected to return to service in mid-August 1998. The outage is costing
approximately $1.0 million per month for the purchase of replacement power, as
indicated in the table above. The total maintenance expense associated with the
outage is $0.8 million as shown below, all of it charged in June.
Net wholesale sales margin (wholesale revenue less wholesale fuel expense)
changed only slightly in the second quarter of 1998 compared to the second
quarter of 1997. Other operating revenues, which include NEPOOL related
transmission revenues, increased by $1.1 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $3.6 million in the second quarter of 1998 compared to the
second quarter of 1997. The principal components of these expense changes
include:
$ millions
- --------------------------------------------------------------------------------
Connecticut Yankee Unit, preparing for decommissioning (1.5)
- --------------------------------------------------------------------------------
Cogeneration and other purchases (0.4)
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 0.8
- --------------------------------------------------------------------------------
Unscheduled outage and other expenses at Seabrook 0.4
- --------------------------------------------------------------------------------
Millstone Unit 3 (1.1)
- --------------------------------------------------------------------------------
Pension investment performance and changes to actuarial
assumptions and methodologies (1.5)
- --------------------------------------------------------------------------------
Personnel reductions (1.5)
- --------------------------------------------------------------------------------
Other 1.2
- --------------------------------------------------------------------------------
Depreciation expense, excluding amortization of conservation and load
management costs, increased slightly in the second quarter of 1998 compared to
the second quarter of 1997.
All of the accelerated amortization in 1997 was recorded in the second
quarter of that year as a result of a one-time gain recorded in that quarter.
The Company expects that all of the required accelerated amortization for 1998
will be recorded against earnings from operations and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings from utility operations. Therefore, $3.3 million of
- 21 -
accelerated amortization, reflecting one quarter of the 1998 accelerated
amortization requirement of the five-year rate plan implemented in 1997, was
recorded in the second quarter of 1998.
Other net income decreased slightly in the second quarter of 1998 compared
to the second quarter of 1997. The Company's largest unregulated subsidiary,
American Payment Systems (APS), earned about $126,000 (after-tax) in the second
quarter of 1998, before one-time charges, compared to a loss of $185,000
(after-tax) in the second quarter of 1997. This was more than offset by the
absence of other non-utility income accruals made in 1997, and a reduction in
interest income.
Interest charges continued on their downward trend, decreasing by $2.6
million in the second quarter of 1998 compared to the second quarter of 1997, as
a result of the Company's refinancing program and strong cash flow.
SIX MONTHS OF 1998 VS. SIX MONTHS OF 1997
- -----------------------------------------
Earnings for the first six months of 1998 were $14.4 million, or $1.03 per
share (on both a basic and diluted basis), down $1.8 million, or $.12 per share,
from the first six months of 1997. Excluding one-time items and accelerated
amortization due to one-time items, earnings from operations were $17.3 million,
or $1.24 per share, up $.28 per share from the first six months of 1997. The
one-time items were:
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Quarter 2 Cumulative deferred tax benefits associated with future
decommissioning of fossil fuel generating plants $ .48
- --------------------------------------------------------------------------------
1997 Quarter 2 Accelerated amortization associated with one-time item $(.29)
- --------------------------------------------------------------------------------
1998 Quarter 2 Subsidiary reserve for agent collection shortfalls and
other potentially uncollectible receivables $(.21)
- --------------------------------------------------------------------------------
Retail operating revenues decreased by about $0.8 million in the first six
months of 1998 compared to the first six months of 1997, and retail fuel and
energy expense increased by $3.2 million for a retail sales margin (retail
revenues less retail fuel expense and revenue-based taxes) decrease of $4.0
million. The principal components of the retail margin change include:
$ millions
- --------------------------------------------------------------------------------
Revenues from: DPUC rate order (3.2)
- --------------------------------------------------------------------------------
Other price changes (2.4)
- --------------------------------------------------------------------------------
Sales volume-weather related (0.7) % (2.0)
- --------------------------------------------------------------------------------
Sales decrease from Yale University cogeneration (0.3)% (0.7)
- --------------------------------------------------------------------------------
Other "real" sales changes, up 2.7 % 7.7
- --------------------------------------------------------------------------------
Fuel expense from: Sales increase (1.0)
- --------------------------------------------------------------------------------
Reduced nuclear unit availability (1.0)
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 (see Note) (1.2)
- --------------------------------------------------------------------------------
Fossil fuel price and other -
- --------------------------------------------------------------------------------
Note: Saltwater contamination caused a shutdown of the Bridgeport Harbor
Unit 3 generating unit on May 22, 1998. The unit is undergoing repairs and is
expected to return to service in mid-August 1998. The outage is costing
approximately $1.0 million per month for the purchase of replacement power, as
shown in the table above. The total maintenance expense associated with the
outage is $0.8 million as shown below, all of it charged in June.
Net wholesale sales margin (wholesale revenue less wholesale fuel expense)
increased slightly in the first six months of 1998 compared to the first six
months of 1997. Other operating revenues, which include NEPOOL related
transmission revenues, increased by $1.7 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $10.4 million in the first six months of 1998 compared to
the first six months of 1997. The principal components of these expense changes
include:
- 22 -
$ millions
- --------------------------------------------------------------------------------
Connecticut Yankee Unit, preparing for decommissioning (3.7)
- --------------------------------------------------------------------------------
Cogeneration and other purchases (2.9)
- --------------------------------------------------------------------------------
Unscheduled outage at Bridgeport Unit 3 0.8
- --------------------------------------------------------------------------------
Unscheduled outage and other expenses at Seabrook 0.6
- --------------------------------------------------------------------------------
Millstone Unit 3 (0.7)
- --------------------------------------------------------------------------------
Pension investment performance and changes to actuarial
assumptions and methodologies (2.9)
- --------------------------------------------------------------------------------
Personnel reductions (3.0)
- --------------------------------------------------------------------------------
Other 1.4
- --------------------------------------------------------------------------------
Depreciation expense increased by $0.6 million in the first six months of
1998 compared to the first six months of 1997.
All of the accelerated amortization in 1997 was recorded in the second
quarter of that year as a result of a one-time gain recorded in that quarter.
The Company expects that all of the required accelerated amortization for 1998
will be recorded against earnings from operations and that the Company will
still achieve at least a 10.5 percent return on utility common stock equity from
earnings from utility operations. Therefore, $6.5 million of accelerated
amortization, reflecting one half of the 1998 accelerated amortization
requirements of the five-year rate plan implemented in 1997, was recorded in the
first six months of 1998.
Other net income decreased by about $0.6 million in the first six months of
1998 compared to the first six months of 1997. The Company's largest unregulated
subsidiary, American Payment Systems (APS), earned about $287,000 (after-tax) in
the first six months of 1998, before one-time charges, compared to a loss of
$426,000 (after-tax) in the first six months of 1997. This was more than offset
by the absence of other non-utility income accruals made in 1997, and a
reduction in interest income.
Interest charges continued on their downward trend, decreasing by $5.5
million in the first six months of 1998 compared to the first six months of
1997, as a result of the Company's refinancing program and strong cash flow.
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year rate plan
- -------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework that would reduce the Company's retail prices and accelerate the
recovery of certain "regulatory assets," beginning with deferred conservation
costs. The Company is operating under the terms of this order in 1998. The
Order's schedule of price reductions and accelerated amortizations was based on
a DPUC pro-forma financial analysis that anticipated the Company would be able
to implement such changes and earn an allowed return on common stock equity
invested in utility assets of 11.5% over the period 1997 through 2001. The Order
established a set formula to share any income that would produce a return above
the 11.5% level: one-third would be applied to customer bill reductions,
one-third would be applied to additional amortization of regulatory assets, and
one-third would be retained by shareowners.
The DPUC, in the Order, acknowledged that the Order could be revisited in
the light of any new legislation. In April 1998, Connecticut enacted Public Act
98-28, a massive and complex statute designed to restructure the State's
electric utility industry. The business of generating and supplying electricity
to consumers will be opened to competition and will be separated from the
business of delivering electricity to consumers, beginning in the year 2000. The
business of delivering electricity will remain with the incumbent franchised
utility companies (including
- 23 -
the Company), each to be called an "electric distribution company" (Distribution
Company). Beginning in 2000, each retail consumer of electricity in Connecticut
(excluding consumers served by municipal electric systems) will be able to
choose his, her or its supplier of electricity from among the competing
suppliers, for delivery over the wire system of the Distribution Company.
Commencing no later than mid-1999, Distribution Companies will be required to
separate on consumers' bills the charge for electricity generation services from
the charge for delivering the electricity and all other charges. On July 29,
1998, the DPUC issued the first of what are expected to be several orders
relative to this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will 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, above-market investments in power plants (stranded costs), and the
costs of systems benefits and conservation programs. They will be recovered by
the Distribution Companies from all consumers of electricity on a going-forward
basis, commencing in 2000. Because it is expected that many fossil-fueled power
plants may have market values in excess of their net historic costs, the
restructuring legislation requires that, in order for a Distribution Company to
recover the stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, and the 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.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
On May 20, 1998, the Company announced that it would commence the process
of selling, through a two-stage bidding process, all of its nonnuclear
generation assets in compliance with the statute. The assets offered for sale
include the Company's three fossil-fueled power plants located in Bridgeport and
New Haven, Connecticut, two long-term contracts for the purchase of power from
refuse-to-energy facilities located in Bridgeport and Shelton, Connecticut, one
long-term contract for the purchase of power from a hydroelectric generating
station located in Derby, Connecticut and the Company's 5.45% participating
share in the Hydro-Quebec transmission intertie facility linking New England and
Quebec, Canada. The aggregate generating capability represented by these assets
is approximately 1,300 megawatts. In the first stage of the divestiture process,
the Company solicited statements of interest from prospective purchasers of the
assets. The Company has commenced the second stage of the process, during which
a group of potential bidders will conduct in-depth evaluations of the assets and
prepare final, binding bids. In addition to the DPUC, the sale of these assets
must be approved by the Federal Energy Regulatory Commission.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.6% of this decrease through rate reductions in 1997.
The Order anticipated sufficient income in 2000 to accelerate amortization of
regulatory assets of about $50 million, equivalent to about 8% of retail
revenues. Substantially all of this accelerated amortization may have to be
eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the Order's five-year rate
plan, beginning in the year 2000.
- 24 -
1998 Earnings
- -------------
The Company's earnings from its utility business are greatly affected by:
retail sales that fluctuate with weather conditions and economic activity,
fossil fuel prices, nuclear generating unit availability and operating costs,
and interest rates. These are all items over which the Company has little
control, although the Company engages in economic development activities to
increase sales, and hedges its exposure to volatility in fuel costs and interest
rates.
The Company's revenues are principally dependent on the level of retail
sales. The two primary factors that affect retail sales volume are economic
conditions and weather. The Company estimates that mild 1997 weather reduced
retail kilowatt-hour sales by about 0.5 percent for the year. Because much of
the mild 1997 weather occurred in the summer months when prices are higher than
average, the revenue impact was exacerbated. It is estimated that mild weather
may have reduced revenues by as much as $5.2 million for the year, and retail
sales margin (retail revenue less retail fuel expense and revenue-based taxes)
by as much as $4.2 million. Weather corrected retail sales for 1997 were
probably in the 5,375-5,425 gigawatt-hour range. On this basis, the Company
experienced about 1.0-1.5 percent of "real" sales growth in 1997 (i.e. exclusive
of weather and leap year factors) over "normal" 1996 sales, with almost all of
the growth occurring in the last half of the year. A similar level of growth in
1998 compared to 1997 from all customer groups would add about $6-$8 million to
sales margin. Growth in "real" sales in the first six months of 1998 compared to
the first six months of 1997 was more than 2.0 percent, indicating the potential
for further real growth in future quarters. Such growth may be tempered by other
factors, however, some of which are noted below.
Reductions in revenues could occur for several other reasons. The Company
has dealt with the potential loss of customers as a result of self-generation,
relocation or discontinuation of operations by successfully negotiating
multi-year contracts with major customers. Such a contract has been signed with
Yale University, the Company's largest customer, which has constructed a
cogeneration unit that will produce approximately one half of its annual
electricity requirements (about 1.5 percent of the Company's total 1997 retail
sales), commencing in mid-1998. While providing cost reduction and price
stability for customers and helping the Company maintain its customer base for
the long term, these contracts are expected to cause future reductions in retail
revenues. They reduced retail revenues by about $3 million in 1997 compared to
1996, but are not expected to approach that level of change in 1998.
Additionally, rate migration (customers switching to rates that are more
favorable because of usage patterns) reduced retail revenues by about $3 million
in 1997 compared to 1996; but the impact of rate migration on revenues in 1998
compared to 1997 is expected to be less than $1 million. Also, as part of the
Order, the operation of the Company's long-standing fossil fuel adjustment
clause (FAC) mechanism that allowed for recovery in retail rates of changes in
fossil fuel costs was suspended within a broad range of fuel prices. FAC
revenues decreased by about $1.9 million, to zero, in the first quarter of 1998
compared to the first quarter of 1997, due to this suspension of the FAC.
To summarize, assuming that rates of "real" growth experienced in the first
six months of 1998 continue in the second half, and assuming the expected loss
of sales due to Yale University cogeneration, and more normal weather for the
last six months of 1998, some growth in retail kilowatt-hour sales, perhaps 0.5
percent, could occur in 1998 compared to 1997. Retail revenues will be reduced,
from what they would otherwise be, if the Company is in the "sharing" range
above an 11.5% return on common stock equity. Currently, the Company anticipates
a revenue reduction of about $2.5 million in 1998 under the sharing mechanism.
The overall average retail price anticipated for 1998 is about 11.5 cents per
kilowatt-hour, slightly below the average 1997 price but almost 5 percent below
the average 1996 price.
Improvements in wholesale sales margin (wholesale revenue less wholesale
fuel expense) will be dependent on the capacity and energy needs of the region,
on the availability of generating units, on the addition of new generation
sources, and on how the capacity and energy markets perform under the new NEPOOL
open competition system, designed to meet Federal Energy Regulatory Commission
(FERC) open access orders, when it is implemented. Implementation of this system
is currently expected on or about December 1, 1998, but this date is subject to
NEPOOL information system development and testing and further orders from the
FERC. No significant
- 25 -
wholesale sales margin improvement is expected by the Company from wholesale
capacity, transmission and energy sales during 1998.
Another major factor affecting the Company's 1998 earnings prospects will
be the Company's ability to control operating expenses. The Company offered
voluntary early retirement programs and a voluntary severance program to union,
nonunion and management employees in 1996. A portion of the resulting personnel
cost savings occurred in 1996 and 1997, but the largest increment in annual
savings will be realized in 1998. Annual savings of about $6 million from
personnel reductions are estimated, and this amount was validated by first half
results.
The Company is expecting other significant expense declines in 1998
compared to 1997 from a number of sources. From the nuclear generating units, it
is expected that operation and maintenance expenses associated with the Seabrook
and Connecticut Yankee units should decline by a total of about $8 million. The
Seabrook unit went out of service on June 11, 1998 for unscheduled repairs, but
resumed generation on July 11, 1998. This outage should have little impact on
anticipated operation and maintenance expense. The Seabrook unit should have no
refueling outage during the remainder of 1998 and, if it operates at an assumed
95% availability for the rest of the year (its availability was virtually 100%
between refueling outages in 1997), net fuel expense should decline by about $1
million.
Millstone Unit 3 was taken out of service on March 30, 1996. A
comprehensive Nuclear Regulatory Commission (NRC) inquiry into the conformity of
the unit and its operations with all applicable NRC regulations and standards
was completed and the unit was allowed to resume operation beginning on July 4,
1998. It achieved full power production on July 15, 1998. The Company
anticipates that operating costs should ramp down to more normal levels for an
efficient and safe nuclear unit of this class, and expects a reduction of about
$3 million in these costs in 1998 compared to 1997. Also, net fuel expense
should decline by $400,000 per month for every month of operation, net of the
replacement fuel provision of about $100,000 per month...for a total reduction
of about $2.0 million for 1998 compared to 1997.
Pension and health benefit expenses, excluding one-time items, are expected
to decrease by about $2.5 million in 1998 compared to 1997. NEPOOL expenses are
expected to increase by about $1.0 million, and expenses associated with the
"Year 2000 Issue" could increase by as much as $2.0-$3.0 million over the
1998-99 period, above the original $2.6 million estimate for information
technology systems. This increased estimate is based on more current and
detailed information received from embedded technology vendors. Other operation
and maintenance expenses may increase or decrease by amounts that cannot be
predicted at this time.
Interest costs are expected to decline by about $10 million in 1998
compared to 1997 to about $52 million, a level that was last experienced in
1984. This interest cost reduction is largely a result of debt refinancings and
debt paydown. Interest charges for the first six months of 1998 compared to the
first six months of 1997 decreased by $5.5 million.
Other factors should increase costs. Other operation and maintenance
expense should increase by about $7 million in 1998 compared to 1997 reflecting
increased fossil-fueled generating unit scheduled maintenance and provisions for
future outages. Base depreciation, excluding accelerated amortization, should
increase about $2.0 million. Accelerated amortization, per the Order, will
increase by about $7 million (reflecting a $3.3 million per quarter increase,
except for a $3.1 million decrease in the 1998 second quarter compared to 1997,
as all of the $6.4 million amortization for 1997 was recorded as an offset to a
one-time gain in the second quarter.) Other operating expenses will have some
increases and some decreases that should more or less offset one another.
In summary, the Company expects substantial net expense reductions that
should more than compensate for the loss of one-time items recognized in 1997
(all of them utility related), cover the increase in accelerated conservation
and load management amortization, and allow utility earnings to increase above
an 11.5% return on common stock equity into the "sharing" range of the Order.
The 11.5% return level would produce utility earnings of about $3.40-$3.45 per
share, while "shared" earnings could add an additional $.05-$.10 per share.
Non-utility earnings, before one-time items, should increase approximately $.05
per share in 1998 compared to 1997, due principally to
- 26 -
the anticipated breakeven operation of the non-regulated subsidiaries. The
Company expects that 1998 quarterly earnings from operations will follow a
pattern similar to that of 1997 on a weather-normalized basis.
As reported in its recent filing (Form 8-K) with the Securities and
Exchange Commission, an investigation of the accounting records of the Company's
largest subsidiary, American Payment Systems, Inc. (APS) has led to the
creation, in the second quarter of 1998, of additional reserves by APS, for
shortfalls in agent collections and other potentially uncollectible receivables
that were incurred prior to 1998, in the amount of $4.9 million. This resulted
in a one-time charge to the Company's second quarter earnings of $2.9 million
after-tax, or $.21 per share of the Company's common stock. APS accounting
procedures, which failed to detect the cash flow discrepancies, have been
rectified.
Longer Term
- -----------
In addition to the effects of Connecticut's 1998 electric utility industry
restructuring legislation (see the "Five-year rate plan" discussion at the
beginning of the Looking Forward section), there are several other matters that
will affect the longer-term outlook.
The Connecticut Yankee nuclear unit's expenses are expected to continue to
decline by substantial amounts before leveling out at about $6 million per year
after 1998, compared to $11.8 million in 1997, until decommissioning is
complete. However, the ability of the Company to recover its investment in
Connecticut Yankee and its ownership share of future costs associated with the
retirement of the Connecticut Yankee unit will be dependent upon the outcome of
pending regulatory filings with the Federal Energy Regulatory Commission.
On August 7, 1997, the Company and the other nine minority joint owners of
Millstone Unit 3 that are not subsidiaries of Northeast Utilities (NU) filed
lawsuits against NU and its trustees, as well as a demand for arbitration
against The Connecticut Light and Power Company and Western Massachusetts
Electric Company, the operating electric utility subsidiaries of NU that are the
majority joint owners of the unit and have contracted with the minority joint
owners to operate it. The ten non-NU joint owners, who together own about 19.5%
of the unit, claim that NU and its subsidiaries failed to comply with NRC
regulations, failed to operate Millstone Station in accordance with good utility
operating practice and concealed their failures from the non-operating joint
owners and the NRC. The arbitration and lawsuits seek to recover costs of
purchasing replacement power and increased operation and maintenance costs
resulting from the shutdown of Millstone Unit 3.
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. An inventory and assessment of the
Company's computer system applications, hardware, software and embedded
technologies has been completed, and recommended solutions to all identified
risks and exposures have been generated. A remediation, retirement, renovation
and testing program has commenced. Necessary upgrades to mainframe hardware and
software are expected to be completed and tested during 1998, and a parallel
program with respect to desktop hardware and application software on all
platforms is currently projected to be completed and tested, for all critical
systems, by March 31, 1999. The Company believes that the successful
implementation of this program, currently estimated to cost $2.6 million for
existing information systems, will preclude any adverse impact of the Year 2000
Issue on its operations and financial condition. However, embedded technology
remediation may increase the cost of this program by as much as $2.0-$3.0
million over the 1998-99 period. As more embedded technology vendor product
information is received and evaluated, the extent of any such increase will be
determined. The Company is also identifying critical suppliers and other persons
with whom data must be exchanged and is asking for assurance of their Year 2000
readiness. Requests for documented readiness information have been sent to all
critical suppliers, data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed. The external risks of the Year 2000 Issue are significantly
complicated by the interdependence of the utility system infrastructure,
particularly in the power grid and telecommunications areas. UI has joined with
the other New England Power Pool participants
- 27 -
and with the regional Independent System Operator (ISO-New England) in a program
to ensure that the Year 2000 Issue in these areas is being adequately addressed.
Contingency plans will be developed for replacing critical operational and
information systems, if any, for which Year 2000 readiness has not been
demonstrated in a timely manner. 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 these programs and their
implementation will succeed.
Other
- -----
The City of New Haven (the City) and the Company are involved in a dispute
over the amount of personal property taxes owed to the City for tax years
beginning with 1991-1992. On May 8, 1998, the City and the Company reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992 through 1997-1998 and the
Company's personal property tax assessments for the tax year 1998-1999 and
subsequent years. Under the terms of this settlement, the Company will pay the
City $14.025 million, subject to Superior Court approval of the settlement and
conditioned on the Company receiving authorization from the DPUC to recover the
settlement amount from its retail customers. The DPUC denied the Company's
initial application for such authorization and, on June 30, 1998, the City
agreed to extend to August 31, 1998 the time period for satisfying this
condition of the settlement in return for a payment by the Company of $5
million. The Company filed a second application with the DPUC on July 9, 1998.
If the DPUC authorization is not forthcoming, the $5 million payment will be
applied to future tax bills.
- 28 -
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. On March 7, 1997, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1997-1998, which notices purport to increase said
assessed value by approximately 54% over the valuations declared by the Company
and are expected to generate tax claims of approximately $3.7 million. The
Company has vigorously contested each of these actions by the City's tax
assessor. In January 1996, the Connecticut Superior Court granted the Company's
motion for summary judgment against the City relative to the earliest tax year
at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had
no statutory authority to revalue personal property listed and valued on the
Company's tax list for the tax year 1991-1992. This Superior Court decision,
which would also have been applicable to and defeated the assessor's valuation
increases for the two subsequent tax years, 1992-1993 and 1993-1994, was
appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed
the Superior Court's decisions in this and two other companion cases involving
other taxpayers, ruling that the tax assessor had a three-year period in which
to audit and revalue personal property listed and valued on the Company's tax
list for the tax year 1991-1992. On May 8, 1998, the City and the Company
reached a comprehensive settlement of all of the Company's contested personal
property tax assessments and tax bills for the tax years 1991-1992 through
1997-1998 and the Company's personal property tax assessments for the tax year
1998-1999 and subsequent years. Under the terms of this settlement, the Company
will pay the City $14.025 million, subject to Superior Court approval of the
settlement and conditioned on the Company receiving authorization from the DPUC
to recover the settlement amount from its retail customers. The DPUC denied the
Company's initial application for such authorization and, on June 30, 1998, the
City agreed to extend to August 31, 1998 the time period for satisfying this
condition of the settlement in return for a payment by the Company of $5
million. The Company filed a second application with the DPUC on July 9, 1998.
If the DPUC authorization is not forthcoming, the $5 million payment will be
applied to future tax bills.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Annual Meeting of the Shareowners of the Registrant was held on May 20,
1998, for the purpose of electing a Board of Directors for the ensuing year,
voting on the employment, by the Board of Directors, of Price Waterhouse LLP as
the firm of independent public accountants to audit the books and affairs of the
Registrant for the fiscal year 1998, and considering and acting on a proposal to
amend the Registrant's Certificate of Incorporation relative to the number of
members of the Board of Directors.
- 29 -
All of the nominees for election as Directors listed in the Registrant's
proxy statement for the meeting were elected by the following votes:
NUMBER OF SHARES
----------------------------------
VOTED NOT
NOMINEE "FOR" VOTED
------- ----- -----
Thelma R. Albright 12,573,251 173,602
Marc C. Breslawsky 12,585,923 160,930
David E. A. Carson 12,589,837 157,016
John F. Croweak 12,585,210 161,643
J. Hugh Devlin 12,592,918 153,935
Robert L. Fiscus 11,879,894 866,959
Richard J. Grossi 11,890,717 856,136
Betsy Henley-Cohn 12,571,418 175,435
John L. Lahey 12,589,215 157,638
F. Patrick McFadden, Jr. 12,583,615 163,238
Frank R. O'Keefe, Jr. 12,573,342 173,511
James A. Thomas 12,573,354 173,499
The employment of Price Waterhouse LLP as the firm of independent public
accountants to audit the books and affairs of the Registrant for the fiscal year
1998 was approved by the following vote:
NUMBER OF SHARES
------------------------------------------------
VOTED VOTED NOT
"FOR" "AGAINST" VOTED
----- --------- -----
12,595,433 47,639 103,781
The proposal to amend the Registrant's Certificate of Incorporation
relative to the number of members of the Board of Directors was approved by the
following vote:
NUMBER OF SHARES
-----------------------------------------------
VOTED VOTED NOT
"FOR" "AGAINST" VOTED
----- --------- -----
12,125,056 367,467 254,330
ITEM 5. OTHER INFORMATION.
See the Company's Current Report (Form 8-K), dated July 15, 1998,
regarding the creation of $4.9 million of additional reserves by the Company's
subsidiary American Payment Systems, Inc. and the resultant one-time charge to
the Company's second quarter earnings of $2.9 million after-tax, or $.21 per
share of the Company's common stock.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
(3) 3.1d Copy of Certificate Amending Certificate of Incorporation by
Actions of Board of Directors and Shareholders, dated May 28,
1998.
(3) 3.2 Copy of Bylaws of The United Illuminating Company, as amended to
May 28, 1998.
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended
June 30, 1998 and Twelve Months Ended December 31, 1997, 1996,
1995, 1994 and 1993).
(27) 27 Financial Data Schedule
(b) Reports on Form 8-K.
Item Financial
Reported Statements Date of Report
-------- ---------- --------------
5 None May 20, 1998
5 None July 15, 1998
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
Date 8/13/98 Signature /s/ Robert L. Fiscus
-------------- ----------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
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EXHIBIT INDEX
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
(3) 3.1d Copy of Certificate Amending Certificate of Incorporation by
Actions of Board of Directors and Shareholders, dated May 28,
1998.
(3) 3.2 Copy of Bylaws of The United Illuminating Company, as amended to
May 28, 1998.
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended
June 30, 1998 and Twelve Months Ended December 31, 1997, 1996,
1995, 1994 and 1993).
(27) 27 Financial Data Schedule