SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A-2
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
------------ -----------
COMMISSION FILE NUMBER 1-6788
THE UNITED ILLUMINATING COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
CONNECTICUT 06-0571640
(State or other jurisdiction of incorporation (I.R.S. Employer
or organization) Identification No.)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
------------------------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED
---------- ------------------- ------------------------
The United Illuminating Company Common Stock, no par value New York Stock Exchange
United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange
Securities, Series A (Liquidation
Preference $25 per Security)
(1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3,
1995 by United Capital Funding Partnership L.P., a special purpose limited
partnership in which The United Illuminating Company owns all of the
general partner interests, and are guaranteed by The United Illuminating
Company.
SECURITIES REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE,
OF THE UNITED ILLUMINATING COMPANY
-----------------------------------------
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
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 1999 was $699,286,165, computed on the basis of
the average of the high and low sale prices of said stock reported in the
listing of composite transactions for New York Stock Exchange listed securities,
published in The Wall Street Journal on February 1, 1999.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 1999, was 14,334,922.
DOCUMENTS INCORPORATED BY REFERENCE
Document Part of this Form 10-K into which document is incorporated
-------- ----------------------------------------------------------
None N/A
TABLE OF CONTENTS
PAGE
----
Item 6. Selected Financial Data. 4
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 8
- Major Influences on Financial Condition 8
- Liquidity and Capital Resources 11
- Subsidiary Operations 13
- Year 2000 Issue 14
- Results of Operations 15
- Looking Forward 21
Item 8. Financial Statements and Supplementary Data. 24
- Consolidated Financial Statements for the Years 1998, 1997
and 1996 24
- Statement of Income 24
- Statement of Cash Flows 25
- Balance Sheet 26
- Statement of Retained Earnings 28
- Statement of Changes in Shareholders' Equity 29
- Notes to Consolidated Financial Statements 30
- Statement of Accounting Policies 30
- Capitalization 36
- Rate-Related Regulatory Proceedings 41
- Accounting for Phase-in Plan 43
- Short-Term Credit Arrangements 43
- Income Taxes 45
- Supplementary Information 47
- Pension and Other Benefits 48
- Jointly Owned Plant and Power Purchase Agreements 52
- Unamortized Cancelled Nuclear Project 52
- Fuel Financing Obligations and Other Lease Obligations 53
- Commitments and Contingencies 54
1
TABLE OF CONTENTS (CONTINUED)
PAGE
----
PART II (CONTINUED)
- Capital Expenditure Program 54
- Nuclear Insurance Contingencies 54
- Other Commitments and Contingencies 54
- Connecticut Yankee 54
- Hydro-Quebec 55
- Property Taxes 55
- Environmental Concerns 56
- Site Decontamination, Demolition and Remediation
Costs 56
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 56
- Fair Value of Financial Instruments 58
- Quarterly Financial Data (Unaudited) 59
- Segment Information 59
- Restatement of Financial Results 60
Report of Independent Accountants 62
Report of Independent Accountants on Financial Statement Schedule 63
PART IV
Consent of Independent Accountants 64
Signatures 65
2
This amendment to the Annual Report on Form 10-K of The United Illuminating
Company (the "Company") for the fiscal year ended December 31, 1998 (the
"Original Form 10-K") amends and modifies the Original Form 10-K by restating
(a) Item 6 "Selected Financial Data" in order to amend and supplement that Item,
(b) Item 7 "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in order to amend and supplement the sections
captioned,"Major Influences on Financial Condition", "Subsidiary Operations",
"Year 2000 Issue", "New Accounting Standards", and "Results of Operations", and
(c) Item 8 "Financial Statements and Supplementary Data" in order to (i)
supplement and revise the "Consolidated Statement of Income", "Consolidated
Statement of Cash Flows", Consolidated Balance Sheet", and "Consolidated
Statement of Retained Earnings" and Notes (A), (B), (F), (G), (H), (I), (K), and
(O) to the Notes to Consolidated Financial Statements, as well as the Financial
Statement Schedule II, "Valuation and Qualifying Accounts", and (ii) to add Note
(P), "Segment Information" and Note (Q), "Restatement of Financial Results", to
the Notes to Consolidated Financial Statements, as well as the "Consolidated
Statement of Changes in Shareholders' Equity" to the 'Consolidated Financial
Statements for the Years 1998, 1997, and 1996.
3
ITEM 6. SELECTED FINANCIAL DATA
1998 1997 1996
============================================================================================================================
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $262,974 $259,325 $266,068
Commercial 254,765 248,490 264,111
Industrial 102,201 102,763 109,032
Other 11,667 11,755 11,903
------------- ------------- ----------------
Total Retail 631,607 622,333 651,114
Wholesale (1) 44,948 82,871 72,844
Other operating revenues 9,636 3,825 3,300
------------- ------------- ----------------
Total operating revenues 686,191 709,029 727,258
------------- ------------- ----------------
Fuel and interchange energy -net
Retail -own load 116,769 109,542 95,359
Wholesale 34,775 73,124 65,158
Capacity purchased-net 34,515 39,976 46,830
Depreciation 82,809 (3) 74,618 (3) 65,921
Other amortization, principally deferred return and cancelled plant 13,758 13,758 13,758
Other operating expenses, excluding tax expense 188,946 200,803 219,630 (7)
Gross earnings tax 24,039 23,571 26,804
Other non-income taxes 40,635 (4) 28,922 30,382
------------- ------------- ----------------
Total operating expenses, excluding income taxes 536,246 564,314 563,842
------------- ------------- ----------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 468 1,575 2,375
Other non-operating income(loss) 1,097 (5) 1,361 (8,445) (5)
Interest expense
Long-term debt - net 42,836 56,158 65,046
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other 9,018 6,068 4,721
------------- ------------- ----------------
Total 56,667 67,039 74,580
------------- ------------- ----------------
Income tax expense
Operating income tax 53,619 40,833 (6) 53,590
Non-operating income tax (3,848) (3,678) (9,869)
------------- ------------- ----------------
Total 49,771 37,155 43,721
------------- ------------- ----------------
Income(loss) before cumulative effect of accounting change 45,072 43,457 39,045
Cumulative effect of change in accounting - net of tax 0 0 0
------------- ------------- ----------------
Net income (loss) 45,072 43,457 39,045 (8)
Discount on preferred stock redemption (21) (48) (1,840)
Preferred and preference stock dividends 201 205 330
------------- ------------- ----------------
Income (loss) applicable to common stock $44,892 $43,300 $40,555
- ----------------------------------------------------------------------------------------------------------------------------
Operating income $96,326 $103,882 $109,826
============================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $1,172,555 $1,222,174 $1,258,306
Construction work in progress 33,695 25,448 40,998
Plant-related regulatory asset 0 0 0
Other property and investments 58,047 58,441 49,091
Current assets 305,189 204,474 179,194
Deferred charges and regulatory assets 371,674 408,993 449,150
------------- ------------- ----------------
Total Assets $1,941,160 $1,919,530 $1,976,739
- ----------------------------------------------------------------------------------------------------------------------------
Common stock equity $445,507 $436,081 $439,468
Preferred, preference stock and company-obligated mandatorily
redeemable securities of subsidiaries holding solely parent debentures 54,299 54,351 54,461
Long-term debt excluding current portion 664,510 644,670 759,680
Noncurrent liabilities (9) 109,981 119,868 138,816
Current portion of long-term debt 66,202 100,000 69,900
Notes payable 86,892 37,751 10,965
Other current liabilities (9) 172,830 175,340 146,235
Deferred income tax liabilities and other 340,939 351,469 357,214
------------- ------------- ----------------
Total Capitalization and Liabilities $1,941,160 $1,919,530 $1,976,739
============================================================================================================================
(1) Operating Revenues, for years prior to 1992, include wholesale power
exchange contract sales that were reclassified from Fuel and Capacity
expenses in accordance with Federal Energy Regulatory Commission
requirements.
(2) Includes reclassification of certain Commercial and Industrial customers.
(3) Includes the before-tax effect of charges for additional amortization of
conservation & load management costs: $13.1 million in 1998 and $6.6
million in 1997.
(4) Includes the effect of charges of $14.0 million, before-tax, associated
with property tax settlement.
(5) Includes the before-tax effect of charges for losses associated with
unregulated subsidiaries: $2.8 million in 1997 and $5.8 million in 1996.
4
1995 1994 1993 1992 1991 1990 1989
==========================================================================================================
$260,694 $252,386 $238,185 $226,455 $226,751 $211,891 $205,183
259,715 250,771 (2) 256,559 253,456 (2) 255,782 234,704 219,852
106,963 104,242 (2) 97,466 97,010 (2) 91,895 94,526 92,855
11,736 11,469 11,349 11,065 10,886 10,536 9,943
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
639,108 618,868 603,559 587,986 585,314 551,657 527,833
48,232 34,927 45,931 75,484 84,236 85,657 77,925
3,109 2,953 3,533 3,855 3,821 3,332 3,348
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
690,449 656,748 653,023 667,325 673,371 640,646 609,106
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
96,538 99,589 98,694 108,084 123,010 119,285 128,739
41,631 27,765 39,356 55,169 61,858 69,117 62,681
47,420 44,769 47,424 43,560 44,668 42,827 50,234
61,426 58,165 56,287 50,706 48,181 36,526 35,618
13,758 1,172 1,780 10,415 10,415 4,173 10,415
183,749 193,098 203,427 (10) 183,426 178,912 176,419 144,867
27,379 27,403 27,955 27,362 27,223 25,595 24,506
31,564 32,458 29,977 31,869 28,673 24,648 20,294
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
503,465 484,419 504,900 510,591 522,940 498,590 477,354
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
0 0 7,497 15,959 17,970 21,503 0
2,762 3,463 4,067 3,232 5,190 3,443 65,443
(5,068) (1,907) 71 18,545 2,697 22,654 (219,742)
63,431 73,772 80,030 88,666 90,296 94,056 91,126
3,583 0 0 0 0 0 0
12,841 10,301 12,260 12,882 9,847 15,468 22,849
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
79,855 84,073 92,290 101,548 100,143 109,524 113,975
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
59,828 44,937 33,309 48,712 47,231 43,493 37,963
(4,901) (3,214) (6,322) (12,558) (19,299) (17,409) (101,135)
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
54,927 41,723 26,987 36,154 27,932 26,084 (63,172)
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
49,896 48,089 40,481 56,768 48,213 54,048 (73,350)
0 (1,294) 0 0 7,337 0 0
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
49,896 46,795 40,481 (11) 56,768 55,550 54,048 (73,350)
(2,183) 0 0 0 0 0 0
1,329 3,323 4,318 4,338 4,530 4,751 8,233
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
$50,750 $43,472 $36,163 $52,430 $51,020 $49,297 ($81,583)
- ----------------------------------------------------------------------------------------------------------
$127,156 $127,392 $114,814 $108,022 $103,200 $98,563 $93,789
==========================================================================================================
$1,277,910 $1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173 $562,473
41,817 57,669 77,395 59,809 54,771 50,257 675,831
0 0 0 0 0 0 81,768
53,355 53,267 58,096 65,320 79,009 90,006 91,648
136,481 157,309 187,981 247,954 164,839 161,066 170,823
475,258 538,601 567,394 556,493 554,365 553,986 605,696
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
$1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239
- ----------------------------------------------------------------------------------------------------------
$439,484 $428,028 $423,324 $422,746 $401,771 $379,812 $362,584
60,539 44,700 60,945 60,945 62,640 69,700 70,000
845,684 708,340 875,268 893,457 909,998 899,993 868,884
65,747 59,458 62,666 44,567 110,217 110,850 117,200
40,800 193,133 143,333 92,833 37,500 41,667 18,667
0 67,000 0 84,099 13,000 15,000 45,000
102,336 122,084 117,343 114,757 114,280 138,173 133,459
430,231 452,248 451,413 440,230 423,449 409,293 572,445
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
$1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239
==========================================================================================================
(6) Includes the effect of credits of $6.7 million to provide tax provision
for fossil generation decommissioning.
(7) Includes the effect of charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(8) Includes the effect of charges of $13.4 million, after-tax, associated
with voluntary early retirement programs.
(9) Amounts for years prior to 1996 were reclassified in 1996.
(10) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(11) Includes the effect of a reorganization charge of $7.8 million,
after-tax.
5
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1998 1997 1996
============================================================================================================================
COMMON STOCK DATA
Average number of shares outstanding 14,017,644 13,975,802 14,100,806
Number of shares outstanding at year-end 14,034,562 13,907,824 14,101,291
Earnings(loss) per share (average) - basic $3.20 $3.10 $2.88
Earnings(loss) per share (average) - diluted $3.20 $3.09 $2.87
Book value per share $31.74 $31.35 $31.16
Average return on equity
Total 9.44% 10.45% 9.20%
Utility 11.43% 11.54% 11.51%
Dividends declared per share $2.88 $2.88 $2.88
Market Price:
High $53.750 $45.938 $39.750
Low $42.625 $24.500 $31.375
Year-end $51.500 $45.938 $31.375
============================================================================================================================
Net cash provided by operating activities,
less dividends ($000's) $74,812 $131,192 $120,625
Capital expenditures, excluding AFUDC $38,040 $33,436 $47,174
============================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 1,924,724 1,899,284 1,895,804
Commercial 2,324,507 2,248,974 2,263,056
Industrial 1,154,935 1,168,470 1,143,410
Other 48,166 48,619 48,388
------------- ------------- ----------------
Total 5,452,332 5,365,347 5,350,658
------------- ------------- ----------------
Number of retail customers by class (average)
Residential 281,591 280,283 279,024
Commercial 29,468 29,228 28,666
Industrial 1,752 1,697 1,652
Other 1,172 1,163 1,141
------------- ------------- ----------------
Total 313,983 312,371 310,483
------------- ------------- ----------------
Revenue per kilowatt hour by class (cents)
Residential 13.66 13.65 14.03
Commercial 10.96 11.05 11.67
Industrial 8.85 8.79 9.54
Average large industrial customers time of
use rate (cents) 8.16 8.12 8.26
System requirements (MWh) 5,728,222 5,631,296 5,640,957
Peak load - kilowatts 1,142,670 1,173,160 1,044,620
Generating capability- peak(kilowatts) 1,323,380 1,356,100 1,522,350
Load factor 57.23% 54.80% 61.64%
Fuel generation mix percentages
Coal 21 44 38
Oil 46 15 8
Nuclear 23 25 37
Cogeneration 6 9 9
Gas 0 2 3
Hydro 4 5 5
- ----------------------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $629,446 $620,636 $643,344
Base rate adjustments 2,161 1,697 7,770
Sales provision adjustment 0 0 0
------------- ------------- ----------------
Total $631,607 $622,333 $651,114
------------- ------------- ----------------
Revenues - retail sales per kWh (cents)
Base 11.54 11.57 12.02
Base rate adjustments 0.04 0.03 0.15
Sales provision adjustment 0.00 0.00 0.00
------------- ------------- ----------------
Total 11.58 11.60 12.17
------------- ------------- ----------------
Fuel and energy cost per kWh (cents) 2.04 1.95 1.69
Fossil 2.60 2.39 2.41
Nuclear 0.58 0.61 0.46
- ----------------------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,193 1,175 1,287
Total payroll($000 'S) $65,294 $68,640 $69,276
============================================================================================================================
(1) Includes reclassification of certain Commercial and Industrial customers.
6
1995 1994 1993 1992 1991 1990 1989
==========================================================================================================
14,089,835 14,085,452 14,063,854 13,941,150 13,899,906 13,887,748 13,887,748
14,100,091 14,086,691 14,083,291 14,033,148 13,932,348 13,887,748 13,887,748
$3.60 $3.09 $2.57 $3.76 $3.67 $3.55 ($5.87)
$3.59 $3.08 $2.56 $3.74 $3.66 $3.55 ($5.87)
$31.16 $30.39 $30.06 $30.12 $28.84 $27.35 $26.11
11.84% 10.19% 8.45% 12.67% 13.01% 13.39% -18.88%
13.04% 12.50% 10.97% 14.46% 13.39% 13.97% 20.21%
$2.82 $2.76 $2.66 $2.56 $2.44 $2.32 $2.32
$38.500 $39.500 $45.875 $42.000 $39.125 $34.125 $34.250
$29.500 $29.000 $38.500 $34.125 $30.000 $26.875 $24.750
$37.375 $29.500 $40.250 $41.500 $39.000 $31.125 $34.250
==========================================================================================================
$120,033 $94,807 $104,547 $109,020 $73,865 $39,189 $31,437
$59,363 $63,044 $94,743 $66,390 $63,157 $64,018 $77,041
==========================================================================================================
1,890,575 1,892,955 1,844,041 1,799,456 1,851,447 1,826,700 1,883,363
2,273,965 2,285,942 (1) 2,359,023 2,303,216 (1) 2,347,757 2,259,340 2,254,099
1,126,458 1,135,831 (1) 1,036,547 997,168 (1) 980,071 1,060,751 1,109,119
48,435 48,718 50,715 52,984 55,118 58,013 60,427
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
5,339,433 5,363,446 5,290,326 5,152,824 5,234,393 5,204,804 5,307,008
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
278,326 275,441 273,752 273,936 274,064 275,637 276,385
28,550 28,394 (1) 28,968 28,848 (1) 29,768 29,808 29,526
1,599 1,538 (1) 959 1,017 (1) 268 319 347
1,122 1,127 1,175 1,358 1,361 1,352 1,316
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
309,597 306,500 304,854 305,159 305,461 307,116 307,574
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
13.79 13.33 12.92 12.58 12.25 11.60 10.89
11.42 10.97 10.88 11.00 10.89 10.39 9.75
9.50 9.18 9.40 9.73 9.38 8.91 8.37
8.53 8.69 8.89 8.84 8.64 8.06 7.58
5,647,690 5,652,657 5,630,581 5,475,664 5,541,477 5,501,495 5,603,502
1,156,740 1,130,780 1,114,900 1,034,440 1,145,820 1,054,600 1,094,400
1,434,102 1,462,290 1,515,420 1,402,800 1,474,190 1,449,600 1,289,800
55.74% 57.07% 57.65% 60.26% 55.21% 59.55% 58.45%
37 35 31 34 34 43 39
7 14 16 17 21 24 37
37 32 38 35 29 20 11
9 9 8 8 9 9 9
5 4 1 1 4 3 3
5 6 6 5 3 1 1
- ----------------------------------------------------------------------------------------------------------
$637,219 $619,097 $605,887 $608,176 $607,997 $589,346 $577,611
1,889 (229) (2,328) (41,221) (37,497) (45,900) (49,778)
0 0 0 21,031 14,814 8,211 0
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
$639,108 $618,868 $603,559 $587,986 $585,314 $551,657 $527,833
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
11.93 11.54 11.45 11.80 11.62 11.32 10.88
0.04 0.00 (0.04) (0.80) (0.72) (0.88) (0.93)
0.00 0.00 0.00 0.41 0.28 0.16 0.00
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
11.97 11.54 11.41 11.41 11.18 10.60 9.95
- -------------- ------------ ------------- ------------ ------------ ------------ ------------
1.71 1.76 1.75 2.43 2.67 2.63 2.78
2.22 2.14 2.08 2.98 3.11 2.89 2.98
0.85 0.94 1.23 1.42 1.62 1.55 0.89
- ----------------------------------------------------------------------------------------------------------
1,358 1,377 1,490 1,554 1,571 1,587 1,627
$72,984 $75,441 $75,305 $74,052 $71,888 $69,237 $65,175
==========================================================================================================
7
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company originally filed its Annual Report on Form 10-K with the
Securities and Exchange Commission (SEC) on March 11, 1999. Subsequent to that
filing, in conjunction with a review of the Company's disclosure statements with
respect to becoming a holding company, the SEC has requested, and the Company
has agreed, to restate the effects of several one-time items taken in 1996, 1997
and 1998 over different time periods. Through year-end 1998, the cumulative
effect of these changes, which are detailed in Note (Q), "Restatement of
Financial Results", is zero. The following discussion, as well as all financial
tables and statements throughout the 10-K, have been modified to reflect these
changes.
The Company's financial condition will continue to be dependent on the
level of its retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Total operation and maintenance expense, excluding
one-time items and cogeneration capacity purchases, declined by 1.1 percent, on
average, during the past 5 years. There will be significant changes to operation
and maintenance expense and other expenses in 1999, partly as a result of the
Generation Asset Divestiture (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 Rate Plan). The DPUC did not change the existing retail
base rates charged to customers; but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The 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 Rate Plan, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Also as a result of the Rate Plan,
customer prices are required to be reduced by an additional 1% in 2000, and
another 1% in 2001, compared to 1996. Retail revenues have decreased by
approximately 4.8% through 1998 compared to 1996 due to customer price
reductions. The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act described below, the Rate
Plan may be reopened and modified. However, aside from implementing an
additional price reduction in 2000 to achieve the minimum 10% price reduction
required by the Restructuring Act and the probable reductions in the accelerated
amortizations scheduled in the Rate Plan, the Company is unable to predict, at
this time, in what other respects the Rate Plan may be modified on account of
this legislation.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from
8
among competing licensed suppliers, for delivery over the wires system of the
franchised Distribution Company. Commencing no later than mid-1999, Distribution
Companies will be required to separate on consumers' bills the charge for
electricity generation services from the charge for delivering the electricity
and all other charges. On July 29, 1998, the DPUC issued the first of what are
expected to be several orders relative to this "unbundling" requirement, and has
now reopened its proceeding to consider the amount of the generation services
charge to be included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to certain adjustments, at least 10%
below its fully bundled prices for electricity at rates in effect on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments, to be the total rate charged under the standard offer, including
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment charge.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of other
above-market generation costs eligible for the competitive transition
assessment, such as regulated plant costs and tax-related regulatory assets or
other costs related to the restructuring transition, such that there will be no
net income effect of the sale. Net cash proceeds from the sale are expected to
be in the range of $160-$165 million. The Company anticipates using these
proceeds to reduce debt.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
9
On October 1, 1998, in its "unbundling plan" filing with the DPUC under the
Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. In order
to mitigate the financial risk that these regulated service mandates will pose
to the Company in an unregulated power generation environment, its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates, effective July 1, 2000, as permitted by the Restructuring Act. This
clause, similar to and based on the purchased gas adjustment clauses used by
Connecticut's natural gas local distribution companies, would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay competitive market rates for power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
The Restructuring Act provides for the Distribution Company to recover its
reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
other state and federal agencies, and the Company's common stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order anticipated sufficient
income in 2000 to accelerate amortization of regulatory assets of about $50
million, equivalent to about 8% of retail revenues. Substantially all of this
accelerated amortization may have to be eliminated to allow for the additional
standard offer price reduction requirement of 10%, at a minimum, while providing
for the added costs imposed by the restructuring legislation. The legislation
does prescribe certain bases for adjusting the price of standard offer service
if the 10% minimum price reduction cannot be accomplished.
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
10
service rates and to establish regulatory assets on its balance sheet for such
costs. The effects of competition or a change in the cost-based regulatory
structure could cause the operations of the Company, or a portion of its assets
or operations, to cease meeting the criteria for application of these accounting
rules. The Company expects to continue to meet these criteria in the foreseeable
future. The Restructuring Act enacted in Connecticut in 1998 provides for the
Company to recover in future regulated service rates previously deferred costs
through ongoing assessments to be included in such rates. If the Company, or a
portion of its assets or operations, were to cease meeting these criteria,
accounting standards for businesses in general would become applicable and
immediate recognition of any previously deferred costs, or a portion of deferred
costs, would be required in the year in which the criteria are no longer met, if
such deferred costs are not recoverable in that portion of the business that
continues to meet the criteria for the application of SFAS No. 71. If this
change in accounting were to occur, it 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.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as follows:
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year (1) $101.4 $34.5 $9.0 $42.7 $ -
Internally Generated Funds less Dividends (2) 98.4 59.4 57.4 64.4 72.7
Net Proceeds from Sale of Fossil Generation Plants 160.0 - - - -
----- ------ ----- ----- -----
Subtotal 359.8 93.9 66.4 107.1 72.7
Less:
Capital Expenditures (excluding AFUDC) (2) 30.7 34.5 23.4 18.9 23.3
----- ----- ----- ----- -----
Cash Available to pay Debt Maturities and Redemptions 329.1 59.4 43.0 88.2 49.4
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 145.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
----- ----- ------ ----- -----
External Financing Requirements (Surplus) (2) $(34.5) $(9.0) $(42.7) $12.1 $51.1
===== ==== ====== ==== ====
(1) Includes the Seabrook Unit 1 operating deposit, but not restricted cash
of American Payment Systems, Inc.
(2) Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings
and cash flow projections, including the implementation of the
legislative mandate to achieve a 10% price reduction from December 31,
1996 price levels by the year 2000. Connecticut's Restructuring Act,
described at "Major Influences on Financial Condition", requires the
Company to divest itself of its fossil-fueled generating plants prior to
January 1, 2000 and to attempt to divest itself of its ownership
interests in nuclear-fueled generating units prior to January 1, 2004.
This forecast reflects the estimated net after-tax proceeds ($160-$165
million) from a proposed divestiture of fossil-fueled generation plants
on or about April 1, 1999. All of these estimates are subject to change
due to future events and conditions that may be substantially different
from those used in developing the projections.
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 common stock, if necessary. The continued availability of these
methods of financing will be dependent on many factors, including conditions in
the securities markets, economic conditions, and the level of the Company's
income and cash flow.
On 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
11
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.
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.
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 December 31, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
On December 18, 1998, the Company issued and sold $100 million principal
amount of 6% five-year Notes. The yield on the Notes, which were issued at a
discount, is 6.034%; and the Notes will mature on December 15, 2003. The
proceeds from the sale of the Notes were used to repay $66.2 million principal
amount of 6.2% Notes, which matured on January 15, 1999, and for general
corporate purposes.
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and will be paid semi-annually beginning on
August 1, 1999. In addition, on February 1, 1999, the Company converted $98.5
million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds will
be paid semi-annually beginning on August 1, 1999.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 1999. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
December 31, 1998, the Company had no short-term borrowings outstanding under
this facility.
In addition, as of December 31, 1998, one of the Company's subsidiaries,
American Payment Systems, Inc., had borrowings of $6.8 million outstanding under
a bank line of credit agreement.
12
At December 31, 1998, the Company had $101.4 million of cash and temporary
cash investments, including the Seabrook Unit 1 operating deposit, but excluding
restricted cash of American Payment Systems, Inc. This was an increase of $69.4
million from the corresponding balance at December 31, 1997. The components of
this increase, 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 110.0
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments 29.4
- Dividend payments (40.5)
Net cash provided by investing activities, excluding
investment in plant 8.5
Cash invested in plant, including nuclear fuel (38.0)
-----
Net Change in Cash 69.4
-----
Balance, December 31, 1998 $101.4
=====
The Company's long-term debt instruments do not limit the amount of short-term
debt that the Company may issue. The Company's revolving credit agreement
described above requires it to maintain an available earnings/interest charges
ratio of not less than 1.5:1.0 for each 12-month period ending on the last day
of each calendar quarter. For the 12-month period ended December 31, 1998, this
coverage ratio was 3.6:1.0.
SUBSIDIARY OPERATIONS
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement UI's regulated electric utility business and provide long-term
rewards to UI's shareowners.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. It
manages agent networks in 36 states and processed approximately $7.5 billion in
customer payments during 1998, generating operating revenues of approximately
$33.7 million and operating income of approximately $1.7 million. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional buildings, and is participating
in the development of district heating and cooling facilities in the downtown
New Haven area, including the energy center for an office tower and
participation as a 52% partner in the energy center for a city hall and office
tower complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial buildings,
government buildings and industrial facilities. URI's fourth subsidiary, United
Bridgeport Energy, Inc., is participating in a merchant wholesale electric
generating facility being constructed on land leased from UI at its Bridgeport
Harbor Station generating plant.
The after-tax impact of the subsidiaries on the consolidated financial
statements of the Company is as follows:
Assets
Net Income (loss) Earnings at Dec. 31
(000's) per Share (000's)
---------------- --------- ----------
(Basic & Diluted)
1998 $(1,111) $(0.08) $83,306
1997 (2,185) (0.16) 69,338
1996 (5,979) (0.42) 51,827
In 1996 and 1997, the Company made provisions for losses of $3.3 million
(after-tax) and $1.6 million (after-tax), respectively, associated with
collection agent errors and defaults and miscellaneous other items at its
American Payment Systems, Inc. subsidiary.
13
YEAR 2000 ISSUE
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct
deficiencies in its computer systems. This comprehensive program includes all
information technology systems and encompasses systems critical to the
generation, transmission and distribution of electric energy as well as
traditional business systems. Critical systems have been defined as those
business processes, including embedded technology, which if not remediated may
have a significant impact on safety, customers, revenue or regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged and is asking for assurance of their Year 2000
compliance.
An inventory and assessment of the Company's computer system applications,
hardware, software and embedded technologies have been completed, and
recommended solutions to all identified risks and exposures have been generated.
A testing, remediation, renovation, replacement and retirement program has been
in progress since early 1998. Both external and internal resources are being
utilized to accomplish the testing, remediation and renovation efforts. A total
of 383 affected business processes have been identified and 337 of them have
been verified as Year 2000 compliant through testing, remediation, replacement
or retirement. The remediation methodology utilized has been Fixed Windowing,
and totally independent platforms have been installed for testing all of the
applications. Necessary upgrades to mainframe hardware and software were
completed and tested by June 30, 1999. This included a "destructive" mainframe
test performed at an independent site in Ponca City, Oklahoma.
The Company included its operating non-nuclear generation facilities in the
Year 2000 program up to the date of their divestiture on April 16, 1999. At that
point, all related documentation was transferred and delivered to
Wisvest-Connecticut, LLC, the purchaser of these generation facilities. See Note
(C), "Rate-Related Regulatory Proceedings" above, for a description of this
transaction.
As of August 3, 1999 there were 36 business processes remaining to be
determined as Year 2000 ready. Priority one processes are those defined as
affecting safety, reliability, regulatory compliance or having a significant
financial impact. The priority one Customer Services process relates to the
Customer Information System that has been 100% tested but is under continuous
change due to the electric industry restructuring in Connecticut. The
Controller's department has two systems awaiting modification and testing, the
accounts payable system and the general ledger system. All priority one systems
are to be complete by December 31, 1999. Priority two implies that failure of
this software or hardware will present a disruption of service at current budget
levels, but work-arounds with negative implications for current service or cost
levels are available, if needed. Priority three implies that failure of this
software or hardware may present an inconvenience to occasional work
requirements or an impediment to achievement of higher service or lower cost
levels, but alternative work-arounds can be pursued if deemed necessary at some
future date. Priority four implies that failure of this software or hardware
will produce a nuisance or confusion but will not present any direct negative
business consequence. The summary of remaining business processes by department
and priority level is as follows:
Priority 1 Priority 2 Priority 3 Priority 4 Total
Customer Services 1 20 8 1 30
Support Services 0 1 2 0 3
Controller's Department 2 1 0 0 3
Total 3 22 10 1 36
----------------------------------------------------
As of August 3, 1999, the Company had completed the assessment and
remediation phases of its program for these non-priority one business processes,
which are in various stages of the testing and approval process and are
projected to be completed by September 1, 1999. UI has successfully complied
with all regulatory requirements. Most recently, UI successfully completed a
Connecticut Department of Public Utility Control audit along with eight other
utilities in the state. The Company also provides monthly reports to the North
American Electric Reliability Council on the Year 2000 status of its
transmission, distribution, telecommunication and system control and data
acquisition assets.
14
Requests for documented compliance information have been sent to all
critical suppliers, data sharers and facility building owners and, as responses
are received, appropriate solutions and testing programs are being developed and
executed. While failure to achieve Year 2000 compliance by any one of a number
of critical suppliers and data sharers could have some adverse effect on the
success of the Company's implementation program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications providers, the other participants in the New England Power
Pool (NEPOOL), and the Independent System Operator (ISO) that operates the
NEPOOL bulk power supply system. Year 2000 compliance failures by any of these
entities could have a material effect on electricity delivery and telemetering.
In its efforts to mitigate these risks, the Company has taken several actions.
UI has communicated its concerns to its principal telecommunications provider
and a joint effort to design and plan appropriate testing to insure that all
critical telecommunications functions will be operational has commenced. The
Year 2000 Issue is also being addressed at the regional level by NEPOOL and the
ISO. Coordination efforts with NEPOOL to establish utility testing and readiness
are in progress. The Company is a participant in all of the subcommittees
working within NEPOOL/ISO on efforts to assure operational reliability. The
Company is also actively involved with NEPOOL/ISO in the planning effort for
integrated contingency planning, as directed by the North American Electric
Reliability Council (NERC). The first NERC directed test was successfully
completed on April 9, 1999.
Aside from telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant risk to the success of the Company's Year 2000 compliance
implementation program. In order to minimize these risks, the Company will be
actively involved in contingency planning. While the Company's knowledge and
experience in electric system recovery planning and execution has been
demonstrated in the past, the Company recognizes the need for, and importance
of, Year 2000-specific contingency planning, because the complex interaction of
today's computing and communications systems precludes certainty that all
critical system remediation will be successful. High level contingency planning
for essential business processes has been completed. These plans will be
continually reviewed, revised and modified throughout the remainder of the year
as appropriate. As a part of the contingency planning process, consideration
will be given to potential frequency and duration of interruptions in the
generating, financial and communications infrastructures. Since contingency
planning is, by nature, a speculative process, there can be no assurance that
this planning will completely eliminate the risk of material impacts to the
Company's business due to Year 2000 problems. However, the Company recognizes
the importance to its customers of a reliable supply of electricity, and it
intends to devote whatever resources are necessary to assure that both the
program and its implementation are successful.
The Company believes that the successful implementation of this program
should ultimately cost approximately $6.1 million for existing information
systems and embedded technology. A total of $5.2 million had been expended as of
June 30, 1999. As systems testing progresses and more embedded technology vendor
product information is forthcoming, business decisions made and testing results
verified, the need for increased expenditures, if necessary, will be determined.
The Company believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.
NEW ACCOUNTING STANDARDS
See the discussion included in Note (A) of the Notes to Consolidated
Financial Statements, Statement of Accounting Policies.
RESULTS OF OPERATIONS
1998 VS. 1997
- -------------
Earnings for the twelve months of 1998 were $44.9 million, or $3.20 per
share (both basic and diluted), up $1.6 million, or $.11 per share, from the
twelve months of 1997, diluted. Excluding one-time items, accelerated
amortization due to one-time items and associated regulated "sharing" effects,
1998 earnings from operations were $47.8 million, or $3.41 per share, up $.48
per share from 1997. The one-time items and their earnings per share impacts
recorded in these periods are shown at "One-time items recorded in 1997 and
1998" below.
15
Retail operating revenues increased by about $9.3 million in the twelve
months of 1998 compared to 1997. Retail fuel and energy expense increased by
$7.2 million and there was an increase of $0.4 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $1.7 million. The principal components of the
retail sales margin change, year over year, include:
$ millions
------------------------------------------------------------------ ---------
Revenue from:
------------------------------------------------------------------ ---------
DPUC rate order, excluding "sharing" (1.3)
------------------------------------------------------------------ ---------
Other price changes (0.3)
------------------------------------------------------------------ ---------
Estimate of "real" retail sales growth, up 1.3% 12.1
------------------------------------------------------------------ ---------
Estimate of weather effect on retail sales, up 0.2 % 1.8
------------------------------------------------------------------ ---------
Sales decrease from Yale University cogeneration, (0.9) % (3.0)
------------------------------------------------------------------ ---------
Fuel and energy, margin effect:
------------------------------------------------------------------ ---------
Sales increase (2.7)
------------------------------------------------------------------ ---------
Increased nuclear availability 0.4
------------------------------------------------------------------ ---------
Unscheduled outage at Bridgeport Unit 3 (see Note A) (2.5)
------------------------------------------------------------------ ---------
Fossil price and other (2.4)
------------------------------------------------------------------ ---------
Note A: Saltwater contamination caused a shutdown of the Bridgeport
Harbor Unit 3 generating unit on May 22, 1998. The unit
returned to full service on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale energy expense)
increased slightly in the twelve months of 1998 compared to the twelve months of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $5.8 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $15.0 million in the twelve months of 1998 compared to the
twelve months of 1997. The principal components of these expense changes, year
over year, include:
$ millions
------------------------------------------------------------------ ---------
Capacity expense:
------------------------------------------------------------------ ---------
Connecticut Yankee preparing for decommissioning (4.2)
------------------------------------------------------------------ ---------
Cogeneration and other purchases (1.3)
------------------------------------------------------------------ ---------
Other O&M expense:
------------------------------------------------------------------ ---------
Seabrook (4.6)
------------------------------------------------------------------ ---------
Millstone Unit 3 (4.0)
------------------------------------------------------------------ ---------
Fossil generation unit overhauls and outages 7.5
------------------------------------------------------------------ ---------
Pension investment performance and assumptions (3.0)
------------------------------------------------------------------ ---------
Personnel reductions (6.0)
------------------------------------------------------------------ ---------
NEPOOL transmission expense 3.1
------------------------------------------------------------------ ---------
Other (2.5)
------------------------------------------------------------------ ---------
Depreciation expense, excluding accelerated amortization, increased by $1.5
million in the twelve months of 1998 compared to 1997. According to the
Company's current regulatory Rate Plan, "accelerated" amortization of past
utility investments is scheduled for every year that the Rate Plan is in effect,
contingent upon the Company earning a 10.5% return on utility common stock
equity. All of the accelerated amortization in 1997 was recorded in the second
quarter of that year as a result of a one-time gain recorded in that quarter.
All of the accelerated amortization for 1998, $13.1 million, was recorded
against earnings from operations. In addition, as part of the "sharing"
mechanism, the Company would have accrued an additional amortization of about
$2.6 million ($1.7 million after-tax) in 1998 against utility earnings from
operations. Because of the one-time items in 1998, no "sharing" was actually
recorded. The one-time charge for property tax expense incurred in the fourth
quarter was a utility expense and negated the "sharing" that would have occurred
from operations.
Other net income from operations decreased by about $1.9 million in the
twelve months of 1998 compared to 1997. The Company's largest unregulated
subsidiary, American Payment Systems, Inc. (APS), earned about $1.6 million
(before-tax) in 1998 compared to a $2.7 million loss in 1997. This was more than
offset by greater losses,
16
compared to 1997, in the Company's other unregulated subsidiaries: $1.2 million
(before-tax) at Precision Power, Inc. from the write-off of previously deferred
costs and a review of reserves, and $1.2 million (before-tax) from start-up
costs in other unregulated activities. By DPUC order, since consolidation at the
unregulated subsidiary level produced no net taxable income in either year, the
tax benefits associated with the losses, about $0.8 million in 1998 and $0.4
million in 1997, were treated as benefits to utility income for the purposes of
calculating return on utility common equity and "sharing". Other net income also
decreased due to the absence of other non-utility income accruals of about $1
million made in 1997 that reversed a provision for 1997 Millstone 3 expense made
in 1996 and charged to operating expenses in 1997, cancelled project costs of
about $0.8 million for merger and acquisition advisor fees and analysis and
lower income from non-operating utility investments.
Interest charges, excluding allowance for borrowed funds used during
construction, continued on their downward trend, decreasing by $10.4 million in
the twelve months of 1998 compared to 1997, as a result of the Company's
refinancing program and strong cash flow.
OVERVIEW OF "SHARING" AND THE IMPACT ON EARNINGS
- ------------------------------------------------
As previously indicated, the Company's regulatory Rate Plan requires a
"sharing" of regulated utility income that produces a return on utility equity
exceeding 11.5%. The measurement of this utility income and resulting return
calculation includes the effects of any utility one-time items. Under the Rate
Plan, one-third of the income above the 11.5% return 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.
Earnings from operations, which excludes the impact of one-time items,
should reflect an appropriate imputed amount of "sharing" to reflect accurately
what the earnings would have been had neither the one-time items, nor their
impact on "sharing", occurred. The Company estimates that the "sharing" that
would have occurred had there been no one-time items in 1998 would have been: a
revenue reduction of about $3.0 million or $.12 per share, increased
amortization of about $1.7 million (after-tax) or $.12 per share, and retention
by the Company of $1.7 million of income (after-tax) or $.12 per share. To
summarize for 1998:
1998 Earnings per share (EPS) From One-time
Operations Items
and and "Sharing"
"Sharing" Reversals Total
--------- ------------- -----
Utility earnings before "sharing" $3.73 $(.45) $3.28
Less: Utility earnings to be "shared" (.36) .36 -
----- --- ----
Utility EPS at 11.5 percent utility return $3.37 $(.09) $3.28
Plus: 1/3 Retained "Sharing" benefit .12 (.12) -
---- ---- ----
Net Utility EPS 3.49 (.21) 3.28
Unregulated Subsidiaries (.08) - (.08)
---- ----- ----
Total 1998 EPS $3.41 $(.21) $3.20
Earnings reported through 3rd quarter 3.02 (.12) 2.90
---- ----- ----
Imputed 4th quarter earnings $ .39 $(.09) $ .30
===== ===== =====
17
ONE-TIME ITEMS RECORDED IN 1997 AND 1998
- ----------------------------------------
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Cumulative deferred operating income tax benefits associated $ .48
with future Decommissioning of fossil fuel generating plants
(see Note F)
- --------------------------------------------------------------------------------
1997 Accelerated amortization associated with one-time item $(.30)
- --------------------------------------------------------------------------------
1997 Gain from subleasing office space $ .05
- --------------------------------------------------------------------------------
1997 Pension benefit adjustments associated with 1996 VERP and VSP $ .11
- --------------------------------------------------------------------------------
1997 Contract termination charge $(.18)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1998 Refund of prior period transmission charges, with interest $ .14
"Sharing" due to one-time items recorded through third quarter $(.05)
- --------------------------------------------------------------------------------
1998 Property tax settlement with the City of New Haven, CT $(.59)
Reversal of "sharing" imputed to property tax settlement $ .29
- --------------------------------------------------------------------------------
The most significant one-time item recorded in 1997 was a gain from an
operating income tax expense reduction of $6.7 million, or $.48 per share, which
makes provision for the cumulative deferred tax benefits associated with the
future decommissioning of fossil fuel generating plants for which the Company
had made provision in prior years without accruing the tax benefit. By order of
the DPUC, the Company was instructed to accelerate the amortization of
regulatory assets by as much as $6.4 million ($4.1 million after-tax), or $.30
per share, provided that the 1997 return on utility common stock equity would
exceed 10.5% for the year. As a result of the tax benefit, the full $6.4 million
was charged in 1997.
Additional 1997 one-time items included: a $.05 per share gain related to
subleasing office space; a "curtailment" gain of $2.5 million ($1.5 million
after-tax), or $.11 per share, related to forgone pension benefits associated
with the approximate 230 employees who left the Company as a result of 1996
voluntary retirement and separation programs; and a charge of $4.3 million ($2.5
million after-tax), or $.18 per share, for early termination of a contract with
consultants that assisted the Company with its restructuring efforts, after the
Company determined that the early termination option was more economic than the
multi-year performance-based payout option. All of these one-time items were
recorded as "Operating Expense - Operations - other".
As reported in its Quarterly Report on Form 10-Q for the period ending
March 31, 1998, filed with the Securities and Exchange Commission, the Company
had been investigating potential errors in the accounting procedure of APS. As a
result of the investigation, the Company determined that APS should create
additional reserves for shortfalls in agent collections and other potentially
uncollectible receivables of $4.9 million. The Company has restated its 1997 and
1996 earnings to provide for the reserves. See Note (Q), "Restatement of
Financial Results".
The principal business of APS is to operate a network of field agents for
the purpose of accepting cash and check payments of a utility's bills and
forwarding those payments, through APS accounts, to the utility. APS experienced
rapid growth in 1996 and 1997. The number of agents in the APS network increased
from 2,537 in 1995 to 4,904 in 1997; and the dollar volume of payment
transactions increased from $2.3 billion on 17.2 million transactions in 1995 to
$7.5 billion on 73.2 million transactions in 1997.
At year-end 1996, APS created a reserve to provide for losses associated
with agent collections and uncollectible check deposits totaling $4.4 million
before-tax. The Company has restated its 1996 earnings to move a small portion
of this loss to 1995. See Note (Q), "Restatement of Financial Results". These
losses stemmed from inadequate "back-office" banking systems and controls that
failed to detect a significant amount of deposit shortfalls from agents and
failed to identify a substantial number of uncollectible check deposits that
were reimbursable from the utilities serviced.
In 1997, under new management with added banking expertise, APS began
implementing new systems and controls to manage the agent collection/deposit
process. These changes included the increased use of daily cash reporting and
account reconciliation on high volume agents, extensive reconciliation
procedures, and agent monitors that interact daily with agents to investigate
discrepancies in deposits. These new procedures were fully implemented by the
4th quarter of 1997.
18
In March of 1998, APS contracted for an insurance policy with an A+ rated
carrier to protect against future losses from robberies, missing deposits, and
agent fraud. The effect of the policy is to "cap" the cost of such losses at
$200,000 per event per agent. The level of detected agent fraud in 1998 was well
below that level, averaging $23,000 per month in total, or .004% of the monthly
transaction dollar volume.
Also in 1998, APS implemented new procedures to correct difficulties in
tracking agent deposits in bank mergers or acquisitions situations. During this
process, it was discovered that certain large agent depository bank accounts
were not reconciled appropriately and that the amount of APS working capital
invested in the agent depository accounts to cover timing delays for cash
transfers was over-estimated and the amount due to utilities underestimated.
These cash flow discrepancies were masked by the rapid growth of cash deposits
from the expansion in the agent network and the failure to properly take into
account the cash effects of uncleared bank transfers from agent depository
accounts to utilities. APS accounting procedures, which failed to detect the
cash flow discrepancies, have been rectified.
The one-time gain recorded in the third quarter of 1998 was to record a
refund of prior period transmission charges. It amounted to $3.4 million or $.14
per share, but was recorded as two separate items; $1.8 million, or a gain of
$.07 per share, as a credit to operation expense and $1.6 million, or $.07 per
share, of interest income recorded as Other Income and (Deductions), Other-net.
At the time this one-time item was recorded, in the third quarter of 1998, the
Company estimated that it would be in the Rate Plan "sharing" range of earnings
for the year of 1998 in total, and recorded, therefore, a "sharing" revenue
reduction and increased amortization expense to reflect that estimate. The
"sharing" related to the utility portion of this one-time item, the operation
expense credit, was a charge of $.05 per share. The net result of the one-time
gain for the period was, therefore, $.09 per share. The one-time charge recorded
in the fourth quarter of 1998 as property tax expense of $14 million, or $.59
per share, reflected the DPUC's rejection of the Company's proposed accounting
treatment of a property tax settlement between the Company and the City of New
Haven. Upon that rejection, the Company was required to write-off immediately
the full effect of that settlement. As a result of this one-time charge, the
Company's final 1998 earnings results eliminated the requirement to record any
Rate Plan "sharing" in 1998. The one-time charge eliminated "sharing" revenue
reductions and increased amortization expense amounting to $.29 per share. The
net result of the one-time charge for the period was, therefore, $.30 per share.
See Note (L), Commitments and Contingencies Other Commitments and Contingencies
- - Property Taxes.
1997 VS. 1996
- -------------
Earnings for the twelve months of 1997 were $43.3 million, or $3.10 basic,
and $3.09 diluted, earnings per share, up $2.7 million, or $.22 per share
diluted, from 1996. Earnings from operations, which exclude one-time items and
accelerated amortization of costs attributable to one-time items, decreased by
$12.0 million, or $.82 per share, in 1997 compared to 1996, to a level of $2.93
per share, diluted. The one-time items recorded in 1996, which amounted to a net
loss of $.88 per share were: charges to operating expenses of $23.0 million
($13.4 million after-tax), or $.95 per share, from early retirement and
voluntary severance programs and $1.4 million ($0.8 million after-tax), or $.06
per share, for the cumulative loss on an office space sublease, and a gain of
$1.8 million (after-tax), or $.13 per share, from the repurchase of preferred
stock at a discount to par value.
Retail operating revenues decreased by about $28.8 million in 1997 compared
to 1996:
o A retail kilowatt-hour sales increase of 0.3% from the prior year increased
retail revenues by $1.8 million and sales margin (revenue less fuel expense
and revenue-based taxes) by $1.3 million. The Company believes that weather
factors had a negative impact on retail kilowatt-hour sales of about 0.5
percent. There was one less day in 1997 (1996 was a leap year), which
decreased retail kilowatt-hour sales by 0.3 percent. This would indicate
that "real" (i.e. not attributable to abnormal weather or the leap year day
in 1996) kilowatt-hour sales increased by about 1.0-1.5 percent for the
year.
o Reductions in customer bills, as agreed to by the Company and the DPUC in
December 1996, decreased retail revenues by about $23.0 million, including
suspension of the fossil fuel adjustment clause (FAC) mechanism that
reduced revenues by $6.0 million. This was a somewhat greater decrease than
expected, principally because of a decrease in conservation spending and
the corresponding decrease in conservation revenues. Other reductions in
customer bills, due to rate mix, contract pricing and other pass-through
reductions, amounted to $7.6 million.
19
Wholesale "capacity" revenues increased $2.1 million in 1997 compared to
1996. Wholesale "energy" revenues, which increased during 1997 compared to 1996
as a result of nuclear generating unit outages in the region, are a direct
offset to wholesale energy expense and do not contribute to sales margin.
Retail fuel and energy expenses increased by $14.2 million in 1997 compared
to 1996. These expenses increased by $12.6 million due to the need for more
expensive energy to replace generation by nuclear generating units: for the
Connecticut Yankee unit, which ran at nearly full capacity in the first six and
one-half months of 1996, for Millstone Unit 3, which ran at nearly full capacity
in the first quarter of 1996, for an unplanned eight-day extension of a Seabrook
unit refueling outage in the second quarter of 1997 that increased the Company's
replacement generation cost by about $0.7 million, and for an unplanned Seabrook
unit outage that began on December 5, 1997. The Seabrook unit was returned to
service from the last outage on January 17, 1998. Millstone Unit 3 was taken out
of service on March 30, 1996 and Connecticut Yankee was taken out of service on
July 23, 1996. Retail fuel and energy expenses also increased by about $1.6
million in 1997 compared to 1996, due to higher fossil fuel prices. By order of
the DPUC, these costs are not passed on to customers through the FAC.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $1.7 million, excluding the impact of one-time items, in
1997 compared to 1996:
o Purchased capacity expense decreased $6.9 million, due to declining costs
from the retired Connecticut Yankee nuclear generating unit, and also due
to slightly lower cogeneration costs.
o Operation and maintenance expense increased by $5.1 million. General,
refueling and unscheduled outage expenses at the Seabrook nuclear
generating unit increased about $2.9 million, and general expenses at the
Millstone 3 nuclear generating unit increased $4.8 million. Expenses
associated with the Company's re-engineering efforts increased by a net
$1.0 million. Other general expenses increased by about $2.9 million. These
increases were partly offset by a $4.6 million reduction in pension expense
due to investment performance and changes in actuarial assumptions and
methodologies, and health benefit reductions of $1.9 million. The increase
at Millstone Unit 3 was partly offset by the reversal of a portion of a
1996 provision in "Other income (deductions)".
Depreciation expense, excluding the impact of one-time items, increased by
$2.3 million in 1997 compared to 1996. Income taxes, exclusive of the effects of
one-time items, changed based on changes in taxable income and tax rates.
Other net income increased by $9.8 million in 1997 compared to 1996 due,
principally, to an improvement in earnings (reduction in losses) from
unregulated subsidiaries. The Company's largest unregulated subsidiary, American
Payment Systems, lost about $2.7 million (before-tax) in 1997, an improvement of
$6.8 million over 1996 losses of about $9.5 million. Other UI subsidiaries lost
$1.0 million ($0.6 million after-tax) compared to a loss of $0.2 million in
1996. The remainder of the improvement in other net income was due to an
increase of $0.8 million in interest income and $2.4 million from the reversal
of an accrual taken in 1996 for Millstone 3 expense of $1.2 million.
Interest charges continued their significant decline, decreasing by $7.5
million, or 11 percent, in 1997 compared to 1996 as a result of the Company's
refinancing program and strong cash flow. Also, total preferred dividends
(net-of-tax) decreased slightly in 1997 compared to 1996 as a result of
purchases of preferred stock by the Company in 1996.
Early retirement and voluntary severance programs
- -------------------------------------------------
On May 22, 1995, the Company and the union representing approximately 695
of its operating maintenance and clerical employees agreed on a three-year
contract, effective May 16, 1995. As part of this agreement, the Company offered
a voluntary early retirement program to 74 employees, who had until January 31,
1996 to accept. The early retirement offer was accepted by 64 employees, and the
Company recognized a charge to earnings in January 1996 of $7.2 million ($4.2
million, after-tax). The employees accepting the offer retired during the first
nine months of 1996. In June 1996, the Company recognized an additional charge
to earnings of $0.9 million ($0.5 million, after-tax) to reflect additional
early retirement costs. In July 1996, the Company offered a Voluntary Early
Retirement Program and a Voluntary Separation Plan to virtually all of its
employees. A total of 163 employees accepted one or the other of these plans. In
the third quarter of 1996, the Company recognized a charge to earnings of $14.9
million
20
($8.7 million, after-tax) to reflect the cost of these plans. The employees
accepting the offer retired on or before December 31, 1997.
These programs should result in a reduction of 230 employees from a level
of approximately 1,300 employees at year-end 1996. A portion of the personnel
cost savings began in 1996, but the majority of the savings will be realized as
the Company's process re-engineering efforts are completed over the next several
years. Incremental annual savings in personnel costs of $4 million in 1997 and
another $6 million in 1998 are expected
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year rate plan and restructuring legislation
- -------------------------------------------------
The reader is referred to "Major Influences on Financial Condition", above,
for a description of the Company's five-year Rate Plan and Connecticut's
electric utility industry restructuring legislation.
1999 Earnings
- -------------
1999 will be a year of transition to the January 1, 2000 effective date of
electric utility restructuring legislation passed by the Connecticut legislature
in 1998. The Company has taken one major step toward restructuring by proceeding
with the sale of its fossil fuel generation plants...referred to as the
Generation Asset Divestiture (GAD). That sale is expected to close on or about
April 1, 1999.
One result of the generation plant sale will be a reduction in the
Company's electric utility rate base, the basis for measuring return on utility
common stock equity. Rate base is expected to decline from an average of $1,128
million in 1998 to about $920 million in 1999. Offsetting the decline is the
Company's longstanding policy of debt paydown that increases the portion of rate
base financed by equity. During 1998, a return of 11.5% on utility common stock
equity would have produced earnings of about $3.43 per share. Utility earnings
from operations above this range would have given rise to an imputed "sharing"
benefit of $.12 per share. Because of the rate base reduction expected in 1999,
the allowed return is expected to produce utility earnings in the $3.35-$3.40
per share range. Currently, the Company expects to be in a Rate Plan "sharing"
position in 1999, to a somewhat greater extent than was the case for earnings
from operations in 1998.
The Company's earnings from its utility business are affected principally
by: retail sales that fluctuate with weather conditions and economic activity,
nuclear generating unit availability and operating costs, and interest rates.
These are all items over which the Company has little control, although the
Company engages in economic development activities to increase sales, and hedges
its exposure to volatility in interest rates.
The Company's revenues are principally dependent on the level of retail
electricity sales. The two primary factors that affect the volume of these
retail sales are economic conditions and weather. The Company's retail sales for
1998 of 5,452 gigawatt-hours set an all-time record for the Company and were up
1.4% from the 1997 level.
The Company estimates that mild 1998 weather reduced retail kilowatt-hour
sales by about 0.5%, retail revenues by about $3.4 million, and retail sales
margin by about $2.7 million. Weather corrected retail sales for 1998 were
probably in the 5,470-5,500 gigawatt-hour range. On this weather-adjusted basis,
the Company experienced about 1.0-1.5% of "real" sales growth in 1998 over
weather-adjusted 1997 sales, with most of the growth appearing to occur in the
first three quarters of the year.
Aside from "real" economic growth, reductions in retail electricity sales
will occur in 1999 compared to 1998 as a result of the operation of a
cogeneration unit at Yale University that produces approximately one half of
Yale's annual electricity requirements (about 1.5% of the Company's total 1998
retail sales). This unit commenced operations in mid-1998, and has reduced total
Company retail kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The
remaining impact will be reflected in the first half of 1999. Thus, it would
require "real" growth of 0.5 percent in 1999 compared to 1998 just to maintain
the 1998 level of "real" sales. Retail kilowatt-hour sales growth of 1.0%
produces a margin improvement of about $5.0 million, before any "sharing" effect
considerations.
21
Prices in individual customer rate classes will not change in 1999 relative
to 1998, exclusive of any "sharing". However, sales growth is occurring in rate
classes with higher than average prices, and the Company expects to have an
increase in retail revenue of about $3.0 million in 1999 compared to 1998 from
this price mix improvement.
Other operating revenues are expected to increase as a result of NEPOOL
related transmission revenues by about $4.0 million due to NEPOOL restructuring
changes; but this would have no net income effect as the higher revenues are due
to higher transmission operating expense. Other than the NEPOOL impact, these
revenues are expected to decrease by about $2 million to a more normal level.
The Company does not anticipate, at this time, any other significant revenue
reductions in 1999 retail revenues compared to 1998, unless the Company is
achieving a "sharing" level of earnings.
As a result of GAD, wholesale capacity revenues will decrease by about $7.7
million in 1999 compared to 1998, because existing wholesale sales contracts
were part of the asset sale. Also as a result of GAD, the Company's fuel and
purchased energy charges will increase in 1999 compared to 1998 by about $40
million, to replace the power previously provided by the Company's fossil-fueled
generation plants. This power supply purchase agreement was part of the GAD
plant sale and it will help to ensure adequate resources to meet customer energy
demands under a short-term fixed price agreement until July 2000 (the price
declines somewhat in 2000 compared to 1999) when all customers will have a
choice of generation suppliers. The Company expects that its projected 1999
energy requirements that are not met by the GAD power supply purchase agreement
will be met at lower prices than those experienced in 1998, primarily because of
lower projected fossil fuel prices and energy prices in general. This is
expected to result in energy cost savings of about $5 million.
Purchased capacity costs should decrease by about $2 million in 1999, due
primarily to the retirement of the Connecticut Yankee nuclear generation plant.
Several other expense categories are expected to be reduced substantially
in 1999 because of GAD and the Company's other cost reduction efforts,
offsetting the impact of the increase in purchased energy. Operation and
maintenance expense is projected to decrease by a net $22 million, reflecting a
decrease of $32 million due to GAD and other general changes, partly offset by
increases of about $5 million for nuclear unit refueling outages, $1 million for
Y2K costs and $4 million due to NEPOOL transmission charges. The latter would
have no net income effect, as the higher transmission expense would be covered
by higher transmission revenues. Total Y2K costs for 1999 are currently
projected at about $3.6 million. Other operation and maintenance expenses in
1999 should be fairly stable compared to 1998, unless an event occurs that
cannot be predicted at this time.
Interest costs are expected to decline by about $14 million in 1999
compared to 1998, to about $38 million, a level that was last experienced in
1982. This anticipated interest cost reduction will result largely from debt
paydown through use of the after-tax cash proceeds from GAD. The Company also
expects to generate substantial cash flow from operations after dividend and
capital spending, that will also be used to pay down debt.
Depreciation, excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to GAD but also from the near
completion in 1998 of amortization of previously capitalized conservation
program expenditures. A significant portion of the decrease in depreciation
related to GAD will not affect taxable income and will not increase income
taxes, and will therefore supplement the $13 million decrease with an additional
tax benefit, comparing 1999 to 1998, of about $2.5 million, or $.18 per share.
Accelerated amortization, per the Rate Plan, will increase by about $7
million in 1999 compared to 1998. Property taxes should decrease by about $2
million, due mostly to GAD. Other operating expenses can be expected to have
some increases and some decreases that should, more or less, offset one another.
In summary, the Company expects substantial net expense reductions as a
result of GAD and ongoing cost control measures that should more than compensate
for increased charges for purchased power and increased accelerated amortization
costs in 1999. Such performance should allow utility earnings to increase above
an 11.5% return on common stock equity into the Rate Plan "sharing" range. The
11.5% return level would produce utility earnings from operations of about
$3.35-$3.40 per share, while the "shared" earnings benefit is currently
anticipated to contribute about $.20 per share, although the size of this
benefit will fluctuate with every event that affects utility operations during
the year. The Company expects that 1999 quarterly earnings from operations will
follow a pattern similar to that of 1998 on a weather-normalized basis.
22
Unregulated subsidiaries are expected to experience a loss of up to $.10
per share to earnings in 1999. American Payment Systems, Inc. is expected to
build on 1998's contribution to earnings from operations of $.07 per share.
However, this will depend on its ability to expand sales to its utility
customers. Precision Power, Inc. (PPI) increased its organizational
infrastructure in 1998, also in an effort to increase its presence in its
principal markets of distributed power systems and services. At its current
level of expense, PPI would lose $.10 to $.15 per share in 1999 if no
substantial new contracts are obtained. PPI may also engage in acquisition
activities in 1999 that may have short-term dilutive effects on earnings beyond
those indicated above.
As a result of the earnings contributions anticipated from all of its
different business activities described above, the Company expects earnings per
share from operations to be in the range of $3.45 to $3.65 in 1999. These
estimates are subject to all of the contingencies and uncertainties detailed in
the preceding discussion and the reader is cautioned to read the "Looking
Forward" and "Major Influences on Financial Condition" sections in their
entirety.
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
1998 1997 1996
---- ---- ----
OPERATING REVENUES (NOTE G) $686,191 $709,029 $727,258
------------- ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 151,544 182,666 160,517
Capacity purchased 34,515 39,976 46,830
Early retirement program charges - - 23,033
Other 146,058 158,600 158,945
Maintenance 42,888 42,203 37,652
Depreciation (Note G) 82,809 74,618 65,921
Amortization of cancelled nuclear project and deferred return (Note D and J) 13,758 13,758 13,758
Income taxes (Note A and F) 53,619 40,833 53,590
Other taxes (Note G) 64,674 52,493 57,186
------------- ------------ ------------
Total 589,865 605,147 617,432
------------- ------------ ------------
OPERATING INCOME 96,326 103,882 109,826
------------- ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 13 336 940
Other-net (Note G) 1,097 1,361 (8,445)
Non-operating income taxes 3,848 3,678 9,869
------------- ------------ ------------
Total 4,958 5,375 2,364
------------- ------------ ------------
INCOME BEFORE INTEREST CHARGES 101,284 109,257 112,190
------------- ------------ ------------
INTEREST CHARGES
Interest on long-term debt 50,129 63,063 66,305
Interest on Seabrook obligation bonds owned by the company (7,293) (6,905) (1,259)
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other interest (Note G) 6,507 3,280 2,092
Allowance for borrowed funds used during construction (455) (1,239) (1,435)
------------- ------------ ------------
53,701 63,012 70,516
Amortization of debt expense and redemption premiums 2,511 2,788 2,629
------------- ------------ ------------
Net Interest Charges 56,212 65,800 73,145
------------- ------------ ------------
NET INCOME 45,072 43,457 39,045
Discount on preferred stock redemptions (21) (48) (1,840)
Dividends on preferred stock 201 205 330
------------- ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $44,892 $43,300 $40,555
============= ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,018 13,976 14,101
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,023 13,992 14,131
EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.20 $3.10 $2.88
============= ============ ============
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.20 $3.09 $2.87
============= ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.88
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
24
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 1998, 1997 and 1996
(Thousands of Dollars)
1998 1997 1996
----- ----- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $45,072 $43,457 $39,045
------------ ------------ ------------
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 88,099 79,487 70,363
Deferred income taxes 3,074 6,804 (2,813)
Deferred investment tax credits - net (762) (762) (762)
Amortization of nuclear fuel 6,892 5,799 5,690
Allowance for funds used during construction (468) (1,575) (2,375)
Amortization of deferred return 12,586 12,586 12,586
Early retirement costs accrued - - 23,033
Changes in:
Accounts receivable - net (14,889) (2,277) (23,514)
Fuel, materials and supplies (14,466) 2,863 239
Prepayments (4,027) 211 (557)
Accounts payable (9,782) 28,307 39,338
Interest accrued (63) (3,569) (671)
Taxes accrued 4,849 3,116 (4,247)
Other assets and liabilities (4,062) (1,644) 6,078
------------ ------------ ------------
Total Adjustments 66,981 129,346 122,388
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 112,053 172,803 161,433
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 4,923 (6,432) 40
Long-term debt 199,636 98,500 82,500
Notes payable 49,141 26,786 10,965
Securities redeemed and retired:
Preferred stock (52) (110) (6,078)
Long-term debt (222,348) (151,199) (72,895)
Discount on preferred stock redemption 21 48 1,840
Expenses of issues (1,600) (1,500) (442)
Lease obligations (339) (315) (291)
Dividends
Preferred stock (202) (206) (410)
Common stock (40,285) (40,408) (40,399)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (11,105) (74,836) (25,170)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (38,040) (33,436) (47,174)
Investment in Seabrook obligation bonds 8,528 (34,541) (71,084)
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (29,512) (67,977) (118,258)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 71,436 29,990 18,005
BALANCE AT BEGINNING OF PERIOD 53,065 23,075 5,070
------------ ------------ ------------
BALANCE AT END OF PERIOD 124,501 53,065 23,075
LESS: RESTRICTED CASH 26,812 23,392 20,094
------------ ------------ ------------
BALANCE: UNRESTRICTED CASH $97,689 $29,673 $2,981
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $51,481 $59,441 $69,669
============ ============ ============
Income taxes $42,450 $26,773 $51,415
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
25
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1998, 1997 and 1996
ASSETS
(Thousands of Dollars)
1998 1997 1996
----- ----- ----
Utility Plant at Original Cost
In service $1,886,930 $1,867,145 $1,843,952
Less, accumulated provision for depreciation 714,375 644,971 585,646
---------------- -------------- --------------
1,172,555 1,222,174 1,258,306
Construction work in progress 33,695 25,448 40,998
Nuclear fuel 20,174 25,990 23,010
---------------- -------------- --------------
Net Utility Plant 1,226,424 1,273,612 1,322,314
---------------- -------------- --------------
Other Property and Investments 37,873 32,451 26,081
---------------- -------------- --------------
Current Assets
Unrestricted cash and temporary cash investments 97,689 29,673 2,981
Restricted cash 26,812 23,392 20,094
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800, $1,800 and $2,300 54,178 57,231 64,960
Other, less allowance for doubtful accounts of
$631, $5,397 and $6,629 64,240 46,298 36,292
Accrued utility revenues 21,079 25,269 29,139
Fuel, materials and supplies, at average cost 33,613 19,147 22,010
Prepayments 7,424 3,397 3,608
Other 154 67 110
---------------- -------------- --------------
Total 305,189 204,474 179,194
---------------- -------------- --------------
Deferred Charges
Unamortized debt issuance expenses 9,421 6,611 6,580
Other 1,664 5,727 1,485
---------------- -------------- --------------
Total 11,085 12,338 8,065
---------------- -------------- --------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax
differences (Note A) 264,811 277,350 289,672
Connecticut Yankee 42,633 51,313 64,851
Deferred return - Seabrook Unit 1 12,586 25,171 37,757
Unamortized redemption costs 23,468 23,027 25,063
Unamortized cancelled nuclear project 10,952 12,125 13,297
Uranium enrichment decommissioning costs 1,177 1,312 1,377
Other 4,962 6,357 9,068
---------------- -------------- --------------
Total 360,589 396,655 441,085
---------------- -------------- --------------
$1,941,160 $1,919,530 $1,976,739
================ ============== ==============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
26
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1998, 1997 and 1996
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1998 1997 1996
----- ----- ----
Capitalization (Note B)
Common stock equity
Common stock $292,006 $288,730 $284,579
Paid-in capital 2,046 1,349 772
Capital stock expense (2,182) (2,182) (2,182)
Unearned employee stock ownership plan equity (10,210) (11,160) -
Retained earnings 163,847 159,344 156,299
---------------- -------------- --------------
445,507 436,081 439,468
Preferred stock 4,299 4,351 4,461
Company-obligated mandatorily redeemable securities of subsidiary
holding solely parent debentures 50,000 50,000 50,000
Long-term debt
Long-term debt 757,370 746,058 826,527
Investment in Seabrook obligation bonds (92,860) (101,388) (66,847)
---------------- -------------- --------------
Net long-term debt 664,510 644,670 759,680
Total 1,164,316 1,135,102 1,253,609
---------------- -------------- --------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 32,711 40,821 54,752
Pensions accrued (Note H) 31,097 39,149 49,205
Nuclear decommissioning obligation 23,045 17,538 12,851
Obligations under capital leases 16,506 16,853 17,193
Other 6,622 5,507 4,815
---------------- -------------- --------------
Total 109,981 119,868 138,816
---------------- -------------- --------------
Current Liabilities
Current portion of long-term debt 66,202 100,000 69,900
Notes payable 86,892 37,751 10,965
Accounts payable 48,749 62,552 60,470
Accounts payable - APS utility customers 54,515 50,494 24,269
Dividends payable 10,155 10,051 10,205
Taxes accrued 9,015 4,166 1,050
Interest accrued 10,203 10,266 13,835
Obligations under capital leases 348 340 315
Other accrued liabilities 39,845 37,471 36,091
---------------- -------------- --------------
Total 325,924 313,091 227,100
---------------- -------------- --------------
Customers' Advances for Construction 1,867 1,878 1,888
---------------- -------------- --------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,623 16,385 17,147
Other 2,065 2,356 1,811
---------------- -------------- --------------
Total 17,688 18,741 18,958
---------------- -------------- --------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities) 321,384 330,850 336,368
Commitments and Contingencies (Note L)
---------------- -------------- --------------
$1,941,160 $1,919,530 $1,976,739
================ ============== ==============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
27
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(THOUSANDS OF DOLLARS)
1998 1997 1996
----- ----- ----
BALANCE, JANUARY 1 $159,344 $156,299 $156,380
Net income 45,072 43,457 39,045
Adjustments associated with repurchase
of preferred stock 21 48 1,815
------------ ------------ ------------
Total 204,437 199,804 197,240
------------ ------------ ------------
Deduct Cash Dividends Declared
Preferred stock 201 205 330
Common stock 40,389 40,255 40,611
------------ ------------ ------------
Total 40,590 40,460 40,941
------------ ------------ ------------
BALANCE, DECEMBER 31 $163,847 $159,344 $156,299
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
28
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
DECEMBER 31, 1998, 1997 AND 1996
(DOLLAR AMOUNTS IN THOUSANDS)
Capital Unearned
Common Stock Preferred Stock Paid-in Stock ESOP Retained
Shares Amount Shares Amount Capital Expense Equity Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1996 14,100,091 $284,542 105,394 $10,539 $769 ($2,207) - $156,380 $450,023
- -----------------------------------------------------------------------------------------------------------------------------------
Net income for 1996 39,045 39,045
Cash dividends on common stock
- $2.88 per share (40,611) (40,611)
Cash dividends on preferred stock (330) (330)
Issuance of 1,200 shares common stock
- no par value 1,200 37 3 40
Repurchase and cancellation of
preferred stock (60,782) (6,078) 25 (25) (6,078)
Discount on preferred stock repurchase 1,840 1,840
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1996 14,101,291 284,579 44,612 4,461 772 (2,182) - $156,299 $443,929
- -----------------------------------------------------------------------------------------------------------------------------------
Net income for 1997 43,457 43,457
Cash dividends on common stock
- $2.88 per share (40,255) (40,255)
Cash dividends on preferred stock (205) (205)
Issuance of 134,833 shares common stock
- no par value 134,833 4,151 577 4,728
ESOP purchase of 328,300 common shares (328,300) (11,160) (11,160)
Repurchase and cancellation of preferred
stock (1,103) (110) (110)
Discount on preferred stock repurchase 48 48
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1997 13,907,824 288,730 43,509 4,351 1,349 (2,182) (11,160) $159,344 $440,432
- ------------------------------------------------------------------------------------------------------------------------------------
Net income for 1998 45,072 45,072
Cash dividends on common stock
- $2.88 per share (40,389) (40,389)
Cash dividends on preferred stock (201) (201)
Issuance of 98,798 shares common stock
- no par value 98,798 3,276 459 3,735
Allocation of benefits - ESOP 27,940 238 950 1,188
Repurchase and cancellation of preferred
stock (524) (52) (52)
Discount on preferred stock repurchase 21 21
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1998 14,034,562 $292,006 42,985 $4,299 $2,046 ($2,182)($10,210) $163,847 $449,806
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are
an integral part of the financial statements.
29
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The United Illuminating Company (UI or the Company) is an operating
electric public utility company, engaged principally in the production,
purchase, transmission, distribution and sale of electricity for residential,
commercial and industrial purposes in a service area of about 335 square miles
in the southwestern part of the State of Connecticut. The service area, largely
urban and suburban in character, includes the principal cities of Bridgeport
(population 137,000) and New Haven (population 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals.
In addition, the Company has created, and owns, unregulated subsidiaries.
The Board of Directors of the Company has authorized the investment of a maximum
of $32.25 million in the unregulated subsidiaries, and, at February 28, 1999,
$30 million had been invested. A wholly-owned subsidiary, United Resources,
Inc., serves as the parent corporation to American Payment Systems, Inc., (APS)
which manages a national network of agents for the processing of bill payments
made by customers of other utilities.
(A) STATEMENT OF ACCOUNTING POLICIES
ACCOUNTING RECORDS
The accounting records are maintained in accordance with the uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC) and the Connecticut Department of Public Utility Control (DPUC).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to use estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.
Actual results could differ from those estimates.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, United Resources Inc. Intercompany accounts and
transactions have been eliminated in consolidation.
REGULATORY ACCOUNTING
The consolidated financial statements of the Company are in conformity with
generally accepted accounting principles and with accounting for regulated
electric utilities prescribed by the Federal Energy Regulatory Commission (FERC)
and the Connecticut Department of Public Utility Control (DPUC). Generally
accepted accounting principles for regulated entities allow the Company to give
accounting recognition to the actions of regulatory authorities in accordance
with the provisions of Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation". In accordance
with SFAS No. 71, the Company has deferred recognition of costs (a regulatory
asset) or has recognized obligations (a regulatory liability) if it is probable
that such costs will be recovered or obligations relieved in the future through
the ratemaking process. In addition to the Regulatory Assets and Liabilities
separately identified on the Consolidated Balance Sheet, there are other
regulatory assets and liabilities such as conservation and load management costs
and certain deferred tax liabilities. The Company also has obligations under
long-term power contracts, the recovery of which is subject to regulation.
The effects of competition could cause the operations of the Company, or a
portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. If the Company, or a portion of its assets or
operations, were to cease meeting these criteria, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met. If this
30
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
change in accounting were to occur, it could have a material adverse effect on
the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
See Note (C), Rate-Related Regulatory Proceedings.
RECLASSIFICATION OF PREVIOUSLY REPORTED AMOUNTS
Certain amounts previously reported have been reclassified to conform with
current year presentations.
UTILITY PLANT
The cost of additions to utility plant and the cost of renewals and
betterments are capitalized. Cost consists of labor, materials, services and
certain indirect construction costs, including an allowance for funds used
during construction (AFUDC). The cost of current repairs and minor replacements
is charged to appropriate operating expense accounts. The original cost of
utility plant retired or otherwise disposed of and the cost of removal, less
salvage, are charged to the accumulated provision for depreciation.
The Company's utility plant in service as of December 31, 1998, 1997 and
1996 was comprised as follows:
1998 1997 1996
---- ---- ----
(000's)
Production $1,133,984 $1,131,285 $1,124,113
Transmission 161,643 161,288 160,970
Distribution 408,845 401,426 387,825
General 56,264 52,776 47,889
Future use plant 30,505 30,594 32,751
Other 95,689 89,776 90,404
------- ------- -------
$1,886,930 $1,867,145 $1,843,952
========== ========== ==========
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
In accordance with the applicable regulatory systems of accounts, the
Company capitalizes AFUDC, which represents the approximate cost of debt and
equity capital devoted to plant under construction. In accordance with FERC
prescribed accounting, the portion of the allowance applicable to borrowed funds
is presented in the Consolidated Statement of Income as a reduction of interest
charges, while the portion of the allowance applicable to equity funds is
presented as other income. Although the allowance does not represent current
cash income, it has historically been recoverable under the ratemaking process
over the service lives of the related properties. The Company compounds the
allowance applicable to major construction projects semi-annually. Weighted
average AFUDC rates in effect for 1998, 1997 and 1996 were 7.0%, 7.5% and 9.0%,
respectively.
DEPRECIATION
Provisions for depreciation on utility plant for book purposes are computed
on a straight-line basis, using estimated service lives determined by
independent engineers. One-half year's depreciation is taken in the year of
addition and disposition of utility plant, except in the case of major operating
units on which depreciation commences in the month they are placed in service
and ceases in the month they are removed from service. The aggregate annual
provisions for depreciation for the years 1998, 1997 and 1996 were equivalent to
approximately 3.26%, 3.15% and 3.12%, respectively, of the original cost of
depreciable property.
INCOME TAXES
In accordance with Statement of Financial Accounting Standards (SFAS) No.
109 "Accounting for Income Taxes", the Company has provided deferred taxes for
all temporary book-tax differences using the liability method. The liability
method requires that deferred tax balances be adjusted to reflect enacted future
tax rates that are anticipated to be in effect when the temporary differences
reverse. In accordance with generally accepted accounting
31
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
principles for regulated industries, the Company has established a regulatory
asset for the net revenue requirements to be recovered from customers for the
related future tax expense associated with certain of these temporary
differences.
For ratemaking purposes, the Company normalizes all investment tax credits
(ITC) related to recoverable plant investments except for the ITC related to
Seabrook Unit 1, which was taken into income in accordance with provisions of a
1990 DPUC retail rate decision.
ACCRUED UTILITY REVENUES
The estimated amount of utility revenues (less related expenses and
applicable taxes) for service rendered but not billed is accrued at the end of
each accounting period.
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 is required to maintain an operating deposit with the project
disbursing agent related to its 17.5% ownership interest in Seabrook Unit 1.
This operating deposit, which is the equivalent to one and one half months of
the funding requirement for operating expenses, is restricted for use and
amounted to $3.8 million, $2.3 million and $3.4 million, at December 31, 1998,
1997 and 1996, respectively.
The Company's wholly-owned subsidiary, American Payment Systems, Inc.,
maintains separate bank accounts for holding cash received from utility
customers before the amounts are transferred to utilities. The amount of this
restricted cash at December 31, 1998, 1997 and 1996 was $25.3 million, $20.1
million and $16.7 million, respectively.
INVESTMENTS
The Company's investment in the Connecticut Yankee Atomic Power Company, a
nuclear generating company in which the Company has a 9 1/2% stock interest, is
accounted for on an equity basis. This investment amounted to $9.9 million,
$10.5 million and $10.1 million at December 31, 1998, 1997 and 1996,
respectively, and is included on the Consolidated Balance Sheet as a regulatory
asset. See Note (L), Commitments and Contingencies - Other Commitments and
Contingencies - Connecticut Yankee.
FOSSIL FUEL COSTS
Historically, the amount of fossil fuel costs that cannot be reflected
currently in customers' bills pursuant to the fossil fuel adjustment clause in
the Company's rates has been deferred at the end of each accounting period.
Since adoption of the deferred accounting procedure in 1974, rate decisions by
the DPUC and its predecessors have consistently made specific provision for
amortization and ratemaking treatment of the Company's existing deferred fossil
fuel cost balances. As a result of a December 1996 DPUC decision, the Company
has suspended this deferred accounting procedure unless the average fossil fuel
oil prices increase or decrease outside a certain bandwidth prescribed in the
decision.
INTEREST RATE RISK MANAGEMENT
The Company utilizes interest rate instruments to manage interest rate
risk. Interest rate swaps have been entered into that effectively convert $225
million of variable rate borrowings to fixed rate borrowings. The liability
under the swap agreements is accounted for using the book value of the original
debt, $145 million being included in long-term debt and $80 million within
short-term debt. Interest payable under the swap agreements at the fixed rate is
recorded in interest expense.
This accounting treatment for interest rate swaps is only utilized if the
timing and value of receipts of variable rate interest under the swap agreement
offset UI's liability for interest on the variable rate borrowings. If these
32
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
criteria are not met, the liability of the interest rate swaps is recorded at
fair market value and any change in the market value is recorded as interest
income or interest expense. Any gain or loss on the termination of the swaps is
charged to interest expense in the period of termination. The Company does not
enter into derivative instruments for anticipated transactions.
See Note (N), "Fair Value of Financial Instruments"
RESEARCH AND DEVELOPMENT COSTS
Research and development costs, including environmental studies, are
charged to expense as incurred.
PENSION AND OTHER POSTEMPLOYMENT BENEFITS
The Company accounts for normal pension plan costs in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No. 87,
"Employers' Accounting for Pensions", and for supplemental retirement plan costs
and supplemental early retirement plan costs in accordance with the provisions
of SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and for Termination Benefits".
The Company accounts for other postemployment benefits, consisting
principally of health and life insurance, under the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions", which
requires, among other things, that the liability for such benefits be accrued
over the employment period that encompasses eligibility to receive such
benefits. The annual incremental cost of this accrual has been allowed in retail
rates in accordance with a 1992 rate decision of the DPUC.
URANIUM ENRICHMENT OBLIGATION
Under the Energy Policy Act of 1992 (Energy Act), the Company will be
assessed for its proportionate share of the costs of the decontamination and
decommissioning of uranium enrichment facilities operated by the Department of
Energy. The Energy Act imposes an overall cap of $2.25 billion on the obligation
assessed to the nuclear utility industry and limits the annual assessment to
$150 million each year over a 15-year period. At December 31, 1998, the
Company's unfunded share of the obligation, based on its ownership interest in
Seabrook Unit 1 and Millstone Unit 3, was approximately $1.1 million. Effective
January 1, 1993, the Company was allowed to recover these assessments in rates
as a component of fuel expense. Accordingly, the Company has recognized these
costs as a regulatory asset on its Consolidated Balance Sheet.
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 $2,580,000, $2,571,000 and $2,130,000
during 1998, 1997 and 1996 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1998, the Company's shares of the
trust fund balances, which included accumulated earnings on the funds, were
$16.5 million and $6.5 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.
IMPAIRMENT OF LONG-LIVED ASSETS
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets to Be Disposed Of" requires the recognition
of impairment losses on long-lived assets when the book value of an asset
exceeds the sum of the expected future undiscounted cash flows that result from
the use of the asset and its eventual disposition. This standard also requires
that rate-regulated companies recognize an impairment loss when a regulator
excludes all or part of a cost from rates, even if the regulator allows the
company to earn a return on the remaining allowable costs. Under this standard,
the probability of recovery and the recognition of regulatory assets
33
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
under the criteria of SFAS No. 71 must be assessed on an ongoing basis. The
Company does not have any assets that are impaired under this standard.
APS Revenues and Agent Collections
APS recognized revenue of $33.7 million, $31.7 million and $19.2 million
for the years 1998, 1997 and 1996, respectively, based on established fees per
payment transaction processed.
EARNINGS PER SHARE
The following table presents a reconciliation of the numerators and
denominators of the basic and diluted earnings per share calculations for the
years 1998, 1997 and 1996:
(In thousands except per share amounts)
Income Applicable to Average Number of
Common Stock Shares Outstanding Earnings
(Numerator) (Denominator) per Share
-------------------- ------------------ ---------
1998
- ----
Basic earnings per share $44,892 14,018 $3.20
Effect of dilutive stock options - 5 (.00)
------- ------ -----
Diluted earnings per share $44,892 14,023 $3.20
======= ====== =====
1997
- ----
Basic earnings per share $43,300 13,976 $3.10
Effect of dilutive stock options - 16 (.01)
------ ------ ----
Diluted earnings per share $43,300 13,992 $3.09
======= ====== =====
1996
- ----
Basic earnings per share $40,555 14,101 $2.88
Effect of dilutive stock options - 30 (.01)
------ ------ ----
Diluted earnings per share $40,555 14,131 $2.87
======= ====== =====
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation". This statement establishes financial accounting and
reporting standards for stock-based employee compensation plans, such as stock
purchase plans, stock options, restricted stock, and stock appreciation rights.
The statement defines the methods of determining the fair value of stock-based
compensation and requires the recognition of compensation expense for book
purposes. However, the statement allows entities to continue to measure
compensation expense in accordance with the prior authoritative literature, APB
No. 25, "Accounting for Stock Issued to Employees", but requires that pro forma
net income and earnings per share be disclosed for each year for which an income
statement is presented as if SFAS No. 123 had been applied. The accounting
requirements of this statement are effective for transactions entered into after
1995. However, pro forma disclosures must include the effects of all awards
granted after January 1, 1995. As of December 31, 1998, there were no options
granted to which this statement would apply. The Company has not elected to
adopt the expense recognition provisions of SFAS No. 123.
NEW ACCOUNTING STANDARDS
On January 1, 1998, the Company adopted Statement of Financial Standards
(SFAS) No. 130, "Reporting Comprehensive Income", which provides authoritative
guidance on the reporting and display of comprehensive
34
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
income and its components. For the years ended December 31, 1998, 1997 and 1996,
comprehensive income was equal to net income as reported.
On January 1, 1998, the Company adopted SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information", which provides guidance
about segment reporting. As described in Note (P), "Segment Information", the
Company has only one reportable segment, that of regulated generation,
distribution and sale of electricity.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". This statement,
which is effective for fiscal quarters of fiscal years beginning after June 15,
1999, establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires entities to recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The accounting for the changes in the fair
value of a derivative (gains and losses) would depend on the intended use and
designation of the derivative. The Company currently does not anticipate
utilizing derivative instruments of the type defined in this statement, on or
after the effective date of this statement.
35
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
December 31,
---------------------------------------------------------------------------------------
1998 1997 1996
Shares Shares Shares
Outstanding $(000's) Outstanding $(000's) Outstanding $(000's)
-------------- ------------ -------------- ------------ -------------- ------------
COMMON STOCK EQUITY
Common stock, no par value,
at December 31(a) 14,034,562 $292,006 13,907,824 $288,730 14,101,291 $284,579
Shares authorized
1996 30,000,000
1997 30,000,000
1998 30,000,000
Paid-in capital 2,046 1,349 772
Capital stock expense (2,182) (2,182) (2,182)
Unearned employee stock ownership plan equity (10,210) (11,160) -
Retained earnings (b) 163,847 159,344 156,299
------------ ------------ ------------
Total common stock equity 445,507 436,081 439,468
------------ ------------ ------------
PREFERRED AND PREFERENCE STOCK (c)
Cumulative preferred stock,
$100 par value, shares
authorized at December 31,
1996 1,119,612
1997 1,119,612
1998 1,119,612
Preferred stock issues:
4.35% Series A 10,370 10,894 11,297
4.72% Series B 17,158 17,158 17,658
4.64% Series C 12,745 12,745 12,945
5 5/8% Series D 2,712 2,712 2,712
-------------- -------------- --------------
42,985 4,299 43,509 4,351 44,612 4,461
-------------- ------------ -------------- ------------ -------------- ------------
Cumulative preferred stock, $25 par
value: 2,400,000 shares authorized
Preferred stock issues - - - - - -
Cumulative preference stock, $25 par
value: 5,000,000 shares authorized
Preference stock issues - - - - - -
------------ ------------ ------------
Total preferred stock not
subject to mandatory redemption 4,299 4,351 4,461
------------ ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES (d) 50,000 50,000 50,000
------------ ------------ ------------
36
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
December 31,
--------------------------------------------------
1998 1997 1996
$(000's) $(000's) $(000's)
-------------- -------------- --------------
LONG-TERM DEBT (e)
First Mortgage Bonds:
9.44%, Series B - - $32,400
Other Long-term Debt
Pollution Control Revenue Bonds:
Variable rate, 1996 Series, due June 26, 2026 7,500 7,500 7,500
9 3/8%, 1987 Series, due July 1, 2012 - - 25,000
10 3/4%, 1987 Series, due November 1, 2012 - - 43,500
8%, 1989 Series A, due December 1, 2014 25,000 25,000 25,000
5 7/8%, 1993 Series, due October 1, 2033 64,460 64,460 64,460
Solid Waste Disposal Revenue Bonds:
Adjustable rate 1990 Series A, due September 1, 2015 - - 30,000
Pollution Control Refunding Revenue Bonds:
Variable rate, 1997 Series, due July 30, 2027 98,500 98,500 -
Notes:
7 3/8%, 1992 Series G, due January 15, 1998 - 100,000 100,000
6.20%, 1993 Series H, due January 15, 1999 66,202 100,000 100,000
6.25%, 1998 Series I, due December 15, 2002 100,000 - -
6.00%, 1998 Series J, due December 15, 2003 100,000 - -
Term Loans:
6.95%, due August 29, 2000 (Note 1) 50,000 50,000 50,000
6.47%, due September 6, 2000 (Note 1) - 50,000 50,000
6.4375%, due September 6, 2000 (Note 1) 20,000 50,000 50,000
6.675%, due October 25, 2001 (Note 1) 25,000 25,000 25,000
7.005% due October 25, 2001 (Note 1) 50,000 50,000 50,000
Obligation under the Seabrook Unit 1
sale/leaseback agreement 217,230 225,601 243,660
-------------- -------------- --------------
823,892 846,061 896,520
Unamortized debt discount less premium (320) (3) (93)
-------------- -------------- --------------
Total long-term debt 823,572 846,058 896,427
Less:
Current portion included in Current Liabilities (e) 66,202 100,000 69,900
Investment-Seabrook Lease Obligation Bonds 92,860 101,388 66,847
-------------- -------------- --------------
Total long-term debt included in Capitalization 664,510 644,670 759,680
-------------- -------------- --------------
TOTAL CAPITALIZATION $1,164,316 $1,135,102 $1,253,609
============== ============== ==============
Note 1: The fixed interest rate for these variable interest rate
term loans reflects the effect of the associated interest rate swaps.
37
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(a) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at December 31, 1998, of which 300,360 shares were unallocated
shares held by the Company's Employee Stock Ownership Plan ("ESOP") and not
recognized as outstanding for accounting purposes.
The Company issued 98,798 shares of common stock in 1998, 134,833 shares
of common stock in 1997 and 1,200 shares of common stock in 1996, pursuant to a
stock option plan.
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 December 31, 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 1998.
1998 1997 1996
---- ---- ----
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ -------- ------ -------- ------ --------
Balance - Beginning of Year 115,098 $33.90 252,331 $32.20 255,133 $32.21
Granted - - - - - -
Forfeited - - (2,400) $30.75 (1,602) $34.78
Exercised (98,798) $33.16 (134,833) $30.79 (1,200) $30.75
Balance - End of Year 16,300 $38.37 115,098 $33.90 252,331 $32.20
------- ------- -------
Exercisable at End of Year 16,300 $38.37 96,698 $34.51 215,432 $31.73
======= ======= =======
Stock options in the amounts of 10,936 shares, 99,352 shares and 222,622
shares at December 31, 1998, 1997 and 1996, respectively, were not included it
the computation of diluted EPS because doing so would have been antidilutive for
those periods.
On February 23, 1998, the Board of Directors granted 80,000 "phantom" stock
options to Nathaniel D. Woodson upon his appointment as President of the
Company. On each of the first five anniversaries of the grant date, 16,000
options become exercisable and can be exercised at any time within Mr. Woodson's
period of employment with the Company by means of the Company paying him the
difference between the prevailing market price for each share and the option
price of $45.16 per share option. At ten years after the grant date any
unexercised options will expire. At December 31, 1998, no options had become
exercisable and no expense had been incurred.
In 1996, the Company established its Long-Term Incentive Program (LTIP) for
officers and key employees of the Company. Under the program, each LTIP
participant is awarded contingent performance shares for each three-year
performance period as defined under the program. Each contingent performance
share is equivalent to one share of the Company's common stock. At the end of
each performance period, the number of performance shares earned is calculated
on the basis of the Company's total shareowner return during the performance
period relative to a peer group of companies previously selected. For the
1996-1998 performance period, approximately $1.1 million was paid under this
program. The Company accrues the costs of the LTIP as compensation expense when
it is likely that payments will be made to participants in the program.
38
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of December 31, 1998 and 1997, 300,360 shares and 328,300 shares,
with a fair market value of $15.5 million and $15.1 million, respectively, 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 $266.2 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 $105.7 million were free from such limitations at December 31, 1998.
(c) PREFERRED AND PREFERENCE STOCK
The par value of each of these issues was credited to the appropriate stock
account and expenses related to these issues were charged to capital stock
expense.
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.
Shares of preferred stock have preferential dividend and liquidation rights
over shares of common stock. Preferred shareholders are not entitled to general
voting rights. However, if any preferred dividends are in arrears for six or
more quarters, or if certain other events of default occurs, preferred
shareholders are entitled to elect a majority of the Board of Directors until
all preferred dividend arrearages are paid and any event of default is
terminated.
Preference stock is a form of stock that is junior to preferred stock but
senior to common stock. It is not subject to the earnings coverage requirements
or minimum capital and surplus requirements governing the issuance of preferred
stock. There were no shares of preference stock outstanding at December 31,
1998.
(d) PREFERRED CAPITAL SECURITIES
United Capital Funding Partnership L.P. (United Capital) is a special
purpose limited partnership in which the Company owns all of the general partner
interests.
The sole holding of United Capital is the $50 million of 9 5/8% Junior
Subordinated Deferrable Interest Debentures, Series A, due April 30, 2025, (the
Series A Debentures) issued by United Illuminating in 1995.
Holders of the preferred capital securities will be entitled to receive, to
the extent of funds held by United Capital, cumulative preferential dividends,
at an annual rate 9 5/8% of the liquidation preference of $25 per security,
payable monthly in arrears on the last day of each calendar month. The payment
of dividends and payments on redemption with respect to the preferred capital
securities to the extent of funds held by United Capital, will be guaranteed
under a Payment and Guarantee Agreement (the Guarantee) of United Illuminating.
The Guarantee does not cover payment of amounts in respect of the preferred
capital securities to the extent that United Capital does not have available
funds for the payment thereof and cash on hand sufficient to make such payment.
Such funds and cash on hand will be limited to payments by United Illuminating
on the Series A Debentures. If United Illuminating fails to make interest
payments on the Series A Debentures, United Capital will have insufficient funds
to pay dividends on the preferred capital securities and the Guarantee will not
cover payment of dividends.
39
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The 9 5/8% Preferred Capital Securities, Series A, issued by United Capital
are subject to mandatory redemption when the Series A Debentures, Series A,
mature or are redeemed.
(e) LONG-TERM DEBT
The expenses to issue long-term debt are deferred and amortized over the
life of the respective debt issue.
In 1990, United Illuminating sold and leased back a portion of its
investment in Seabrook Unit 1, a 1150 mw nuclear generation plant in Seabrook,
New Hampshire. The purchaser-lessor issued and sold $212 million of lease
obligation bonds to finance the purchase price of $250 million. United
Illuminating is obligated to make lease payments during the 30-year lease term
that are used to pay the debt service on these bonds. In 1997, the lease
obligation bonds were refinanced by the lessor, and United Illuminating
purchased 49.9% of the new lease obligation bonds.
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.
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.
On December 18, 1998, the Company issued and sold $100 million principal
amount of 6% five-year Notes. The yield on the Notes, which were issued at a
discount, is 6.034%; and the Notes will mature on December 15, 2003. The
proceeds from the sale of the Notes were used to repay $66.2 million principal
amount of 6.2% Notes, which matured on January 15, 1999, and for general
corporate purposes.
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and will be paid semi-annually beginning on
August 1, 1999. In addition, on February 1, 1999, the Company converted $98.5
million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds will
be paid semi-annually beginning on August 1, 1999.
Maturities and mandatory redemptions/repayments are set forth below:
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(000's)
Maturities $66,202 $70,000 $75,000 $100,000 $100,000
Mandatory redemptions/repayments (1) 3,410 430 333 338 485
------ ------ ------ ------- -------
Maturities and Mandatory
redemptions/repayments $69,612 $70,430 $75,333 $100,338 $100,485
====== ====== ====== ======= ========
(1) Principal component of Seabrook lease obligation, net of principal repayment
of Seabrook Lease Obligation Bonds held as an investment.
40
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(C) RATE-RELATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from among competing
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the charge for electricity
generation services from the charge for delivering the electricity and all other
charges. On July 29, 1998, the DPUC issued the first of what are expected to be
several orders relative to this "unbundling" requirement, and has now reopened
its proceeding to consider the amount of the generation services charge to be
included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to certain adjustments, at least 10%
below its fully bundled prices for electricity at rates in effect on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments, to be the total rate charged under the standard offer, including
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment charge.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
41
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of other
above-market generation costs eligible for the competitive transition
assessment, such as regulated plant costs and tax-related regulatory assets or
other costs related to the restructuring transition, such that there will be no
net income effect of the sale. The Company anticipates using the net cash
proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under the
Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. In order
to mitigate the financial risk that these regulated service mandates will pose
to the Company in an unregulated power generation environment, its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates, effective July 1, 2000, as permitted by the Restructuring Act. This
clause, similar to and based on the purchased gas adjustment clauses used by
Connecticut's natural gas local distribution companies, would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay competitive market rates for power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
The Restructuring Act provides for the Distribution Company to recover its
reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
other state and federal agencies, and the Company's common stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order (see below) anticipated
sufficient income in 2000 to accelerate amortization of regulatory assets of
about $50 million, equivalent to about 8% of retail revenues. Substantially all
of this accelerated amortization may
42
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
have to be eliminated to allow for the additional standard offer price reduction
requirement of 10%, at a minimum, while providing for the added costs imposed by
the restructuring legislation. The legislation does prescribe certain bases for
adjusting the price of standard offer service if the 10% minimum price reduction
cannot be accomplished.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers; but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The 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 Rate Plan, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Also as a result of the Rate Plan,
customer prices are required to be reduced by an additional 1% in 2000, and
another 1% in 2001, compared to 1996. Retail revenues have decreased by
approximately 4.8% through 1998 compared to 1996 due to customer price
reductions. The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act described above, the Rate
Plan may be reopened and modified. However, aside from implementing an
additional price reduction in 2000 to achieve the minimum 10% price reduction
required by the Restructuring Act and the probable reductions in the accelerated
amortizations scheduled in the Rate Plan, the Company is unable to predict, at
this time, in what other respects the Rate Plan may be modified on account of
this legislation.
(D) ACCOUNTING FOR PHASE-IN PLAN
The Company phased into rate base its allowable investment in Seabrook Unit
1, amounting to $640 million, during the period January 1, 1990 to January 1,
1994. In conjunction with this phase-in plan, the Company was allowed to record
a deferred return on the portion of allowable investment excluded from rate base
during the phase-in period. Accordingly, the Company is amortizing the
net-of-tax accumulated deferred return of $62.9 million over a five-year period
that commenced January 1, 1995.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 1999. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
December 31, 1998, the Company had no 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
43
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 December 31, 1998, the
Company had $80 million of short-term borrowings outstanding under this
facility.
In addition, as of December 31, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $6.8 million
outstanding under a bank line of credit agreement.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1998, this coverage ratio was 3.6:1.0.
Information with respect to short-term borrowings under the Company's
revolving credit agreements is as follows:
1998 1997 1996
---- ---- ----
(000's)
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $130,000 $50,000 $30,000
Average aggregate short-term borrowings outstanding during the year* $115,753 $41,441 $15,380
Weighted average interest rate* 6.1% 5.9% 5.7%
Principal amounts outstanding at year-end $80,000 $30,000 $0
Annualized interest rate on principal amounts outstanding at year-end 5.7% 6.2% N/A
*Average short-term borrowings represent the sum of daily borrowings
outstanding, weighted for the number of days outstanding and divided by the
number of days in the period. The weighted average interest rate is determined
by dividing interest expense by the amount of average borrowings. Commitment
fees of approximately $381,000, $114,000 and $130,000 paid during 1998, 1997 and
1996, respectively, are excluded from the calculation of the weighted average
interest rate.
44
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
1998 1997 1996
----- ----- ----
Income tax expense consists of: (000's)
Income tax provisions:
Current
Federal $36,774 $23,568 $35,770
State 10,685 7,545 11,526
------------ ------------ ------------
Total current 47,459 31,113 47,296
------------ ------------ ------------
Deferred
Federal 2,964 6,123 216
State 110 681 (3,029)
------------ ------------ ------------
Total deferred 3,074 6,804 (2,813)
------------ ------------ ------------
Investment tax credits (762) (762) (762)
------------ ------------ ------------
Total income tax expense $49,771 $37,155 $43,721
============ ============ ============
Income tax components charged as follows:
Operating expenses $53,619 $40,833 $53,590
Other income and deductions - net (3,848) (3,678) (9,869)
------------ ------------ ------------
Total income tax expense $49,771 $37,155 $43,721
============ ============ ============
The following table details the components of the
deferred income taxes:
Tax depreciation on unrecoverable plant investment $6,291 $8,089 $5,745
Fossil plants decommissioning reserve (329) (7,286)(1) -
Conservation & load management (8,026) (5,768) (367)
Accelerated depreciation 5,449 5,681 5,617
Pension benefits 3,463 4,911 (9,066)
Seabrook sale/leaseback transaction 304 2,664 (598)
Deferred fossil fuel costs - (686) 755
Cancelled nuclear project (467) (467) (4,729)
Unit overhaul and replacement power costs (1,157) 212 (1,491)
Bond redemption costs (1,039) (942) (783)
Property Tax Settlement (834) - -
Gain on sale of utility property (697) (272) -
Other 116 668 2,104
------------ ------------ ------------
Deferred income taxes - net $3,074 $6,804 ($2,813)
============ ============ ============
(1) $6,719 of this amount is for deferred income tax benefits from prior years.
45
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
1998 1997 1996
---- ---- ----
PRE-TAX TAX PRE-TAX TAX PRE-TAX TAX
------- --- ------- --- ------- ---
(000's)
Computed tax at federal statutory rate $33,195 $28,214 $28,968
Increases (reductions) resulting from:
Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 12,586 4,405
ITC taken into income (762) (762) (762) (762) (762) (762)
Allowance for equity funds used during
construction (13) (5) (336) (118) (940) (329)
Fossil plant decommissioning reserve (723) (253) (15,591) (5,457) - -
Book depreciation in excess of
non-normalized tax depreciation 22,789 7,976 23,926 8,374 22,703 7,946
State income taxes, net of federal
income tax benefits 10,795 7,017 8,226 5,345 8,497 5,523
Other items - net (5,149) (1,802) (8,134) (2,846) (5,797) (2,030)
------- ------- -------
Total income tax expense $49,771 $37,155 $43,721
======= ======= =======
Book income before income taxes $94,843 $80,612 $82,766
======= ======= =======
Effective income tax rates 52.5% 46.1% 52.8%
===== ===== =====
At December 31, 1998 the Company had deferred tax liabilities for taxable
temporary differences of $430 million and deferred tax assets for deductible
temporary differences of $109 million, resulting in a net deferred tax liability
of $321 million. Significant components of deferred tax liabilities and assets
were as follows: tax liabilities on book/tax plant basis differences and on the
cumulative amount of income taxes on temporary differences previously flowed
through to ratepayers, $282 million; tax liabilities on normalization of
book/tax depreciation timing differences, $127 million and tax assets on the
disallowance of plant costs, $41 million.
The Company has reflected on its Consolidated Balance Sheet as of December
31, 1997 an additional amount of deferred tax liabilities associated with plant
book/tax basis differences. An offsetting regulatory asset, representing the
future amounts to be collected from customers for the recovery of the tax
expense associated with these additional tax liabilities, has also been
reflected.
46
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
1998 1997 1996
----- ----- ----
(000's)
OPERATING REVENUES
- ------------------
Retail $631,607 $622,333 $651,114
Wholesale - capacity 11,524 9,747 7,686
- energy 33,424 73,124 65,158
Other 9,636 3,825 3,300
----------- ----------- -----------
Total Operating Revenues $686,191 $709,029 $727,258
=========== =========== ===========
SALES BY CLASS(MWH'S) - UNAUDITED
- ---------------------------------
Retail
Residential 1,924,724 1,899,284 1,895,804
Commercial 2,324,507 2,248,974 2,263,056
Industrial 1,154,935 1,168,470 1,143,410
Other 48,166 48,619 48,388
----------- ----------- -----------
5,452,332 5,365,347 5,350,658
Wholesale 1,551,109 2,700,393 2,260,423
----------- ----------- -----------
Total Sales by Class 7,003,441 8,065,740 7,611,081
=========== =========== ===========
OTHER OPERATION EXPENSES
- ------------------------
Production $28,427 $26,203 $22,214
Transmission & Distribution 35,681 36,926 35,415
Customer Service 26,582 28,957 29,107
Administrative & General 55,368 66,514 72,209
----------- ----------- -----------
Total $146,058 $158,600 $158,945
=========== =========== ===========
DEPRECIATION
- ------------
Plant in service $67,143 $65,585 $63,618
Accelerated conservation and load management 13,086 6,636 -
Nuclear decommissioning 2,580 2,397 2,303
----------- ----------- -----------
$82,809 $74,618 $65,921
=========== =========== ===========
OTHER TAXES
- -----------
Charged to:
Operating:
State gross earnings $24,039 $23,571 $26,804
Local real estate and personal property (1) 35,088 22,974 24,854
Payroll taxes 5,547 5,948 5,528
----------- ----------- -----------
64,674 52,493 57,186
Nonoperating and other accounts 510 459 628
----------- ----------- -----------
Total Other Taxes $65,184 $52,952 $57,814
=========== =========== ===========
(1) 1998 includes $14,025 charge for property tax settlement.
OTHER INCOME AND (DEDUCTIONS) - NET
- -----------------------------------
Interest income $3,181 $2,317 $1,505
Equity earnings from Connecticut Yankee 854 1,343 1,225
Loss from subsidiary companies (2) (1,748) (3,639) (9,701)
Miscellaneous other income and (deductions) - net (1,190) 1,340 (1,474)
----------- ----------- -----------
Total Other Income and (Deductions) - net $1,097 $1,361 ($8,445)
=========== =========== ===========
(2)Includes before-tax non-recurring charges in 1997 and 1996 of $2,825
and $5,750, respectively, resulting from losses at American Payment
Systems, Inc.
OTHER INTEREST CHARGES
- ----------------------
Notes Payable $5,050 $2,462 $882
Other 1,457 818 1,210
----------- ----------- -----------
Total Other Interest Charges $6,507 $3,280 $2,092
=========== =========== ===========
47
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(H) PENSION AND OTHER BENEFITS
The Company's qualified pension plan, which is based on the highest three
years of pay, covers substantially all of its employees, and its entire cost is
borne by the Company. The Company also has a non-qualified supplemental plan for
certain executives and a non-qualified retiree only plan for certain early
retirement benefits. The net pension costs for these plans for 1998, 1997 and
1996 were $(5,138,000), ($4,626,000) and $18,403,000, respectively.
The Company's funding policy for the qualified plan is to make annual
contributions that satisfy the minimum funding requirements of ERISA but that do
not exceed the maximum deductible limits of the Internal Revenue Code. These
amounts are determined each year as a result of an actuarial valuation of the
plan In 1996, the Company contributed $2.8 million for 1995 funding
requirements. In 1997, the Company contributed $2.7 million for 1996 funding
requirements and $2.5 million for 1997 funding requirements. In 1998, the
Company contributed $2.6 million for 1998 funding requirements. During 1996, the
Company established a supplemental retirement benefit trust and through this
trust purchased life insurance policies on the officers of the Company to fund
the future liability under the supplemental plan. The cash surrender value of
these policies is shown as an investment on the Company's Consolidated Balance
Sheet.
1998 1997
---- ----
(000's)
The components of net pension costs were as follows:
Service cost of benefits earned during the period $4,389 $ 3,791
Interest cost on projected benefit obligation 17,828 17,565
Expected return on plan assets (25,934) (22,293)
Amortization of:
Prior service cost 406 406
Transition obligation (asset) (1,095) (1,065)
Actuarial (gain) loss (1,132) (498)
Settlements (curtailments) 400 (2,724)
Other amortization and deferrals-net - 192
----- -----
Net pension cost $(5,138) $(4,626)
======= ======
Assumptions used to determine pension costs were:
Discount rate 7.25% 7.75%
Average wage increase 4.50% 4.50%
Return on plan assets 11.00% 11.00%
48
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1998 1997
---- ----
(000's)
The pension benefit obligations and plan assets as of December 31:
Change in Projected Pension Benefit Obligation:
Pension Benefit Obligation - January 1 $259,545 $232,783
Service cost 4,389 3,791
Interest cost 17,828 17,565
Curtailments/settlements - (3,193)
Actuarial (gain) loss 14,064 21,656
Benefits paid (15,080) (13,057)
-------- --------
Pension Benefit Obligation - December 31 $280,746 $259,545
======= =======
Change in Plan Assets:
Fair Value of Plan Assets - January 1 $243,739 $208,863
Actual return on plan assets 38,224 43,225
Employer contributions 2,914 5,429
Benefits paid (including expenses) (16,193) (13,778)
-------- --------
Fair Value of Plan Assets - December 31 $268,684 $243,739
======= =======
Funded Status:
Projected benefits greater than plan assets $12,062 $15,806
Unrecognized prior service cost (3,878) (4,285)
Unrecognized net gain (loss) from past experience 15,639 19,259
Unrecognized transition asset 7,274 8,369
------ ------
Accrued pension liability $31,097 $39,149
====== ======
Assumptions used in estimating benefit obligations at December 31:
Discount rate 6.75% 7.25%
Average wage increase 4.50% 4.50%
In addition to providing pension benefits, the Company also provides other
postretirement benefits (OPEB), consisting principally of health care and life
insurance benefits, for retired employees and their dependents. Employees with
25 years of service are eligible for full benefits, while employees with less
than 25 years of service but greater than 15 years of service are entitled to
partial benefits. Years of service prior to age 35 are not included in
determining the number of years of service.
For funding purposes, the Company established a Voluntary Employees'
Benefit Association Trust (VEBA) to fund OPEB for union employees. Approximately
44% of the Company's employees are represented by Local 470-1, Utility Workers
Union of America, AFL-CIO, for collective bargaining purposes. The Company
established a 401(h) account in connection with the qualified pension plan to
fund OPEB for non-union employees who retire on or after January 1, 1994. The
funding policy assumes contributions to these trust funds to be the total OPEB
expense calculated under SFAS No. 106, adjusted to reflect a share of amounts
expensed as a result of voluntary early retirement programs minus pay-as-you-go
benefit payments for pre-January 1, 1994 non-union retirees, allocated in a
manner that minimizes current income tax liability, without exceeding maximum
tax deductible limits. In accordance with this policy, the Company contributed
approximately $0, $0 and $3.8 million to the union VEBA in 1998, 1997 and 1996,
respectively. The Company contributed $0.9 million, $1.7 million and $0.9
million to the 401(h) account in 1998, 1997 and 1996, respectively. Plan assets
for both the union VEBA and 401(h) account consist primarily of equity and
fixed-income securities.
49
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The components of the net cost of OPEB were as follows:
1998 1997
---- ----
(000's)
Service cost $1,078 $ 925
Interest cost 2,576 2,434
Expected return on plan assets (2,249) (1,787)
Amortization of:
Prior service cost (71) (86)
Transition obligation (asset) 1,169 1,906
Actuarial (gain) loss (361) (648)
Settlements (curtailments) - (186)
Other amortization and deferrals-net - 492
--- ----
Net Cost of Postretirement Benefit $2,142 $3,050
===== =====
Assumptions used to determine OPEB costs were:
Discount rate 7.25% 7.75%
Health Care Cost Trend Rate 5.50% 5.50%
Return on plan assets 11.00% 11.00%
A one percentage point change in the assumed health care cost trend rate would
have the following effects:
1% Increase 1% Decrease
(000's)
Aggregate service and interest cost components $463 $(372)
Accumulated postretirement benefit obligation $4,246 $(3,498)
50
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1998 1997
---- ----
(000's)
The postretirement benefit obligations and plan assets as of December 31:
Change in Projected Postretirement Benefit Obligation:
Postretirement Benefit Obligation - January 1 $35,112 $36,220
Service cost 1,078 925
Interest cost 2,576 2,434
Amendments - (409)
Curtailments/settlements - 204
Actuarial (gain) loss 4,002 (1,923)
Benefits paid (2,539) (2,339)
------- -------
Postretirement Benefit Obligation - December 31 $40,229 $35,112
====== ======
Change in Plan Assets:
Fair Value of Plan Assets - January 1 $21,168 $16,720
Actual return on plan assets 2,491 3,836
Employer contributions 910 1,737
Benefits paid (including expenses) (1,366) (1,125)
------- -------
Fair Value of Plan Assets - December 31 $23,203 $21,168
====== ======
Funded Status:
Projected benefits greater than plan assets $17,026 $13,944
Unrecognized prior service cost 946 1,017
Unrecognized net gain (loss) from past experience 1,241 5,363
Unrecognized transition asset (16,368) (17,537)
------- ---------
Accrued Postretirement liability $ 2,845 $ 2,787
====== ======
Assumptions used in estimating benefit obligations at December 31:
Discount rate 6.75% 7.25%
Average wage increase 4.50% 4.50%
The Company has an Employee Savings Plan (401(k) Plan) in which
substantially all employees are eligible to participate. The 401(k) Plan enables
employees to defer receipt of up to 15% of their compensation and to invest such
funds in a number of investment alternatives. The Company makes matching
contributions in the form of Company common stock for each employee. During the
first five months of 1996, the matching contributions were made into the 401(k)
Plan. Beginning in June 1996, the matching contributions were made into the
Employee Stock Ownership Plan (ESOP). The Company's matching contribution to the
401(k) Plan during the first five months of 1996 was $0.8 million. In June 1996,
all shares of the Company's common stock in the 401(k) Plan were transferred to
the ESOP.
The Company has an ESOP for substantially all its employees. In June 1996,
the Company began making matching contributions to the ESOP based on each
employee's salary deferrals in the 401(k) Plan. The matching contribution
currently equals fifty cents for each dollar of the employee's compensation
deferred, but is not more than three and three-eighths percent of the employee's
annual salary. The Company's matching contributions to the ESOP during 1998,
1997 and the period June 1996 - December 1996 were $1.7 million, $1.7 million
and $0.8 million, respectively.
The Company pays dividends on the shares of stock in the ESOP to the
participant and the Company receives a tax deduction on the dividends paid. The
Company also makes contributions to the ESOP equal to 25% of the dividends paid
to each participant. The Company's annual contributions during 1998, 1997 and
1996 were $270,000, $417,000 and $324,000, respectively.
51
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On May 22, 1995, the Company and the union representing approximately 695
of its operating, maintenance and clerical employees agreed on a three-year
contract, effective May 16, 1995. As part of this agreement, the Company offered
a voluntary early retirement program to 74 employees, who had until January 31,
1996 to accept. The early retirement offer was accepted by 64 employees, and the
Company recognized a charge to earnings in January 1996 of $7.2 million ($4.2
million, after-tax). The employees accepting the offer retired during the first
nine months of 1996. In June 1996, the Company recognized an additional charge
to earnings of $0.9 million ($0.5 million, after-tax) to reflect additional
early retirement costs.
In July 1996, the Company offered a Voluntary Early Retirement Program and
a Voluntary Separation Plan to virtually all of its employees. A total of 163
employees accepted one or the other of these plans. In the third quarter of
1996, the Company recognized a charge to earnings of $14.9 million ($8.7
million, after-tax) to reflect the cost of these plans. The employees accepting
the offer retired on or before December 31, 1997.
(I) JOINTLY OWNED PLANT AND POWER PURCHASE AGREEMENTS
At December 31, 1998, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT IN ACCUMULATED
SHARE SERVICE DEPRECIATION
--------- -------- ------------
(Millions)
Seabrook Unit 1 17.5 % $648 $146
Millstone Unit 3 3.685 135 63
New Haven Harbor Station 93.7 143 78
The Company's share of the operating costs of jointly owned plants is
included in the appropriate expense captions in the Consolidated Statement of
Income.
At December 31, 1998, the Company had two long-term contracts for the
purchase of power. A contract with Wheelabrator Technology, Inc. requires the
Company to purchase all of the energy output of a trash-to-energy cogeneration
facility (Bridgeport RESCO) situated in Bridgeport, Connecticut, through April
2, 2008. A contract between Hydro-Quebec and the New England participants in a
transmission facility linking New England and Quebec, Canada, requires the
Company to purchase its 5.45% participating share of the energy delivered by
Hydro-Quebec over the transmission facility. This contract is scheduled to
expire in September, 2001; but it may be extended. The costs to the Company in
1998 for these two contracts were $26.1 million and $7.0 million, respectively.
There are no annual minimum debt service payments, and no allocable portion of
interest, associated with these contracts. The Company's guaranty liability for
its participating share of the debt financing for the Hydro-Quebec transmission
facility was $6.8 million at December 31, 1998.
(J) UNAMORTIZED CANCELLED NUCLEAR PROJECT
From December 1984 through December 1992, the Company had been recovering
its investment in Seabrook Unit 2, a partially constructed nuclear generating
unit that was cancelled in 1984, over a regulatory approved ten-year period
without a return on its unamortized investment. In the Company's 1992 rate
decision, the DPUC adopted a proposal by the Company to write off its remaining
investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period,
corresponding with the flowback of certain Connecticut Corporation Business Tax
(CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit
2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not
deducted from rate base during the 24-year period of amortization in recognition
of a longer period of time for amortization of the Seabrook Unit 2 balance. As a
result of reducing its remaining unamortized investment in Seabrook Unit 2 with
proceeds from the sale of certain Seabrook Unit 2 equipment, the Company expects
to completely amortize its unamortized investment in the year 2008.
52
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases.
Under this agreement, the financing entity may acquire and/or store natural gas,
coal and fuel oil for sale to the Company, and the Company may purchase these
fossil fuels from the financing entity at a price for each type of fuel that
reimburses the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an inventory of
the fuel determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to May 2000, when it will terminate. The Company discontinued using this fossil
fuel financing arrangement in September 1998. At December 31, 1998, no fossil
fuel purchases were being financed under this agreement. On April 16, 1999, the
Company sold all of its operating non-nuclear generation facilities to an
unaffiliated entity. As a result, the Company will not finance any fuel
purchases under this agreement prior to its termination in May 2000.
The Company also has lease arrangements for data processing equipment,
office equipment, vehicles and office space, including the lease of a
distribution service facility, which is recognized as a capital lease. The gross
amount of assets recorded under capital leases and the related obligations of
those leases as of December 31, 1998 are recorded on the balance sheet.
Future minimum lease payments under capital leases, excluding the Seabrook
sale/leaseback transaction, which is being treated as a long-term financing, are
estimated to be as follows:
(000's)
1999 $ 1,696
2000 1,696
2001 1,696
2002 1,696
2003 1,696
After 2003 16,000
--------
Total minimum capital lease payments 24,480
Less: Amount representing interest 7,626
--------
Present value of minimum capital lease payments $16,854
========
Capitalization of leases has no impact on income, since the sum of the
amortization of a leased asset and the interest on the lease obligation equals
the rental expense allowed for ratemaking purposes.
Operating leases, which are charged to operating expense, consist
principally of a large number of small, relatively short-term, renewable
agreements for a wide variety of equipment. In addition, the Company has an
operating lease for its corporate headquarters. Future minimum lease payments
under this lease are estimated to be as follows:
(000's)
1999 $ 6,426
2000 6,524
2001 6,837
2002 8,168
2003 9,125
2004-2012 91,209
--------
Total $128,289
53
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Rental payments charged to operating expenses in 1998, 1997 and 1996,
including rental payments for its corporate headquarters, were $11.7 million,
$12.2 million and $12.8 million, respectively.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $130.8 million, excluding AFUDC, for 1999 through 2003.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the three nuclear generating
units in which the Company has an interest, the Company will be obligated to pay
its ownership and/or leasehold share of any statutory assessment resulting from
a nuclear incident at any nuclear generating unit. Based on its interests in
these nuclear generating units, the Company estimates its maximum liability
would be $17.8 million per incident. However, any assessment would be limited to
$2.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$3.1 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee.
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from UI. In December of 1996,
Connecticut Yankee filed decommissioning cost estimates and amendments to the
power contracts with its owners with the Federal Energy Regulatory Commission
(FERC). Based on regulatory precedent, this filing seeks confirmation that
Connecticut Yankee will continue to collect from its owners its decommissioning
costs, the unrecovered investment in the Connecticut Yankee Unit and other costs
associated with the permanent shutdown of the Connecticut Yankee Unit. On August
31, 1998, a FERC Administrative Law Judge (ALJ) released an initial decision
regarding Connecticut Yankee's December 1996 filing. The initial decision
contains provisions that would allow Connecticut Yankee to recover,
54
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
through the power contracts with its owners, the balance of its net unamortized
investment in the Connecticut Yankee Unit, but would disallow recovery of a
portion of the return on Connecticut Yankee's investment in the unit. The ALJ's
decision also states that decommissioning cost collections by Connecticut
Yankee, through the power contracts, should continue to be based on a
previously-approved estimate until a new, more reliable estimate has been
prepared and tested. During October of 1998, Connecticut Yankee and its owners
filed briefs setting forth exceptions to the ALJ's initial decision. If this
initial decision is upheld by the FERC, Connecticut Yankee could be required to
write off a portion of the regulatory asset on its Balance Sheet associated with
the retirement of the Connecticut Yankee Unit. In this event, however, the
Company would not be required to record any write-off on account of its 9.5%
ownership share in Connecticut Yankee, because the Company has recorded its
regulatory asset associated with the retirement of the Connecticut Yankee Unit
net of any return on investment. The Company cannot predict, at this time, the
outcome of the FERC proceeding. However, the Company will continue to support
Connecticut Yankee's efforts to contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $9.9
million) and return on investment (approximately $4.7 million) at December 31,
1998, is approximately $32.7 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
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 December 31, 1998, the Company's
guarantee liability for this debt was approximately $6.8 million.
PROPERTY TAXES
The City of New Haven (the City) and the Company have been 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 agreed to pay
the City $14.025 million, subject to Connecticut Superior Court approval of the
settlement and conditioned on the Company receiving authorization from the DPUC
to recover the settlement amount from its retail customers. The DPUC denied the
Company's initial application for such authorization and the City agreed to
extend to December 31, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million. The Company
filed a second application with the DPUC on July 9, 1998, and on December 8,
1998 a Joint Stipulation among the Company, the Office of Consumer Counsel and
the Connecticut Attorney General relative to the recovery of the settlement
amount was filed with the DPUC. On December 30, 1998, the DPUC issued a draft
decision rejecting this Joint Stipulation. The Company filed written exceptions
to this draft decision and requested oral argument on the draft decision; and
the City agreed to extend to March 1, 1999 the time period for obtaining a
favorable DPUC authorization, in return for payment by the Company of an
additional $6 million. On February 10, 1999, the DPUC issued a final decision
rejecting the Joint Stipulation. The Company subsequently waived the condition
to the settlement with the City that the DPUC authorize recovery of the
settlement amount from the Company's retail customers and, on March 5, 1999, the
settlement was approved by the Superior Court. The Company will pay the
remaining $2.025 million of the settlement amount to the City promptly. Based on
the DPUC's final decision, the Company has expensed the $14.025 million
settlement amount in 1998.
55
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water and air quality (particularly "air toxics"
and "global warming"), hazardous waste handling and disposal, toxic substances,
and electric and magnetic fields, the Company may incur substantial capital
expenditures for equipment modifications and additions, monitoring equipment and
recording devices, and it may incur additional operating expenses. Litigation
expenditures may also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful health effects of
electric and magnetic fields. The total amount of these expenditures is not now
determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of December 31, 1998, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities.
Remediation costs, including the repair and/or replacement of approximately 560
linear feet of sheet piling, are currently estimated at $7.5 million. In
addition, the Company is planning to repair and/or replace the remaining
deteriorated sheet piling bordering the English Station property, at an
additional estimated cost of $10 million.
As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company has contracted to sell its Bridgeport Harbor Station and New Haven
Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. Environmental assessments performed
in connection with the marketing of these plants indicate that substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable Connecticut minimum standards following their sale.
The proposed purchaser of the plants has agreed to undertake and pay for the
major portion of this remediation. However, the Company will be responsible for
remediation of the portions of the plant sites that will be retained by it.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
Costs associated with nuclear plant operations include amounts for disposal
of nuclear wastes, including spent fuel, and for the ultimate decommissioning of
the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department
of Energy (DOE) is required to design, license, construct and operate a
permanent repository for high level radioactive wastes and spent nuclear fuel.
The Act requires the DOE to provide for the disposal of spent nuclear fuel and
high level radioactive waste from commercial nuclear plants through contracts
with the owners and generators of such waste; and the DOE has established
disposal fees that are being paid to the federal government by electric
utilities owning or operating nuclear generating units. In return for payment of
the prescribed fees, the federal government was required to take title to and
dispose of the utilities' high level wastes and spent nuclear fuel beginning no
later than January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010 and possibly
not earlier than 2013, notwithstanding the DOE's statutory and contractual
responsibility to begin disposal of high-level radioactive waste and spent fuel
beginning not later than January 31, 1998.
The DOE also announced that, absent a repository, the DOE has no statutory
obligation to begin taking high level wastes and spent nuclear fuel for disposal
by January 1998. However, numerous utilities and states have obtained a judicial
declaration that the DOE has a statutory responsibility to take title to and
dispose of high level wastes and spent nuclear fuel beginning in January 1998,
and that the contracts between the DOE and the plant owners and generators of
such waste will provide a potentially adequate remedy for the latter if the DOE
fails to fulfill its contractual obligations
56
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
by that date. The DOE is contesting these judicial declarations; and it is
unclear at this time whether the United States Congress will enact legislation
to address spent fuel/high level waste disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
operation or decommissioning of nuclear generating units have increased
significantly in recent years and may continue to rise. The cost increases are a
function of increased packaging and transportation costs, and higher fees and
surcharges imposed by the disposal facilities. Currently, the Chem Nuclear LLW
facility at Barnwell, South Carolina, is open to the Connecticut Yankee Unit,
Millstone Unit 3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW
facility at Clive, Utah, is also open to these generating units for portions of
their LLW. All three units have contracts in place for LLW disposal at these
disposal facilities.
Because access to LLW disposal may be lost at any time, Millstone Unit 3
and Seabrook Unit 1 have storage plans that will allow on-site retention of LLW
for at least five years in the event that disposal is interrupted. The
Connecticut Yankee Unit, which has been retired from commercial operation, has a
similar storage program, although disposal of its LLW will take place in
connection with its decommissioning.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
NRC licensing requirements and restrictions are also applicable to the
decommissioning of nuclear generating units at the end of their service lives,
and the NRC has adopted comprehensive regulations concerning decommissioning
planning, timing, funding and environmental reviews. UI and the other owners of
the nuclear generating units in which UI has interests estimate decommissioning
costs for the units and attempt to recover sufficient amounts through their
allowed electric rates, together with earnings on the investment of funds so
recovered, to cover expected decommissioning costs. Changes in NRC requirements
or technology, as well as inflation, can increase estimated decommissioning
costs.
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $497 million (in 1999 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1998 was $2.1 million. UI's share of the fund at December 31, 1998 was
approximately $16.5 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $560 million (in 1999 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during 1998 was $487,000. UI's share of the fund at December 31, 1998 was
approximately $6.5 million. The current decommissioning cost estimate for the
Connecticut Yankee Unit, assuming the prompt removal
57
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
and dismantling of the unit commencing in 1997, is $476 million, of which UI's
share would be $45 million. Through December 31, 1998, $85 million has been
expended for decommissioning. The projected remaining decommissioning cost is
$391 million, of which UI's share would be $37 million. The decommissioning
trust fund for the Connecticut Yankee Unit is also managed by NU. For the
Company's 9.5% equity ownership in Connecticut Yankee, decommissioning costs of
$2.4 million were funded by UI during 1998, and UI's share of the fund at
December 31, 1998 was $25 million.
The Financial Accounting Standards Board (FASB) has issued an exposure
draft related to the accounting for the closure and removal costs of long-lived
assets, including nuclear plant decommissioning. If the proposed accounting
standard were adopted, it may result in higher annual provisions for
decommissioning to be recognized earlier in the operating life of nuclear units
and an accelerated recognition of the decommissioning obligation. The FASB will
be deliberating this issue, and the resulting final pronouncement could be
different from that proposed in the exposure draft.
(N) FAIR VALUE OF FINANCIAL INSTRUMENTS (1)
The estimated fair values of the Company's financial instruments are as
follows:
1998 1997
---- ----
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(000's) (000's)
Cash and temporary cash investments $101,445 $101,445 $32,002 $32,002
Long-term debt (2)(3)(4) $606,342 $611,524 $620,457 $624,192
Interest rate swaps (5) $225,000 $220,877 $225,000 $223,547
Fuel price management instruments(6) - - - ($817)
(1) Equity investments were not valued because they were not considered to be
material.
(2) Excludes the obligation under the Seabrook Unit 1 sale/leaseback agreement.
(3) The fair market value of the Company's long-term debt is estimated by
brokers based on market conditions at December 31, 1998 and 1997,
respectively.
(4) See Note (B), Capitalization - Long-Term Debt.
(5) The fair value of the interest rate swaps is calculated by the counterparty
to the swap agreements using mid-market models and proprietary models.
(6) The fair value of the fuel price management instruments at December 31,
1997 was calculated as the difference between the fuel price within the
swap agreements and the prevailing market price at December 31, 1997
multiplied by the forward swap agreement volumes.
58
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(O) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1998 and 1997 are set forth below:
OPERATING OPERATING NET EARNINGS PER SHARE OF
QUARTER REVENUES INCOME INCOME COMMON STOCK(1)
- ------- --------- --------- ------ ---------------------
(000's) (000's) (000's) Basic Diluted
----- -------
1998
First $162,474 $22,677 $8,962 $.64 $.64
Second 159,792 21,174 8,379 .60 .60
Third 198,601 37,462 26,236 1.87 1.87
Fourth (2) 165,324 15,013 1,495 .10 .10
1997
First (3) $180,917 $28,164 $13,176 $ .93 $.93
Second 164,600 19,544 4,846 .34 .34
Third 197,215 37,680 22,184 1.60 1.59
Fourth 166,297 18,494 3,251 .23 .23
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Operating income, net income and earnings per share for the fourth quarter
of 1998 included an after-tax charge of $8.3 million, associated with a
property tax settlement. See Note (L), "Commitments and Contingencies -
Property Taxes".
(3) Operating income, net income and earnings per share for the first quarter
of 1997 included an after-tax credit of $6.7 million, or $.48 per share, to
provide for the cumulative tax benefits associated with future fossil
generation decommissioning.
(P) SEGMENT INFORMATION
The Company has one reportable operating segment, that of regulated
generation, distribution and sale of electricity. The accounting policies used
for that segment do not differ from those used for nonreportable operating
segments. Revenues from inter-segment transactions are not material and all of
the Company's revenues are derived in the United States.
The revenues from external customers, interest income, interest expense and
depreciation charges of the one reportable segment are identical to the amounts
shown on the Consolidated Statement of Income for each year presented. Income
before taxes of the reportable segment is not materially different from that of
the Company as a whole.
59
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table reconciles the total assets of the reportable segment
with the total assets shown on the Consolidated Balance Sheet at December 31:
1998 1997 1996
---- ---- ----
Total Assets - Regulated Utility $1,892,822 $1,881,883 $1,951,954
Total Assets - Unregulated Subsidiaries 136,062 116,830 101,498
Total Assets - Elimination (85,474) (80,179) (76,712)
-------- -------- --------
Total Consolidated Assets $1,943,410 $1,918,534 $1,976,740
========= ========= =========
(Q) RESTATEMENT OF FINANCIAL RESULTS
During the third quarter of 1999, the Company has restated its financial
statements for 1998, 1997 and 1996 for matters related to the timing of American
Payment Systems ("APS") agency collection reserves and for certain line loss
factors that affect the calculation of unbilled revenues. The Company had
consultations with the staff of the Securities and Exchange Commission and its
independent accountants in determining these restated amounts.
The following tables summarize the restatements that the Company has made
on net income, earnings per share and retained earnings.
Increase (decrease) in net income:
FOR THE YEAR ENDED DECEMBER 31,
1998 1997 1996
---- ---- ----
DESCRIPTION (000'S)
-----------
1998 APS charge $2,882 $(1,643) $(1,239)
1997 unbilled revenues - (691) 691
1996 APS charge - - 497
----- ----- -----
Net increase (decrease) to net income 2,882 (2,334) (51)
Net income applicable to common
shareholders, as originally reported 42,010 45,634 40,606
------ ------ ------
Net income applicable to common
shareholders, as restated $44,892 $43,300 $40,555
====== ====== ======
FOR THE YEAR ENDED DECEMBER 31,
DESCRIPTION 1998 1997 1996
----------- ---- ---- ----
Earnings per share, as originally reported
- Basic $3.00 $3.27 $2.88
- Diluted $3.00 $3.26 $2.87
Earnings per share, as restated
- Basic $3.20 $3.10 $2.88
- Diluted $3.20 $3.09 $2.87
AS OF DECEMBER 31,
1998 1997 1996
---- ---- ----
DESCRIPTION (000'S)
-----------
Retained earnings, as originally reported $163,847 $162,226 $156,847
Net effect of restatements, described above - (2,882) (548)
------- -------- --------
Retained earnings, as restated $163,847 $159,344 $156,299
======== ======== ========
60
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The impact of the adjustments described above was to reduce retained
earnings as of January 1, 1996 by $497.
Included in restricted cash at December 31, 1998, 1997, and 1996 are
amounts of $23,056, $21,063 and $16,682, respectively, representing collections
by APS agents that are held in APS agent accounts prior to transmittal to the
respective APS customers. In addition the Company has included in other accounts
receivable at December 31, 1998, 1997 and 1996 amounts of $26,768, $23,284 and
$0, respectively, which represent collections by APS agents not yet deposited
into APS bank accounts. A corresponding accounts payable has been recorded to
reflect the portions of these collections owed to APS customers, as well as the
amount of restricted cash presented above. The Company had previously presented
its consolidated balance sheet net of these accounts receivable and accounts
payable amounts.
In addition, the Company has revised Schedule II on page S1 to reflect the
restatement of additional reserves for uncollectible accounts related to APS
agent collections.
61
[LETTERHEAD OF PRICEWATERHOUSECOOPERS LLP]
Report of Independent Accountants
To the Board of Directors and Shareholders
of The United Illuminating Company:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of retained earnings and of cash flows
present fairly, in all material respects, the financial position of The United
Illuminating Company and its subsidiaries (the "Company") at December 31, 1998,
1997 and 1996 and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As described in Note Q, the Company revised its December 31, 1998, 1997 and 1996
consolidated financial statements with respect to certain previously recorded
charges.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
New York, NY
February 12, 1999, except for Note Q,
as to which date is November 1, 1999.
62
[LETTERHEAD OF PRICEWATERHOUSECOOPERS LLP]
Report of Independent Accountants on
Financial Statement Schedule
To the Board of Directors and Shareholders
of The United Illuminating Company:
Our audits of the consolidated financial statements referred to in our report
dated February 12, 1999, except as to the restatement of certain expense amounts
described in Note Q, which is as of November 1, 1999 appearing in the 1998
Annual Report on Form 10-K/A-2 of The United Illuminating Company also included
an audit of the Financial Statement Schedule on page S-1 of this Form 10-K/A-2.
In our opinion, this Financial Statement Schedule presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
New York, NY
February 12, 1999, except for Note Q,
as to which the date is November 1, 1999.
63
[LETTERHEAD OF PRICEWATERHOUSECOOPERS LLP]
Consent of Independent Accountants
We hereby consent to the incorporation by reference in these Registration
Statements on Form S-3 (No. 33-50221, No. 33-50445, No. 33-55461 and No.
33-64003) of our report dated February 12, 1999, except as to the restatement of
certain expense amounts described in Note Q, which is as of November 1, 1999,
relating to the financial statements appearing in The United Illuminating
Company's Annual Report on Form 10-K/A-2 for the year ended December 31, 1998.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
New York, NY
November 1, 1999
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act of
1934, as amended, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
Dated: 11/03/99 By: /s/ Robert L. Fiscus
---------------- ------------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
65
SCHEDULE II
VALUATION AND
QUALIFYING ACCOUNTS
THE UNITED ILLUMINATING COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(Thousands of Dollars)
COL. A COL. B COL. C COL. D COL. E
------ ------ ------ ------ ------
ADDITIONS
-------------------------------
BALANCE AT CHARGED TO CHARGED BALANCE AT
BEGINNING COSTS AND TO OTHER END OF
CLASSIFICATION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
-------------- ---------- ---------- -------- ---------- ----------
RESERVE DEDUCTION FROM
ASSET TO WHICH IT APPLIES:
Reserve for uncollectible
accounts (consolidated):
1998 $7,197 $5,745 - $10,511 (A) $2,431
1997 $8,929 $9,832 - $11,564 (A) $7,197
1996 $7,133 $16,080 - $14,284 (A) $8,929
RESERVE DEDUCTION FROM
ASSET TO WHICH IT APPLIES:
Reserve for uncollectible
accounts (American
Payment Systems,
agent collections
1998 $5,392 $361 - $5,208 (A) $545
1997 $6,545 $3,425 - $4,578 (A) $5,392
1996 $796 $6,179 - $430 (A) $6,545
- ------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
S-1