SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported) February 13, 1998
The Cleveland Electric Illuminating Company
(Exact name of Registrant as specified in its charter)
Ohio 1-2323 34-0150020
(State or other juris- (Commission (I.R.S. Employer
diction of incorporation) File Number) Identification No.)
c/o FirstEnergy Corp.
76 South Main Street, Akron, Ohio 44308
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (800)736-3402
Item 5. Other Events
Ohio Edison Company reports audited consolidated
financial statements for the year ended December 31, 1997 and
related matters. Such financial statements and related matters
consist of the following:
1) Consolidated Statements of Income
2) Consolidated Balance Sheets
3) Consolidated Statements of Capitalization
4) Consolidated Statements of Retained Earnings
5) Consolidated Statements of Capital Stock and
Other Paid-In Capital
6) Consolidated Statements of Cash Flows
7) Consolidated Statements of Taxes
8) Notes to Consolidated Financial Statements
9) Report of Independent Public Accountants
10) Management's Discussion and Analysis of Results
of Operations and Financial Condition
11) Consent of Independent Public Accountants
Item 7. Exhibits
Exhibit
Number
- -------
24 Consent of Independent Public Accountants.
- 1 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Nov. 8 - | Jan. 1 - For the Years Ended December 31,
| --------------------------------
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- -----------------------------------------------------|----------------------------------------------
| (In thousands)
<S> <C> | <C> <C> <C>
OPERATING REVENUES $253,963 | $1,529,014 $1,789,961 $1,768,737
-------- | ---------- ---------- ----------
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power 51,381 | 359,048 407,632 413,391
Nuclear operating costs 15,465 | 77,228 96,150 95,791
Other operating costs 61,036 | 303,558 385,853 377,720
-------- | ---------- ---------- ----------
Total operation and maintenance |
expenses 127,882 | 739,834 889,635 886,902
Provision for depreciation and |
amortization 28,111 | 189,937 218,539 208,812
Amortization (deferral) of net |
regulatory assets 3,867 | 21,890 26,076 (36,148)
General taxes 33,912 | 194,400 229,856 229,962
Income taxes 10,689 | 75,621 67,235 81,310
-------- | ---------- ---------- ----------
Total operating expenses and taxes 204,461 | 1,221,682 1,431,341 1,370,838
-------- | ---------- ---------- ----------
|
OPERATING INCOME 49,502 | 307,332 358,620 397,899
|
OTHER INCOME (LOSS) 4,572 | (2,476) (2,089) 31,298
-------- | ---------- ---------- ----------
|
INCOME BEFORE NET INTEREST CHARGES 54,074 | 304,856 356,531 429,197
-------- | ---------- ---------- ----------
|
NET INTEREST CHARGES: |
Interest on long-term debt 35,300 | 197,323 229,491 238,684
Allowance for borrowed funds used |
during construction (631) | (1,928) (2,110) (2,701)
Other interest expense 115 | 14,270 12,597 9,495
-------- | ---------- ---------- ----------
Net interest 34,784 | 209,665 239,978 245,478
-------- | ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 19,290 | 95,191 116,553 183,719
|
EXTRAORDINARY ITEM (NET OF INCOME |
TAXES) (Note 1) - | (324,438) - -
-------- | ---------- ---------- ----------
|
NET INCOME (LOSS) 19,290 | (229,247) 116,553 183,719
|
PREFERRED STOCK DIVIDEND |
REQUIREMENTS - | 45,029 38,743 42,444
-------- | ---------- ---------- ----------
|
EARNINGS (LOSS) ON COMMON STOCK $ 19,290 | $ (274,276) $ 77,810 $ 141,275
======== | ========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
- 2 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
<CAPTION>
At December 31, 1997 1996
- --------------------------------------------------------------------------------------------
(In thousands)
<S> <C> <C>
ASSETS |
UTILITY PLANT: |
In service $4,578,649 | $7,330,963
Less--Accumulated provision for depreciation 1,470,084 | 2,415,226
---------- | ----------
3,108,565 | 4,915,737
---------- | ----------
|
Construction work in progress-- |
Electric plant 41,261 | 56,853
Nuclear fuel 6,833 | 10,629
---------- | ----------
48,094 | 67,482
---------- | ----------
3,156,659 | 4,983,219
---------- | ----------
|
OTHER PROPERTY AND INVESTMENTS: |
Shippingport Capital Trust (Note 3) 575,084 | -
Nuclear plant decommissioning trusts 105,334 | 75,573
Other 21,482 | 20,805
---------- | ----------
701,900 | 96,378
---------- | ----------
|
CURRENT ASSETS: |
Cash and cash equivalents 33,775 | 30,273
Receivables-- |
Customers 29,759 | 4,339
Associated companies 8,695 | 5,634
Other 98,077 | 170,736
Materials and supplies, at average cost-- |
Owned 47,489 | 51,686
Under consignment 25,411 | 23,655
Prepayments and other 57,763 | 58,235
---------- | ----------
300,969 | 344,558
---------- | ----------
DEFERRED CHARGES: |
Regulatory assets 579,711 | 1,349,694
Goodwill 1,552,483 | -
Property taxes 125,204 | 129,048
Other 23,358 | 59,400
---------- | ----------
2,280,756 | 1,538,142
---------- | ----------
$6,440,284 | $6,962,297
========== | ==========
CAPITALIZATION AND LIABILITIES |
|
CAPITALIZATION (See Consolidated Statements of Capitalization): |
Common stockholder's equity $ 950,904 | $1,044,283
Preferred stock-- |
Not subject to mandatory redemption 238,325 | 238,325
Subject to mandatory redemption 183,174 | 186,118
Long-term debt 3,189,590 | 2,523,030
---------- | ----------
4,561,993 | 3,991,756
---------- | ----------
|
CURRENT LIABILITIES: |
Currently payable long-term debt and preferred stock 121,965 | 196,260
Accounts payable-- |
Associated companies 56,109 | 59,815
Other 90,737 | 82,693
Notes payable to associated companies 56,802 | 111,618
Accrued taxes 194,394 | 183,998
Accrued interest 67,896 | 52,487
Other 52,297 | 58,900
---------- | ----------
640,200 | 745,771
---------- | ----------
DEFERRED CREDITS: |
Accumulated deferred income taxes 496,437 | 1,305,601
Accumulated deferred investment tax credits 96,131 | 183,026
Pensions and other postretirement benefits 198,642 | 72,843
Other 446,881 | 663,300
---------- | ----------
1,238,091 | 2,224,770
---------- | ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES |
(Notes 3 and 6 ) ---------- | ----------
$6,440,284 | $6,962,297
========== | ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these balance sheets.
</TABLE>
- 3 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
At December 31, 1997 | 1996
- ---------------------------------------------------------------------------------------- |-----------
(Dollars in thousands, except per share amounts) |
<S> <C> | <C>
COMMON STOCKHOLDER'S EQUITY: |
Common stock, without par value, authorized 105,000,000 shares-- |
79,590,689 shares outstanding $ 931,614 |$1,241,287
Other paid-in capital - | 79,454
Retained earnings (deficit) (Note 4A) 19,290 | (276,458)
---------- |----------
Total common stockholder's equity 950,904 | 1,044,283
---------- |----------
|
|
Number of Shares Optional |
Outstanding Redemption Price |
---------------- --------------------- |
1997 1996 Per Share Aggregate |
---- ---- --------- --------- |
<S> <C> <C> <C> <C> |
PREFERRED STOCK (Note 4B): |
Without par value, authorized |
4,000,000 shares |
Not Subject to Mandatory |
Redemption: |
$ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 50,000 | 50,000
$ 7.56 Series B 450,000 450,000 102.26 46,017 45,071 | 45,071
Adjustable Series L 474,000 474,000 100.00 47,400 46,404 | 46,404
$42.40 Series T 200,000 200,000 500.00 100,000 96,850 | 96,850
--------- --------- --------- --------- |----------
1,624,000 1,624,000 $ 243,917 238,325 | 238,325
========= ========= ========= --------- |----------
Subject to Mandatory |
Redemption (Note 4C): |
$ 7.35 Series C. 110,000 120,000 $ 101.00 $ 11,110 11,110 | 12,000
$88.00 Series E 9,000 12,000 1,007.65 9,069 9,000 | 12,000
$ 9.125 Series N - 150,000 - - - | 14,794
$91.50 Series Q 42,858 53,572 1,000.00 42,858 42,858 | 53,572
$88.00 Series R 50,000 50,000 - - 55,000 | 50,000
$90.00 Series S 74,000 74,000 - - 79,920 | 73,260
Redemption within one year (14,714)| (29,508)
--------- --------- -------- --------- |----------
285,858 459,572 $ 63,037 183,174 | 186,118
========= ========= ======== --------- |----------
LONG-TERM DEBT (Note 4D): |
First mortgage bonds: |
7.625% due 2002 195,000 | 195,000
7.375% due 2003 100,000 | 100,000
8.750% due 2005 75,000 | 75,000
9.500% due 2005 300,000 | 300,000
9.250% due 2009 - | 50,000
8.375% due 2011 125,000 | 125,000
8.375% due 2012 75,000 | 75,000
9.375% due 2017 - | 300,000
10.000% due 2020 - | 100,000
9.000% due 2023 150,000 | 150,000
---------- |----------
Total first mortgage bonds 1,020,000 | 1,470,000
---------- |----------
|
Unsecured notes: |
5.500% due 1997 - | 110
6.700% due 2006 19,500 | 20,000
5.700% due 2008 7,300 | 7,600
6.700% due 2011 5,500 | 5,500
5.875% due 2012 14,300 | 14,300
---------- |----------
Total unsecured notes 46,600 | 47,510
- 4 -
</TABLE>
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
<CAPTION>
At December 31, 1997 1996
- ---------------------------------------------------------------------------------------------------
(In thousands)
<S> <C> <C>
LONG-TERM DEBT: (Cont.)
Secured notes:
9.450% due 1997 - | 43,000
8.150% due 1998 7,500 | 7,500
8.160% due 1998 5,000 | 5,000
8.170% due 1998 11,000 | 11,000
8.260% due 1998 2,500 | 2,500
8.330% due 1998 25,000 | 25,000
8.870% due 1998 10,000 | 10,000
9.000% due 1998 5,000 | 5,000
7.250% due 1999 12,000 | 12,000
7.670% due 1999 3,000 | 3,000
7.770% due 1999 17,000 | 17,000
7.850% due 1999 25,000 | 25,000
8.290% due 1999 10,000 | 10,000
9.250% due 1999 52,500 | 52,500
9.300% due 1999 25,000 | 25,000
7.190% due 2000 175,000 | -
7.420% due 2001 10,000 | 10,000
8.540% due 2001 3,000 | 3,000
8.550% due 2001 5,000 | 5,000
8.560% due 2001 3,500 | 3,500
8.680% due 2001 15,000 | 15,000
9.050% due 2001 5,000 | 5,000
9.200% due 2001 15,000 | 15,000
7.850% due 2002 5,000 | 5,000
8.130% due 2002 28,000 | 28,000
7.750% due 2003 15,000 | 15,000
7.670% due 2004 280,000 | -
7.000% due 2006-2009 1,910 | 64,500
7.130% due 2007 120,000 | -
7.430% due 2009 150,000 | -
6.000% due 2011* 5,650 | 5,650
6.000% due 2011* 1,700 | 1,700
6.200% due 2013 - | 47,500
8.000% due 2013 78,700 | 78,700
3.786% due 2015* 39,835 | 39,835
6.000% due 2017* 1,285 | 1,285
7.880% due 2017 300,000 | -
3.771% due 2018* 72,795 | 72,795
3.800% due 2020* 47,500 | -
6.000% due 2020* 40,900 | 40,900
6.000% due 2020* 9,100 | 9,100
6.000% due 2020 62,560 | -
6.100% due 2020 70,500 | -
9.520% due 2021 7,500 | 7,500
9.750% due 2022 - | 70,500
6.850% due 2023 30,000 | 30,000
8.000% due 2023 73,800 | 73,800
7.625% due 2025 53,900 | 53,900
7.700% due 2025 43,800 | 43,800
7.750% due 2025 45,150 | 45,150
---------- |----------
Total secured notes 2,026,585 | 1,044,615
---------- |----------
|
Capital lease obligations (Note 3) 98,504 | 133,407
---------- |----------
Net unamortized premium (discount) on debt 105,152 | (5,750)
---------- |----------
Long-term debt due within one year (107,251)| (166,752)
---------- |----------
Total long-term debt 3,189,590 | 2,523,030
---------- |----------
TOTAL CAPITALIZATION $4,561,993 |$3,991,756
========== |==========
<FN>
*Denotes variable rate issue with December 31, 1997 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
- 5 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
Nov. 8 - | Jan. 1 - For the Years Ended December 31,
| --------------------------------
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- -----------------------------------------------------|----------------------------------------------
| (In thousands)
<S> <C> | <C> <C> <C>
Balance at beginning of period $ - | $(276,458) $(193,146) $(261,521)
Net income (loss) 19,290 | (229,247) 116,553 183,719
------- | --------- --------- ---------
19,290 | (505,705) (76,593) (77,802)
- -----------------------------------------------------|--------------------------------------------
Cash dividends on preferred stock - | 35,848 38,734 40,694
Cash dividends on common stock - | 123,602 160,816 74,213
Purchase accounting fair value |
adjustment - | (665,387) - -
Other, primarily preferred stock |
redemption expenses - | 232 315 437
------- | --------- --------- ---------
- | (505,705) 199,865 115,344
------- | --------- --------- ---------
Balance at end of period (Note 4A) $19,290 | $ - $(276,458) $(193,146)
=================================================================================================
CONSOLIDATED STATEMENTS OF CAPITAL STOCK AND OTHER PAID-IN CAPITAL
Preferred Stock
------------------------------------------
Not Subject to Subject to
Common Stock Mandatory Redemption Mandatory Redemption
------------------------------ -------------------- ---------------------
Other
Number Carrying Paid-In Number Carrying Number Carrying
of Shares Value Capital of Shares Value of Shares Value
--------- -------- ------- --------- -------- --------- --------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, January 1, 1995 79,590,689 $1,241,087 $78,624 1,650,000 $240,871 868,766 $281,562
Redemptions--
$ 7.35 Series C (10,000) (1,000)
$ 88.00 Series E (3,000) (3,000)
Adjustable Series M (100,000) (9,800)
$ 9.125 Series N 35 (110,766) (10,924)
$ 91.50 Series Q 51 (10,714) (10,714)
$ 90.00 Series S 111 (1,000) (990)
- ---------------------------------------------------------------------------------------------------
Balance, December 31, 1995 79,590,689 1,241,284 78,624 1,650,000 240,871 633,286 245,134
Reclassification of
$90.00 Series S Gain (111) 111
Unrealized loss on
securities (6)
Redemptions--
Adjustable Series L 7 725 (26,000) (2,546)
$ 7.35 Series C (10,000) (1,000)
$ 88.00 Series E (3,000) (3,000)
$ 9.125 Series N 25 (150,000) (14,794)
$ 91.50 Series Q 82 (10,714) (10,714)
Balance, December 31, 1996 79,590,689 1,241,287 79,454 1,624,000 238,325 459,572 215,626
Equity contributions
from parent 4,500
Redemptions--
$ 7.35 Series C (10,000) (1,000)
$ 88.00 Series E (3,000) (3,000)
$ 9.125 Series N 25 (150,000) (14,794)
$ 91.50 Series Q (10,714) (10,714)
___________________________________________________________________________________________________
Purchase accounting
fair value adjustments--
Common Stock (309,698) (83,954)
$ 7.35 Series C 110
$ 88.00 Series R 5,000
$ 90.00 Series S 6,660
- ---------------------------------------------------------------------------------------------------
Balance, December 31, 1997 79,590,689 $ 931,614 $ - 1,624,000 $238,325 285,858 $197,888
===================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
- 6 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Nov. 8 - | Jan. 1 - For the Years Ended December 31,
| --------------------------------
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- -----------------------------------------------------|----------------------------------------------
| (In thousands)
<S> <C> | <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net Income (Loss) $ 19,290 | $(229,247) $116,553 $183,719
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and |
amortization 28,111 | 189,937 218,539 208,812
Nuclear fuel and lease amortization 7,393 | 42,577 45,987 70,745
Other amortization, net 3,867 | 21,890 26,076 (64,641)
Deferred income taxes, net 7,723 | (126,693) 24,973 56,063
Investment tax credits, net (822)| (6,670) (7,992) (12,566)
Allowance for equity funds used |
during construction (140)| (1,647) (2,014) (2,173)
Extraordinary loss - | 499,135 - -
Receivables 51,213 | (3,974) 586 (12,927)
Net proceeds from accounts |
receivable securitization - | - 64,891 -
Materials and supplies (3,922)| 6,363 25,589 9,818
Accounts payable (777)| (7,938) (6,344) 1,084
Other 18,839 | (2,566) 10,992 (7,996)
-------- | -------- -------- --------
Net cash provided from operating |
activities 130,775 | 381,167 517,836 429,938
-------- | -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing-- |
Long-term debt - | 1,176,781 (307) 432,052
Short-term borrowings, net 703 | - 106,618 -
Redemptions and Repayments-- |
Preferred stock - | 29,714 31,528 36,670
Long-term debt 43,500 | 701,843 310,177 481,426
Short-term borrowings, net - | 55,519 - 53,100
Dividend Payments-- |
Common stock 34,785 | 88,816 160,816 74,213
Preferred stock 7,191 | 29,311 39,325 42,951
-------- | --------- -------- --------
Net cash provided from (used for)
financing activities (84,773)| 271,578 (435,535) (256,308)
-------- | --------- -------- --------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions 17,943 | 104,230 105,588 151,038
Capital trust investments 16,248 | 558,836 - -
Other (4,288)| 2,276 16,210 18,465
-------- | --------- -------- --------
Net cash used for investing activities 29,903 | 665,342 121,798 169,503
-------- | --------- -------- --------
Net increase (decrease) in cash and cash |
equivalents 16,099 | (12,597) (39,497) 4,127
Cash and cash equivalents at beginning |
of period 17,676 | 30,273 69,770 65,643
-------- | --------- -------- --------
Cash and cash equivalents at end of |
period $ 33,775 | $ 17,676 $ 30,273 $ 69,770
======== | ========= ======== ========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Period-- |
Interest (net of amounts capitalized) $ 36,000 | $ 188,000 $237,000 $214,000
======== | ========= ======== ========
Income taxes $ 9,000 | $ 26,300 $ 29,732 $ 65,900
======== | ========= ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
- 7 -
<TABLE>
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
<CAPTION>
Nov. 8 - | Jan. 1 - For the Years Ended December 31,
| --------------------------------
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- -----------------------------------------------------|----------------------------------------------
| (In thousands)
<S> <S> | <S> <S> <S>
GENERAL TAXES: |
Real and personal property $ 17,707 | $ 114,393 $ 132,582 $ 134,346
State gross receipts 13,302 | 65,966 78,109 76,806
Social security and unemployment 1,548 | 6,296 9,127 9,145
Other 1,355 | 7,745 10,038 9,665
-------- | --------- ---------- ----------
Total general taxes $ 33,912 | $ 194,400 $ 229,856 $ 229,962
======== | ========= ========== ==========
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal $ 6,969 | $ 37,605 $ 44,147 $ 39,499
State (1) 159 | - - -
-------- | --------- ---------- ----------
7,128 | 37,605 44,147 39,499
-------- | --------- ---------- ----------
Deferred, net- |
Federal 7,617 | (126,693) 24,973 56,063
State (1) 106 | - - -
-------- | --------- ---------- ----------
7,723 | (126,693) 24,973 56,063
-------- | --------- ---------- ----------
Investment tax credit amortization (822) | (6,670) (7,992) (12,566)
-------- | --------- ---------- ----------
Total provision for income taxes $ 14,029 | $ (95,758) $ 61,128 $ 82,996
======== | ========= ========== ==========
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income $ 10,689 | $ 75,621 $ 67,235 $ 81,310
Other income 3,340 | 3,318 (6,107) 1,686
Extraordinary item - | (174,697) - -
--------- | --------- ---------- ----------
Total provision for income taxes $ 14,029 | $ (95,758) $ 61,128 $ 82,996
========= | ========= ========== ==========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for |
income taxes $ 33,319 | $(325,005) $ 177,681 $ 266,715
========= | ========= ========== ==========
Federal income tax expense at |
statutory rate $ 11,662 | $(113,752) $ 62,188 $ 93,350
Increases (reductions) in taxes |
resulting from- |
Amortization of investment tax credits (822) | (6,670) (7,992) (12,566)
Depreciation - | 14,780 7,853 7,915
Other, net 3,189 | 9,884 (921) (5,703)
--------- | --------- ---------- ----------
Total provision for income taxes $ 14,029 | $ (95,758) $ 61,128 $ 82,996
========= | ========= ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences $ 676,853 | $1,482,000 $1,468,000
Deferred nuclear expense 133,281 | 134,000 139,000
Deferred sale and leaseback costs (118,611) | (121,000) (123,000)
Unamortized investment tax credits (42,743) | (95,000) (99,000)
Unused alternative minimum tax credits (133,442) | (173,733) (132,647)
Other (18,901) | 79,334 45,907
--------- | ---------- ----------
Net deferred income tax liability $ 496,437 | $1,305,601 $1,298,260
========= | ========== ==========
|
<FN>
(1) For periods prior to November 8, 1997, state income taxes
are included in the General Taxes section above. These amounts are
not material and no restatement was made.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
- 8 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The
Cleveland Electric Illuminating Company (Company) and its wholly
owned subsidiary, Centerior Funding Corporation (Centerior
Funding). The subsidiary was formed in 1995 to serve as the
transferor in connection with an accounts receivable
securitization completed in 1996. All significant intercompany
transactions have been eliminated. The Company is a wholly owned
subsidiary of FirstEnergy Corp. (FirstEnergy). Prior to the
merger in November 1997 (see Note 2), the Company and The Toledo
Edison Company (TE) were the principal operating subsidiaries of
Centerior Energy Corporation (Centerior). The merger was
accounted for using the purchase method of accounting in
accordance with generally accepted accounting principles, and the
applicable effects were reflected on the separate financial
statements of Centerior's direct subsidiaries as of the merger
date. Accordingly, the post-merger financial statements reflect a
new basis of accounting, and pre-merger period and post-merger
period financial results (separated by a heavy black line) are
presented. The Company follows the accounting policies and
practices prescribed by The Public Utilities Commission of Ohio
(PUCO) and the Federal Energy Regulatory Commission (FERC). The
preparation of financial statements in conformity with generally
accepted accounting principles requires management to make
periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses. Certain
prior year amounts have been reclassified to conform with the
current year presentation.
REVENUES-
The Company's principal business is providing electric
service to customers in northeastern Ohio. The Company's retail
customers are metered on a cycle basis. Revenue is recognized
for unbilled electric service through the end of the year.
Receivables from customers include sales to
residential, commercial and industrial customers located in the
Company's service area and sales to wholesale customers. There
was no material concentration of receivables at December 31, 1997
or 1996, with respect to any particular segment of the Company's
customers.
In May 1996, the Company and TE began to sell on a
daily basis substantially all of their retail customer accounts
receivable to Centerior Funding under an asset-backed
securitization agreement which expires in 2001. In July 1996,
Centerior Funding completed a public sale of $150 million of
receivables-backed investor certificates in a transaction that
qualified for sale accounting treatment.
REGULATORY PLAN-
FirstEnergy's Rate Reduction and Economic Development
Plan for the Company was approved in January 1997, to become
effective upon consummation of the merger. The regulatory
plan initially maintains current base electric rates for the
Company through December 31, 2005. At the end of the regulatory
plan period, the Company's base rates will be reduced by $217
- 9 -
million (approximately 15 percent below current levels). The
regulatory plan also revised the Company's fuel cost recovery
method. The Company formerly recovered fuel-related costs not
otherwise included in base rates from retail customers through a
separate energy rate. In accordance with the regulatory plan, the
Company's fuel rate will be frozen through the regulatory plan
period, subject to limited periodic adjustments. As part of the
regulatory plan, transition rate credits were implemented for
customers, which are expected to reduce operating revenues for
the Company by approximately $280 million during the regulatory
plan period.
All of the Company's regulatory assets related to its
nonnuclear operations are being recovered under provisions of the
regulatory plan (see Regulatory Assets). The Company recognized
a fair value purchase accounting adjustment to reduce nuclear plant
by $1.71 billion in connection with the FirstEnergy merger (see
Note 2); that fair value adjustment recognized for financial reporting
purposes will ultimately satisfy the $1.4 billion asset reduction
commitment contained in the regulatory plan. For regulatory purposes,
the Company will recognize the $1.4 billion of accelerated
amortization over the rate plan period.
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of
construction (except for the Company's nuclear generating units
which were adjusted to fair value in 1997), including payroll and
related costs such as taxes, employee benefits, administrative
and general costs and financing costs (including allowance for
funds used during construction).
The Company provides for depreciation on a straight-
line basis at various rates over the estimated lives of property
included in plant in service. In its April 1996 rate order, the
PUCO approved depreciation rates for the Company of 2.88% for
nuclear property and 3.23 % for nonnuclear property. The
annualized composite rate was approximately 2.8% for the post-
merger period.
Annual depreciation expense includes approximately
$11.7 million for future decommissioning costs applicable to the
Company's ownership interests in three nuclear generating units.
The Company's share of the future obligation to decommission
these units is approximately $406 million in current dollars and
(using a 3.5% escalation rate) approximately $987 million in
future dollars. The estimated obligation and the escalation rate
were developed based on site-specific studies. Payments for
decommissioning are expected to begin in 2016, when actual
decommissioning work begins. The Company has recovered
approximately $99 million for decommissioning through its
electric rates from customers through December 31, 1997. If the
actual costs of decommissioning the units exceed the funds
accumulated from investing amounts recovered from customers, the
Company expects that additional amount to be recoverable from its
customers. The Company has approximately $105.3 million invested
in external decommissioning trust funds as of December 31, 1997.
Earnings on these funds are reinvested with a corresponding
increase to the decommissioning liability. The Company has also
recognized an estimated liability of approximately $11.2 million
at December 31, 1997 related to decontamination and
decommissioning of nuclear enrichment facilities operated by the
United States Department of Energy (DOE), as required by the
Energy Policy Act of 1992.
- 10 -
The Financial Accounting Standards Board (FASB) issued
a proposed accounting standard for nuclear decommissioning trusts
in February 1996. If the standard is adopted as proposed: (1)
annual provisions for decommissioning could increase; (2) the net
present value of estimated decommissioning costs could be
recorded as a liability; and (3) income from the external
decommissioning trusts could be reported as investment income.
The FASB indicated in October 1997 that it plans to continue work
on the proposal in 1998.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, TE, Duquesne Light Company, Ohio Edison
Company (OE) and its wholly owned subsidiary, Pennsylvania Power
Company (Penn), constitute the Central Area Power Coordination
Group (CAPCO). The CAPCO Companies own and/or lease, as tenants
in common, various power generating facilities. Each of the
companies is obligated to pay a share of the costs associated
with any jointly owned facility in the same proportion as its
interest. The Company's portion of operating expenses associated
with jointly owned facilities is included in the corresponding
operating expenses on the Consolidated Statements of Income. The
amounts reflected on the Consolidated Balance Sheet under utility
plant at December 31, 1997 include the following:
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- --------------------------------------------------------------------------
(In millions)
Bruce Mansfield
Units 1, 2, and 3 $ 62.0 $ 18.1 $ .6 19.92%
Beaver Valley Unit 2 342.4 3.5 1.2 24.47%
Davis-Besse 200.1 - 3.6 51.38%
Perry 521.6 - 3.3 31.11%
Eastlake Unit 5 159.9 94.6 .3 68.80%
Seneca 64.9 24.3 .1 80.00%
- --------------------------------------------------------------------------
Total $1,350.9 $140.5 $ 9.1
==========================================================================
The Bruce Mansfield Plant is being leased through a
sale and leaseback transaction (see Note 3) and the above related
amounts represent construction expenditures subsequent to the
transaction. The Seneca Unit is jointly owned by the Company and
a non-CAPCO company.
NUCLEAR FUEL-
The Company leases its nuclear fuel and pays for the
fuel as it is consumed (see Note 3). The Company amortizes the
cost of nuclear fuel based on the rate of consumption. The
Company's electric rates include amounts for the future disposal
of spent nuclear fuel based upon the payments to the DOE.
INCOME TAXES-
Details of the total provision for income taxes are
shown on the Consolidated Statements of Taxes. Deferred income
taxes result from timing differences in the recognition of
revenues and expenses for tax and accounting purposes. Investment
tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The
- 11 -
liability method is used to account for deferred income taxes.
Deferred income tax liabilities related to tax and accounting
basis differences are recognized at the statutory income tax
rates in effect when the liabilities are expected to be paid.
Alternative minimum tax credits of $133 million, which may be
carried forward indefinitely, are available to reduce future
federal income taxes.
RETIREMENT BENEFITS-
Centerior had sponsored jointly with the Company, TE
and Centerior Service Company (Service Company) a noncontributing
pension plan (Centerior Pension Plan) which covered all employee
groups. Upon retirement, employees receive a monthly pension
generally based on the length of service. Under certain
circumstances, benefits can begin as early as age 55. The funding
policy was to comply with the Employee Retirement Income Security
Act of 1974 guidelines. In December 1997, the Centerior Pension
Plan was merged into the FirstEnergy pension plans. In connection
with the merger, the Company recorded fair value purchase accounting
adjustments to recognize the net gain, prior service cost, and net
transition asset (obligation) associated with the pension and post
retirement benefit plans.
The following sets forth the funded status of the
former Centerior Pension Plan. The Company's share of the former
Centerior Pension Plan's total projected benefit obligation
approximates 70% at December 31, 1997.
At December 31, 1997 1996
- ---------------------------------------------------------------
(In millions)
Actuarial present value of benefit |
obligations: |
Vested benefits $418.9 | $325.8
Nonvested benefits 30.5 | 15.8
- -----------------------------------------------------|--------
Accumulated benefit obligation $449.4 | $341.6
=====================================================|========
Plan assets at fair value $461.9 | $420.8
Actuarial present value of |
projected benefit obligation 533.4 | 395.0
- -----------------------------------------------------|--------
Projected benefit obligation in excess of |
plan assets 71.5 | (25.8)
Unrecognized net gain (loss) (3.0)| 55.0
Unrecognized prior service cost - | (14.2)
Unrecognized net transition asset - | 32.3
- -----------------------------------------------------|--------
Net pension liability $ 68.5 | $ 47.3
==============================================================
The assets of the Centerior Pension Plan consisted
primarily of investments in common stock, bonds, guaranteed
investment contracts, cash equivalent securities and real estate.
Net pension costs for the three years ended December 31, 1997
were computed as follows:
- 12 -
<TABLE>
<CAPTION>
Nov. 8 - | Jan. 1 -
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- ----------------------------------------------------|-----------------------------------
| (In millions)
<S> <C> | <C> <C> <C>
Service cost-benefits earned |
during the period $ 2.3 | $ 11.1 $ 12.6 $ 9.8
Interest on projected benefit |
obligation 6.1 | 25.4 27.9 25.8
Return on plan assets (7.7) | (38.0) (49.7) (52.8)
Net deferral (amortization) - | (2.4) 1.8 9.2
Voluntary early retirement |
program expense 23.0 | 4.8 - -
- ----------------------------------------------------|----------------------------------
Net pension cost $ 23.7 | $ 0.9 $ (7.4) $ (8.0)
====================================================|==================================
Company's share, including pro |
rata share of the Service |
Company's costs $ 16.5 | $ (2.5) $ (5.0) $ (5.2)
- ---------------------------------------------------------------------------------------
</TABLE>
- 13 -
A September 30 measurement date was used for 1996
reporting. The assumed discount rates used in determining the
actuarial present value of the projected benefit obligation were
7.25% in 1997, 7.75% in 1996 and 8.0% in 1995. The assumed rate
of increase in future compensation levels used to measure this
obligation was 4.0% in 1997. The rate of annual compensation
increase assumption in 1996 was 3.5% for 1997 and 4.0%
thereafter. The rate of annual compensation increase assumption
in 1995 was 3.5% for 1996 and 1997 and 4.0% thereafter. Expected
long-term rates of return on plan assets were assumed to be 10%
in 1997 and 11% in 1996 and 1995. At December 31, 1997, the
Company's net pension liability included in Pensions and Other
Postretirement Benefits on the Consolidated Balance Sheet was
$49.2 million. At December 31, 1996, the Company's net prepaid
pension cost included in Deferred Charges -- Other on the
Consolidated Balance Sheet was $15.4 million (see Note 2).
Centerior had sponsored jointly with its former
subsidiaries a postretirement benefit plan which provided all
employee groups certain health care, death and other
postretirement benefits other than pensions. The plan was
contributory, with retiree contributions adjusted annually. The
plan was not funded.
The accumulated postretirement benefit obligation and
accrued postretirement benefit cost for the Centerior
postretirement benefit plan are as follows:
At December 31, 1997 1996
- --------------------------------------------------------------
(In millions)
|
Accumulated postretirement benefit |
obligation allocation: |
Retirees $209.8 | $ 177.1
Fully eligible active plan participants 9.8 | 3.9
Other active plan participants 46.9 | 30.9
- ----------------------------------------------------|---------
Accumulated postretirement benefit |
obligation 266.5 | 211.9
Unrecognized transition obligation - | (120.1)
Unrecognized net gain - | 44.4
- ----------------------------------------------------|---------
Net postretirement benefit liability $266.5 | $ 136.2
Net periodic postretirement benefit costs for the three
years ended December 31, 1997 were computed as follows:
- 14 -
<TABLE>
<CAPTION>
Nov. 8 - | Jan. 1 -
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- ---------------------------------------------------------|-----------------------------------
| (In millions)
<S> <C> | <C> <C>
Service cost-benefits |
attributed to the period $0.5 | $ 1.8 $ 2.1 $ 1.7
Interest cost on accumulated |
benefit obligation 2.8 | 13.5 17.8 17.9
Amortization of transition obligation - | 6.4 7.5 7.5
Amortization of gain - | (0.9) - (0.6)
- ---------------------------------------------------------|----------------------------------
Net periodic postretirement |
benefit cost $3.3 | $20.8 $27.4 $26.5
=========================================================|==================================
Company's share, including pro rata |
share of the Service Company's costs $2.6 | $11.4 $18.4 $16.0
- ---------------------------------------------------------------------------------------------
</TABLE>
- 15 -
The Consolidated Balance Sheet classification of
Pensions and Other Postretirement Benefits at December 31, 1997
and 1996 includes the Company's share of the accrued
postretirement benefit liability of $149.5 million and $72.8
million, respectively (see Note 2).
The health care trend rate assumption is approximately
6.0% in the first year gradually decreasing to approximately 4.0%
for the year 2008 and later. The discount rates used to compute
the accumulated postretirement benefit obligation were 7.25% in
1997, 7.75% in 1996 and 8.0% in 1995. An increase in the health
care trend rate assumption by one percentage point in all years
would increase the accumulated postretirement benefit obligation
by approximately $7.7 million and the aggregate annual service
and interest costs by approximately $0.5 million. A September 30
measurement date was used for 1996 reporting.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and interest
charges include amounts for transactions with affiliated
companies in the ordinary course of business operations.
The Company's transactions with TE and the other
FirstEnergy operating subsidiaries (OE and Penn) from the
November 8, 1997 merger date are primarily for firm power,
interchange power, transmission line rentals and jointly owned
power plant operations and construction. (See Note 2.) Beginning
in May 1996, Centerior Funding began serving as the transferor in
connection with the accounts receivable securitization for the
Company and TE.
The Service Company (formerly a wholly owned subsidiary
of Centerior and now a wholly owned subsidiary of FirstEnergy)
provides support services at cost to the Company and other
affiliated companies. The Service Company billed the Company
$34.1 million, $130.8 million, $148.6 million and $141.1 million
in the November 8-December 31, 1997, the January 1-November 7,
1997 period, 1996 and 1995, respectively, for such services.
Fuel and purchased power expenses on the Consolidated
Statements of Income include the cost of power purchased from TE
of $17.7 million, $98.5 million, $105.0 million and $102.1
million in the November 8-December 31, 1997 period, the January
1-November 7, 1997 period, 1996 and 1995, respectively.
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an
initial maturity of three months or less are reported as cash
equivalents on the Consolidated Balance Sheets. The Company
reflects temporary cash investments at cost, which approximates
their market value. Noncash financing and investing activities
included capital lease transactions amounting to $16 million, $37
million and $19 million for the years 1997, 1996 and 1995,
respectively.
All borrowings with initial maturities of less than one
year are defined as financial instruments under generally
accepted accounting principles and are reported on the
Consolidated Balance Sheets at cost, which approximates their
fair market value. The following sets forth the approximate fair
value and related carrying amounts of all other long-term debt,
- 16 -
preferred stock subject to mandatory redemption and investments
other than cash and cash equivalents as of December 31:
1997 1996
-------------- ---------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------
(In Millions)
Long-term debt $3,198 $3,238|$2,562 $2,630
Preferred stock $ 198 $ 198|$ 216 $ 220
Investments other than cash |
and cash equivalents: |
Debt securities |
- (Maturing in more than |
10 years) $ 565 $ 553|$ - $ -
Equity securities 10 10| - -
All other 105 104| 75 75
- ----------------------------------------------|--------------
$ 680 $ 667|$ 75 $ 75
=============================================================
The carrying values of long-term debt and preferred
stock subject to mandatory redemption were adjusted to fair value
in connection with the merger and reflect the present value of
the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call,
as deemed appropriate at the end of each respective year. The
yields assumed were based on securities with similar
characteristics offered by a corporation with credit ratings
similar to the Company's ratings.
The fair value of investments other than cash and cash
equivalents represent cost (which approximates fair value) or the
present value of the cash inflows based on the yield to maturity.
The yields assumed were based on financial instruments with
similar characteristics and terms. Investments other than cash
and cash equivalents include decommissioning trusts investments.
Unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investments with a
corresponding change to the decommissioning liability. In 1996,
the Company and TE transferred most of their investment assets in
existing trusts into Centerior pooled trust funds for the two
companies. The amounts in the table represent the Company's pro
rata share of the fair value of such noncash investments. The
debt and equity securities referred to above are in the held-to-
maturity category. The Company has no securities held for trading
purposes.
REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs
which the FERC and PUCO have authorized for recovery from
customers in future periods. Without such authorization, the
costs would have been charged to income as incurred. All
regulatory assets related to nonnuclear operations are being
recovered from customers under the Company's regulatory plan.
Based on the regulatory plan, at this time, the Company believes
it will continue to be able to bill and collect cost-based rates
(with the exception of the Company's nuclear operations as
discussed below); accordingly, it is appropriate that the Company
continue the application of SFAS No. 71, "Accounting for the
- 17 -
Effects of Certain Types of Regulation" (SFAS 71), in the
foreseeable future for its nonnuclear operations.
The Company discontinued the application of SFAS 71 for
its nuclear operations in October 1997 when implementation of the
regulatory plan became probable. The regulatory plan does not
provide for full recovery of the Company's nuclear operations. In
accordance with SFAS No. 101, "Regulated Enterprises --
Accounting for the Discontinuation of Application of SFAS 71,"
the Company was required to remove from its balance sheet all
regulatory assets and liabilities related to the portion of its
business for which SFAS 71 was discontinued and to assess all
other assets for impairment. Regulatory assets attributable to
nuclear operations of $499.1 million ($324.4 million after taxes)
were written off as an extraordinary item in October 1997. The
regulatory assets attributable to nuclear operations written off
represent the net amounts due from customers for future federal
income taxes when the taxes become payable, which, under the
regulatory plan, are no longer recoverable from customers. The
remainder of the Company's business continues to comply with the
provisions of SFAS 71. All remaining regulatory assets of the
Company will continue to be recovered through rates set for the
nonnuclear portion of its business. For financial reporting
purposes, the net book value of the nuclear generating units was
not impaired as a result of the regulatory plan.
Net regulatory assets on the Consolidated Balance Sheets
are comprised of the following:
At December 31, 1997 1996
- --------------------------------------------------------------
(In millions)
Nuclear unit expenses $ 309.0 $ 320.0
Customer receivables for future
income taxes 143.0 633.6
Rate stabilization program deferrals 288.1 300.3
Gain from Bruce Mansfield Plant sale* (274.4) -
Loss on reacquired debt 80.9 57.8
Other 33.1 38.0
- --------------------------------------------------------------
Total $ 579.7 $1,349.7
===============================================================
* The Gain from the Bruce Mansfield Plant sale was reclassified as
a regulatory liability in connection with the purchase accounting
adjustments, consistent with the ratemaking treatment.
2. OHIO EDISON-CENTERIOR MERGER:
FirstEnergy was formed on November 8, 1997 by the
merger of OE and Centerior. FirstEnergy holds directly all of the
issued and outstanding common shares of OE and all of the issued
and outstanding common shares of Centerior's former direct
subsidiaries, which include, among others, the Company and TE. As
a result of the merger, the former common shareholders of OE and
Centerior now own all of the outstanding shares of FirstEnergy
Common Stock. All other classes of capital stock of OE and its
subsidiaries and of the subsidiaries of Centerior are unaffected
by the Merger and remain outstanding.
The merger was accounted for as a purchase of
Centerior's net assets with 77,637,704 shares of FirstEnergy
Common Stock through the conversion of each outstanding Centerior
Common Stock share into 0.525 of a share of FirstEnergy Common
Stock (fractional shares were paid in cash). Based on an imputed
value of $20.125 per share, the purchase price was approximately
- 18 -
$1.582 billion which also included approximately $20 million of
merger related costs. Goodwill of approximately $2.1 billion was
recognized by FirstEnergy (to be amortized on a straight-line
basis over forty years), which represented the excess of the
purchase price over Centerior's net assets after fair value
adjustments. Such amount may be adjusted if additional
information produces changed assumptions over the twelve months
following the merger as FirstEnergy continues to integrate
operations and evaluate options with respect to its generation
portfolio.
The Company's merger purchase accounting adjustments,
which were recorded in the records of Centerior's direct
subsidiaries, primarily consist of (1) revaluation of the
Company's nuclear generating units to fair value ($1.0 billion),
based upon the results of an independent appraisal and estimated
discounted future cash flows expected to be generated by its
nuclear generating units (the estimated cash flows are based upon
management's current view of the likely cost recovery associated
with the nuclear units); (2) adjusting by $119 million its
preferred stock subject to mandatory redemption and long-term
debt to estimated fair value; (3) recognizing additional
obligations related to retirement benefits (pension liability -
$50 million and postretirement obligation - $71 million); (4)
recognizing the Company's estimated severance and other
compensation liabilities ($56 million); and (5) adjusting the
Company's common equity by $272 million. The nuclear assets
revaluation does not include decommissioning since that
obligation is expected to be recovered with the cash flows
provided by the regulated portion of the business. Other assets
and liabilities were not adjusted since they remain subject to
rate regulation on a historical cost basis. See Note 8.
3. LEASES:
The Company leases certain generating facilities,
nuclear fuel, certain transmission facilities, office space and
other property and equipment under cancelable and noncancelable
leases.
The Company and TE sold their ownership interests in
Bruce Mansfield Units 1, 2 and 3 and TE sold a portion of its
ownership interest in Beaver Valley Unit 2. In connection with
these sales, which were completed in 1987, the Company and TE
entered into operating leases for lease terms of approximately 30
years as co-lessees. During the terms of the leases, the Company
and TE continue to be responsible, to the extent of their
combined ownership and leasehold interest, for costs associated
with the units including construction expenditures, operation and
maintenance expenses, insurance, nuclear fuel, property taxes and
decommissioning. The Company and TE have the right, at the end of
the respective basic lease terms, to renew the leases. The
Company and TE also have the right to purchase the facilities at
the expiration of the basic lease term or renewal term (if
elected) at a price equal to the fair market value of the
facilities.
As co-lessee with TE, the Company is also obligated for
TE's lease payments. If TE is unable to make its payments under
the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the
Company would be obligated to make such payments. No such
payments have been made on behalf of TE. (TE's minimum lease
payments as of December 31, 1997 were $1.7 billion).
- 19 -
The Company is buying 150 megawatts of TE's Beaver
Valley Unit 2 leased capacity entitlement. Purchased power
expense for this transaction was $16.8 million, $87.4 million,
$99.4 million and $97.6 million in the November 8-December 31,
1997, the January 1-November 7, 1997 period, 1996 and 1995,
respectively. This purchase is expected to continue through the
end of the lease period. The future minimum lease payments
through 2017 associated with Beaver Valley Unit 2 are
approximately $1.2 billion.
Nuclear fuel is currently financed for the Company and
TE through leases with a special-purpose corporation. As of
December 31, 1997, $157 million of nuclear fuel ($93 million for
the Company) was financed under a lease financing arrangement
totaling $190 million ($90 million of intermediate-term notes and
$100 million from bank credit arrangements). The notes mature
from 1998 through 2000 and the bank credit arrangements expire in
October 1998. Lease rates are based on intermediate-term note
rates, bank rates and commercial paper rates.
Consistent with the regulatory treatment, the rentals
for capital and operating leases are charged to operating
expenses on the Consolidated Statements of Income. Such costs for
the three years ended December 31, 1997 are summarized as
follows:
- 20 -
<TABLE>
<CAPTION>
Nov. 8 - | Jan. 1 -
Dec. 31, 1997 | Nov. 7, 1997 1996 1995
- ----------------------------------------------------|------------------------------------
| (In millions)
<S> <C> | <C> <C> <C>
Operating leases |
Interest element $10.6 | $ 56.0 $ 58.1 $ 58.1
Other 8.4 | 18.3 4.8 4.8
Capital leases |
Interest element 1.5 | 8.5 10.1 10.7
Other 7.5 | 43.4 51.7 58.4
- ----------------------------------------------------|------------------------------------
Total rentals $28.0 | $126.2 $124.7 $132.0
=========================================================================================
The future minimum lease payments as of December 31, 1997 are:
Capital
Capital Operating Trust
Leases Leases Income Net
- --------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C>
1998 $ 47.0 $ 65.3 $ 40.1 $ 25.2
1999 33.4 69.3 38.2 31.1
2000 18.9 66.6 36.3 30.3
2001 8.5 71.7 35.0 36.7
2002 4.1 76.4 32.9 43.5
Years thereafter 10.8 853.7 227.7 626.0
- ---------------------------------------------------------------------------------
Total minimum lease payments 122.7 $1,203.0 $410.2 $792.8
======== ====== ======
Interest portion 24.2
- ----------------------------------------------
Present value of net minimum
lease payments 98.5
Less current portion 40.4
- ----------------------------------------------
Noncurrent portion $ 58.1
</TABLE>
- 21 -
The Company and TE refinanced high-cost fixed
obligations related to their 1987 sale and leaseback transaction
for the Bruce Mansfield Plant through a lower cost transaction in
June and July 1997. In a June 1997 offering (Offering), the two
companies pledged $720 million aggregate principal amount ($575
million for the Company and $145 million for TE) of first
mortgage bonds due in 2000, 2004 and 2007 to a trust as security
for the issuance of a like principal amount of secured notes due
in 2000, 2004 and 2007. The obligations of the two companies
under these secured notes are joint and several. Using available
cash, short-term borrowings and the net proceeds from the
Offering, the two companies invested $906.5 million ($569.4
million for the Company and $337.1 million for TE) in a business
trust, in June 1997. The trust used these funds in July 1997 to
purchase lease notes and redeem all $873.2 million aggregate
principal amount of 10-1/4% and 11-1/8% secured lease obligation
bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a
special-purpose funding corporation in 1988 on behalf of lessors
in the two companies' 1987 sale and leaseback transaction. As
noted in the table above, the trust income, which is included in
Other Income in the Consolidated Statements of Income,
effectively reduce lease costs related to that transaction.
4. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for
payment of cash dividends on the Company's common stock. The
merger purchase accounting adjustments included resetting the
retained earnings balance at zero at the November 8, 1997 merger
date.
(B) PREFERRED AND PREFERENCE STOCK-
The Company's $42.40 Series T and $88.00 Series R
preferred stock are not redeemable before June 1998 and December
2001, respectively, and its $90.00 Series S has no optional
redemption provision. All other preferred stock may be redeemed
by the Company in whole, or in part, with 30-90 days' notice.
The preferred dividend rate on the Company's Series L
fluctuates based on prevailing interest rates and market
conditions. The dividend rate for this issue was 7% in 1997.
Preference stock authorized for the Company is
3,000,000 shares without par value. No preference shares are
currently outstanding.
(C) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for preferred stock are
as follows:
- 22 -
Redemption
Price Per
Series Shares Share Date Beginning
- -----------------------------------------------
$ 7.35 C 10,000 $ 100 (i)
88.00 E 3,000 1,000 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 November 1 1999
88.00 R 50,000 1,000 December 1 2001
- -----------------------------------------------
i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five
years are $14.7 million in 1998, $33.5 million in each year 1999
and 2000, $80.5 million in 2001 and $18.8 million in 2002. A
liability of $14 million was included in the Company's net assets
as of the merger date for preferred dividends declared
attributable to the post-merger period. Accordingly, no accrual
for preferred stock dividend requirements is included on the
Company's November 8, 1997 to December 31, 1997 Consolidated
Statement of Income.
(D) LONG-TERM DEBT-
The first mortgage indenture and its supplements, which
secure all of the Company's first mortgage bonds, serve as direct
first mortgage liens on substantially all property and
franchises, other than specifically excepted property, owned by
the Company.
Sinking fund requirements for first mortgage bonds and
maturing long-term debt (excluding capital leases) for the next
five years are:
(In millions)
- --------------------------------------------------------------
1998 $ 66.8
1999 145.5
2000 176.0
2001 57.5
2002 229.3
- --------------------------------------------------------------
The Company's obligations to repay certain pollution
control revenue bonds are secured by several series of first
mortgage bonds. One pollution control revenue bond issue is
entitled to the benefit of an irrevocable bank letter of credit
of $48.1 million. To the extent that drawings are made under this
letter of credit to pay principal of, or interest on, the
pollution control revenue bonds, the Company is entitled to a
credit against its obligation to repay those bonds. The Company
pays an annual fee of 1.1% of the amount of the letter of credit
to the issuing bank and is obligated to reimburse the bank for
any drawings thereunder.
The Company and TE have letters of credit of
approximately $225 million in connection with the sale and
leaseback of Beaver Valley Unit 2 that expire in June 1999. The
letters of credit are secured by first mortgage bonds of the
Company and TE in the proportion of 40% and 60%, respectively
(see Note 3).
- 23 -
5. SHORT-TERM BORROWINGS:
FirstEnergy has a $125 million revolving credit
facility that expires in May 1998. FirstEnergy and the Service
Company may borrow under the facility, with all borrowings
jointly and severally guaranteed by the Company and TE.
FirstEnergy plans to transfer any of its borrowed funds to the
Company and TE. The credit agreement is secured with first
mortgage bonds of the Company and TE in the proportion of 40% and
60%, respectively. The credit agreement also provides the
participating banks with a subordinate mortgage security interest
on the properties of the Company and TE. The banks' fee is 0.625%
per annum payable quarterly in addition to interest on any
borrowings. There were no borrowings under the facility at
December 31, 1997. Also, the Company may borrow from its
affiliates on a short-term basis. At December 31, 1997, the
Company had total short-term borrowings of $56.8 million from its
affiliates with a weighted average interest rate of approximately
6%.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $430 million for property additions and
improvements from 1998-2002, of which approximately $105 million
is applicable to 1998. Investments for additional nuclear fuel
during the 1998-2002 period are estimated to be approximately
$172 million, of which approximately $32 million applies to 1998.
During the same periods, the Company's nuclear fuel investments
are expected to be reduced by approximately $113 million and $42
million, respectively, as the nuclear fuel is consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability
relative to a single incident at a nuclear power plant to $8.92
billion. The amount is covered by a combination of private
insurance and an industry retrospective rating plan. Based on its
present ownership and leasehold interests in Beaver Valley Unit
2, the Davis-Besse Nuclear Power Station (Davis-Besse) and the
Perry Nuclear Power Plant (Perry), the Company's maximum
potential assessment under the industry retrospective rating plan
(assuming the other CAPCO companies were to contribute their
proportionate share of any assessments under the retrospective
rating plan) would be $84 million per incident but not more than
$10.7 million in any one year for each incident.
The Company is also insured as to its respective
interests in Beaver Valley Unit 2, Davis-Besse and Perry under
policies issued to the operating company for each plant. Under
these policies, up to $2.75 billion is provided for property
damage and decontamination and decommissioning costs. The Company
has also obtained approximately $316 million of insurance
coverage for replacement power costs for its respective interests
in Beaver Valley Unit 2, Davis-Besse and Perry. Under these
policies, the Company can be assessed a maximum of approximately
$13 million for incidents at any covered nuclear facility
occurring during a policy year which are in excess of accumulated
funds available to the insurer for paying losses.
- 24 -
The Company intends to maintain insurance against
nuclear risks as described above as long as it is available. To
the extent that replacement power, property damage,
decontamination, decommissioning, repair and replacement costs
and other such costs arising from a nuclear incident at any of
the Company's plants exceed the policy limits of the insurance in
effect with respect to that plant, to the extent a nuclear
incident is determined not to be covered by the Company's
insurance policies, or to the extent such insurance becomes
unavailable in the future, the Company would remain at risk for
such costs.
GUARANTEE-
The Company, together with the other CAPCO companies,
has severally guaranteed certain debt and lease obligations in
connection with a coal supply contract for the Bruce Mansfield
Plant. As of December 31, 1997, the Company's share of the
guarantee (which approximates fair market value) was $14.3
million. The price under the coal supply contract, which includes
certain minimum payments, has been determined to be sufficient to
satisfy the debt and lease obligations. The Company's total
payments under the coal supply contract were $51.2 million, $47.0
million and $38.6 million during 1997, 1996 and 1995,
respectively. The Company's minimum annual payments are
approximately $14 million under the contract, which expires
December 31, 1999.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate
the Company with regard to air and water quality and other
environmental matters. The Company has estimated additional
capital expenditures for environmental compliance of
approximately $12 million, which is included in the construction
forecast provided under "Capital Expenditures" for 1998 through
2002.
The Company is in compliance with the current sulfur
dioxide (SO2) and nitrogen oxides (NOX) reduction requirements
under the Clean Air Act Amendments of 1990. SO2 reductions
through the year 1999 will be achieved by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants,
and/or purchasing emission allowances. Plans for complying with
reductions required for the year 2000 and thereafter have not
been finalized. The Environmental Protection Agency (EPA) is
conducting additional studies which could indicate the need for
additional NOX reductions from the Bruce Mansfield Plant by the
year 2003. In addition, the EPA is also considering the need for
additional NOX reductions from the Company's Ohio facilities. On
November 7, 1997, the EPA proposed uniform reductions of NOX
emissions across a region of twenty-two states, including Ohio
and the District of Columbia (NOX Transport Rule) after
determining that such NOX emissions are contributing
significantly to ozone pollution in the eastern United States. In
a separate but related action, eight states filed petitions with
the EPA under Section 126 of the Clean Air Act seeking reductions
of NOX emissions which are alleged to contribute to ozone
pollution in the eight petitioning states. A December 1997 EPA
Memorandum of Agreement proposes to finalize the NOX Transport
Rule by September 30, 1998 and establishes a schedule for EPA
- 25 -
action on the Section 126 petitions. The cost of NOX reductions,
if required, may be substantial. The Company continues to
evaluate its compliance plans and other compliance options.
The Company is required to meet federally approved SO2
regulations. Violations of such regulations can result in
shutdown of the generating unit involved and/or civil or criminal
penalties of up to $25,000 for each day the unit is in violation.
The EPA has an interim enforcement policy for SO2 regulations in
Ohio that allows for compliance based on a 30-day averaging
period. The Company cannot predict what action the EPA may take
in the future with respect to proposed regulations or the interim
enforcement policy.
The Company is aware of its potential involvement in
the cleanup of three hazardous waste disposal sites listed on the
Superfund National Priorities List and several other sites. The
Company has accrued a liability totaling $4.8 million at December
31, 1997 based on estimates of the costs of cleanup and its
proportionate responsibility for such costs. The Company believes
that the ultimate outcome of these matters will not have a
material adverse effect on the its financial condition, cash
flows or results of operations.
Legislative, administrative and judicial actions will
continue to change the way that the Company must operate in order
to comply with environmental laws and regulations. With respect
to any such changes and to the environmental matters described
above, the Company expects that any resulting additional capital
costs which may be required, as well as any required increase in
operating costs, would ultimately be recovered from its
customers.
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating
results by quarter for 1997 and 1996.
- 26 -
<TABLE>
<CAPTION>
Three Months Ended
--------------------------------
Mar. 31, June 30, Sept. 30, Oct. 1 - | Nov. 8 -
1997 1997 1997 Nov. 7, 1997 | Dec. 31, 1997
- ------------------------------------------------------------------------------------------|---------------
(In millions) |
<S> <C> <C> <C> <C> | <C>
Operating Revenues $431.6 $428.2 $499.5 $169.7 | $254.0
Operating Expenses and Taxes 351.6 350.8 368.0 151.3 | 204.5
- ------------------------------------------------------------------------------------------|------------
Operating Income 80.0 77.4 131.5 18.4 | 49.5
Other Income (Loss) (3.7) (5.2) 7.5 (1.2) | 4.6
Net Interest Charges 56.1 58.2 71.3 24.0 | 34.8
- ------------------------------------------------------------------------------------------|------------
Income (Loss) Before Extraordinary Item 20.2 14.0 67.7 (6.8) | 19.3
Extraordinary Item (Net of Income Taxes) |
(Note 1) - - - (324.4) | -
- ------------------------------------------------------------------------------------------|------------
Net Income (Loss) $ 20.2 $ 14.0 $ 67.7 $(331.2) | $ 19.3
- ------------------------------------------------------------------------------------------|------------
Earnings (Loss) on Common Stock $ 10.9 $ 4.9 $ 58.9 $(348.9) | $ 19.3
- ------------------------------------------------------------------------------------------|------------
<CAPTION>
March 31, June 30, September 30, December 31,
Three Months Ended 1996 1996 1996 1996
- ---------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C>
Operating Revenues $427.5 $434.0 $506.5 $421.9
Operating Expenses and Taxes 351.7 348.1 385.8 345.7
- ------------------------------------------------------------------------------------
Operating Income 75.8 85.9 120.7 76.2
Other Income (Loss) 1.3 .7 (2.7) (1.4)
Net Interest Charges 60.3 61.4 59.3 59.0
- ------------------------------------------------------------------------------------
Net Income $ 16.8 $ 25.2 $ 58.7 $ 15.8
- ------------------------------------------------------------------------------------
Earnings on Common Stock $ 6.8 $ 15.3 $ 49.2 $ 6.5
- ------------------------------------------------------------------------------------
</TABLE
- 27 -
Earnings for the quarter ended September 30, 1996 were
decreased by $10.8 million as a result of a $16.6 million charge
for the disposition of materials and supplies inventory as part
of the reengineering of the supply chain process.
8. PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME UNAUDITED):
The following pro forma statements of income for the
Company give effect to the OE-Centerior merger as if it had been
consummated on January 1, 1996, with the purchase accounting
adjustments actually recognized in the business combination.
Year Ended December 31,
----------------------
1997 1996
- ----------------------------------------------------------------
(In millions)
Operating Revenues $1,783 $1,790
Operating Expenses and Taxes 1,418 1,424
------ ------
Operating Income 365 366
Other Income 15 2
Net Interest Charges 232 227
------ ------
Net Income $ 148 $ 141
=============================================================
Pro forma adjustments reflected above include: (1) adjusting the
Company's nuclear generating units to fair value based upon
independent appraisals and estimated discounted future cash flows
based on management's current view of cost recovery; (2) the
effect of discontinuing SFAS 71 for the Company's nuclear
operations; (3) amortization of the fair value adjustment for
long-term debt; (4) goodwill recognized representing the excess
of the Company's portion of the purchase price over the Company's
adjusted net assets; (4) the elimination of merger costs; and (5)
adjustments for estimated tax effects of the above adjustments.
See Note 2.
9. PENDING MERGER OF TE INTO THE COMPANY:
In March 1994, Centerior announced a plan to merge TE
into the Company. All necessary regulatory approvals have been
obtained, except the approval of the Nuclear Regulatory Commission
(NRC). This application was withdrawn at the NRC's request pending
the decision whether to complete this merger. No final decision
regarding the proposed merger has been reached.
In June 1995, TE's preferred stockholders approved the
merger and the Company's preferred stockholders approved the
authorization of additional shares of preferred stock. If and
when the merger becomes effective, TE's preferred stockholders
will exchange their shares for preferred stock shares of the
Company having substantially the same terms. Debt holders of the
merging companies will become debt holders of the Company.
- 28 -
For the merging companies, the combined pro forma
operating revenues were $2.527 billion, $2.554 billion and $2.516
billion and the combined pro forma net income was $220 million
(excluding the extraordinary item discussed in Note 1 and a
similar item for TE), $218 million and $281 million for the years
1997, 1996 and 1995, respectively. The pro forma data is based on
accounting for the merger of the Company and TE on a method
similar to a pooling of interests and for 1997 and 1996 includes
pro forma adjustments to reflect the effect of the OE and
Centerior merger (see Note 8). The pro forma data is not
necessarily indicative of the results of operations which would
have been reported had the merger been in effect during those
years or which may be reported in the future. The pro forma data
should be read in conjunction with the audited financial
statements of both the Company and TE.
- 29 -
Report of Independent Public Accountants
To the Stockholders and Board of Directors of The Cleveland
Electric Illuminating Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of The Cleveland
Electric Illuminating Company (an Ohio corporation and wholly
owned subsidiary of FirstEnergy Corp.) and subsidiary as of
December 31, 1997 (post-merger) and 1996 (pre-merger), and the
related consolidated statements of income, retained earnings,
capital stock and other paid-in capital, cash flows and taxes for
the years ended December 31, 1996 and 1995 and the period from
January 1, 1997 to November 7, 1997 (pre-merger), and the period
from November 8, 1997 to December 31, 1997 (post-merger). 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 in accordance with generally accepted
auditing standards. Those standards 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. An audit
also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of The Cleveland Electric Illuminating Company and subsidiary as
of December 31, 1997 (post-merger) and 1996 (pre-merger), and the
results of their operations and their cash flows for the years
ended December 31, 1996 and 1995 and the period from January 1,
1997 to November 7, 1997 (pre-merger), and the period from
November 8, 1997 to December 31, 1997 (post-merger), in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 13, 1998
- 30 -
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward looking statements based
on information currently available to management. Such statements
are subject to certain risks and uncertainties. These statements
typically contain, but are not limited to, the terms "anticipate",
"potential", "expect", "believe", "estimate" and similar words.
Actual results may differ materially due to the speed and nature of
increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and
margins, changes in markets for energy services, changing energy
market prices, legislative and regulatory changes (including
revised environmental requirements), availability and cost of
capital and other similar factors.
RESULTS OF OPERATIONS
We continued to make significant progress in 1997 as we
prepare for a more competitive environment in the electric utility
industry.
The most significant event during the year was the
approval by the Federal Energy Regulatory Commission (FERC) of the
merger of our former parent company, Centerior Energy Corporation,
with Ohio Edison Company to form FirstEnergy Corp., which came into
existence on November 8, 1997. We expect the merger to produce a
minimum of $1 billion in savings for FirstEnergy Corp. during the
first ten years of joint operations through the elimination of
duplicative activities, improved operating efficiencies, lower
capital expenditures, accelerated debt reduction, the coordination
of the companies' work forces and enhanced purchasing power.
The merger was accounted for using the purchase method of
accounting in accordance with generally accepted accounting
principles (see Note 2), and the applicable effects were "pushed
down," or reflected on the separate financial statements of
Centerior's direct subsidiaries as of the merger date. As a result,
we recorded purchase accounting fair value adjustments to: (1)
revalue our nuclear generating units to fair value, (2) adjust
preferred stock and long-term debt to fair value, (3) recognize
additional retirement and severance benefit liabilities, and (4)
record goodwill. Accordingly, the post-merger financial statements
reflect a new basis of accounting, and separate financial
statements are presented for the pre-merger and post-merger
periods. For the remainder of this discussion, for categories
substantially unaffected by the merger and with no significant pre-
merger or post-merger accounting events, we have combined the 1997
pre-merger and post-merger periods and have compared the total to
1996.
Earnings on common stock in the 1997 pre-merger period were
adversely affected by an extraordinary item resulting from the
October 1997 write-off of certain regulatory assets discussed
below. Excluding this write-off, pre-merger 1997 earnings on common
stock were $50.2 million. Earnings on common stock for the 1997
post-merger period were $19.3 million. In 1996, earnings on common
- 31 -
stock were $77.8 million which was lower than 1995 due primarily to
the delay in implementing our 1996 rate increase and the end of
certain regulatory accounting deferrals in November 1995.
Operating revenues were down $7.0 million in 1997 from
1996 levels following a $21.2 million increase in 1996 compared to
1995. A significant factor contributing to lower operating revenues
was the cancellation of a generating plant lease agreement for
which revenues were recorded in 1996; a related refund was
recognized in the 1997 first quarter which reduced other operating
revenue. The following table summarizes the sources of changes in
operating revenues for 1997 and 1996 as compared to the previous
year:
1997 1996
---- ----
(In millions)
Reduced retail kilowatt-hour sales $ (9.8) $(40.7)
Change in average retail price (4.8) 42.2
Sales to utilities 18.6 14.6
Other (11.0) 5.1
------ ------
Net Change $ (7.0) $ 21.2
====== ======
Total kilowatt-hour sales were at a new high for the
second consecutive year with 22.3 billion kilowatt-hours sold.
Sales to other utilities increased 38.4% in 1997. This followed a
27.2% increase from the previous year resulting from greater
availability of our generating units and an aggressive bulk power
marketing effort. Retail sales totaled 19.3 billion kilowatt-hours
in 1997, a decline of 0.4% from the prior year level. Residential
sales decreased 2.2% in 1997 following a 2.1% decline the previous
year. Commercial sales were down 0.4% and 0.6% in 1997 and 1996,
respectively. Industrial sales increased slightly in 1997,
following a small decline the previous year. Overall, there was a
3.5% increase in total kilowatt-hour sales following a 1.3%
increase in 1996 based on the strength of wholesale sales.
- 32 -
We spent more on fuel and purchased power during 1997, as
higher purchased power expense was partially offset by lower fuel
expense. An increase in the mix of nuclear generation to coal-fired
generation contributed to the lower fuel costs. Lower nuclear
expenses in 1997 resulted from lower operating costs at the Perry
and Davis-Besse plants offset in part by increased operating costs
at the Beaver Valley Plant. The decrease in other operating costs
in 1997 resulted from ongoing cost cutting and the effect of work
force reductions. Also, other operation and maintenance expenses in
1996 included an $11.9 million charge for the disposal of obsolete
materials and supplies. The 1997 decrease in other operating costs
was offset in part by a fourth quarter, pre-merger charge for
estimated severance expenses totaling $9.9 million.
Depreciation and amortization increased in the 1997 pre-
merger period and in 1996 principally due to changes in
depreciation rates approved in the April 1996 Public Utilities
Commission of Ohio (PUCO) rate order. In the post-merger period
depreciation and amortization was lower due to a fair value adjustment
which was recorded in connection with accounting for the merger.
Amortization of regulatory assets remained nearly unchanged in 1997
after a large increase in 1996 following cessation of the Rate
Stabilization Program deferrals and initiation of their amortization.
Income taxes increased in 1997, compared to 1996, as a function of taxable
income. Income taxes decreased in 1996 from the prior year due to
lower pretax operating income.
Other income decreased in the 1997 pre-merger period and
in 1996 principally due to merger-related expenses and costs
associated with the accounts receivable securitization. In the
post-merger period, other income increased primarily because of
interest income on trust notes acquired in connection with the
Bruce Mansfield Plant lease refinancing. Interest costs were higher
overall in 1997 because new secured notes and short-term borrowings
for the Bruce Mansfield Plant lease refinancing exceeded the
expense reduction from the redemption and refinancing of debt
securities in 1997 and 1996.
CAPITAL RESOURCES AND LIQUIDITY
Our financial position has improved over the past five
years. Cash generated from operations was 24% higher in 1997 than
it was in 1992 due to higher revenues and aggressive cost controls.
At the end of 1997 we had 1,300 fewer employees than five years ago
as a result of our focus on becoming more competitive. The
availability of additional cash generated from operations increased
the Company's ability to redeem higher cost debt and preferred
stock. We have also actively pursued refinancing activities which
replace higher cost debt and preferred stock with lower cost
issues. The merger has resulted in improved credit ratings which
has lowered the cost of new issues. The following table summarizes
changes in credit ratings resulting from the merger.
Pre-Merger Post-Merger
-------------------- ------------------
Standard Moody's Standard Moody's
& Poor's Investors & Poor's Investors
Corporation Service, Inc. Corporation Service, Inc.
----------- ------------- ----------- ------------
First mortgage
bonds BB Ba2 BB+ Ba1
Subordinated debt B+ Ba3 BB- Ba3
Preferred Stock B b2 BB- b1
Excluding the effect of the Bruce Mansfield Plant lease refinancing
described below, interest costs and preferred dividends have been
reduced by approximately $22 million from 1996 levels. Through
economic refinancings and redemption of higher cost debt we have
reduced the average cost of outstanding debt from 8.90% in 1992 to
8.15% in 1997. The Bruce Mansfield Plant lease refinancing is
expected to provide an annual after tax savings of about $13
million resulting from an increase in interest income and a
decrease in rent expense offset in part by increased interest
expense on secured notes issued as part of the transaction.
Our cash requirements in 1998 for operating expenses,
construction expenditures and scheduled debt maturities are
expected to be met without issuing additional securities. We have
cash requirements of approximately $856.1 million for the 1998-2002
- 33 -
period to meet scheduled maturities of long-term debt and preferred
stock. Of that amount, approximately $81.5 million applies to 1998.
We had about $33.8 million of cash and temporary
investments and $56.8 million of short-term indebtedness to an
associated company on December 31, 1997. Upon completion of the
merger, application of purchase accounting reduced bondable
property such that we are not able to issue a material amount of
additional first mortgage bonds, except in connection with
refinancings. As of December 31, 1997, we had unused borrowing
capability of $125 million under a revolving line of credit.
Our capital spending for the period 1998-2002 is expected
to be about $430 million (excluding nuclear fuel), of which
approximately $105 million applies to 1998. This spending level is
over $300 million lower than actual capital outlays over the past
five years. Investments for additional nuclear fuel during the
1998-2002 period are estimated to be approximately $172 million, of
which about $32 million applies to 1998. During the same periods,
our nuclear fuel investments are expected to be reduced by
approximately $113 million and $42 million, respectively, as the
nuclear fuel is consumed. Also, we have operating lease commitments
net of trust income of approximately $167 million for the 1998-2002
period, of which approximately $25 million relates to 1998. We
recover the cost of nuclear fuel consumed and operating leases
through our electric rates.
OUTLOOK
We face many competitive challenges in the years ahead as
the electric utility industry undergoes significant changes,
including changing regulation and the entrance of more energy
suppliers into the marketplace. Retail wheeling, which would allow
retail customers to purchase electricity from other energy
producers, will be one of those challenges. The FirstEnergy Rate
Reduction and Economic Development Plan provides the foundation to
position us to meet the challenges we are facing by significantly
reducing fixed costs and lowering rates to a more competitive
level. The plan was approved by the PUCO in January 1997, and
initially maintains current base electric rates through December
31, 2005. The plan also revised our fuel recovery methods.
As part of the regulatory plan, the base rate freeze is
to be followed by a $217 million base rate reduction in 2006;
interim reductions beginning in June 1998 of $3 per month will
increase to $5 per month per residential customer by July 1, 2001.
Total savings of $280 million are anticipated over the term of the
plan for our customers. We have also committed $70 million for
economic development and energy efficiency programs.
We have been authorized by the PUCO to recognize
additional depreciation related to our generating assets and
additional amortization of regulatory assets during the regulatory
plan period of at least $1.4 billion more than the amounts that
would have been recognized if the regulatory plan was not in
effect. For regulatory purposes these additional charges will be
reflected over the rate plan period. Our regulatory plan does not
provide for full recovery of nuclear operations. Accordingly,
regulatory assets representing customer receivables for future
income taxes related to nuclear assets of $499 million were written
off ($324 net of tax impact) prior to consummation of the merger
- 34 -
since we ceased application of Statement of Financial Accounting
Standards No. 71 "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71) for our nuclear operations when
implementation of the FirstEnergy regulatory plan became probable.
Based on the regulatory environment we operate in today
and our regulatory plan, we believe we will continue to be able to
bill and collect cost-based rates relating to our nonnuclear
operations; accordingly, it is appropriate that we continue the
application of SFAS 71 for those operations. However, as discussed
below, changes in the regulatory environment are on the horizon.
The Ohio legislature is in the discussion stages of restructuring
the electric utility industry within the State. We do not expect
any changes in regulation to be effective within the next two years
and we cannot assess what the ultimate impact may be.
At the consummation of the merger in November 1997, we
recognized a fair value purchase accounting adjustment which
decreased the carrying value of our nuclear assets by approximately
$1.7 billion based upon cash flow models. The fair value adjustment
to nuclear plant recognized for financial reporting purposes will
ultimately satisfy the asset reduction commitment contained in our
regulatory plan over the regulatory plan period.
On January 6, 1998, the co-chairs of the Ohio General
Assembly's Joint Select Committee on Electric Industry Deregulation
released their draft report of a plan which proposes to give
customers a choice from whom they buy electricity beginning January
1, 2000. No consensus has been reached by the full Committee; in
the meantime, legislation consistent with the co-chairs' draft
report may be introduced into the General Assembly by one or both
of the co-chairs. We cannot predict when or if this legislation
will be introduced and if it will be passed into law. We continue
to study the potential effects that such legislation would have on
our financial position and results of operations.
The Financial Accounting Standards Board (FASB) issued a
proposed accounting standard for nuclear decommissioning costs in
February 1996. If the standard is adopted as proposed: (1) annual
provisions for decommissioning could increase; (2) the net present
value of estimated decommissioning costs could be recorded as a
liability; and (3) income from the external decommissioning trusts
could be reported as investment income. The FASB reported in
October 1997 that it plans to continue working on the proposal in
1998.
The Clean Air Act Amendments of 1990, discussed in Note
6, require additional emission reductions by 2000. We are pursuing
cost-effective compliance strategies for meeting the reduction
requirements that begin in 2000.
We have been named as a "potentially responsible party"
(PRP) for three sites listed on the Superfund National Priorities
List and are aware of our potential involvement in the cleanup of
several other sites. Allegations that we disposed of hazardous
waste at these sites, and the amount involved are often
unsubstantiated and subject to dispute. Federal law provides that
all PRPs for a particular site be held liable on a joint and
several basis. If we were held liable for 100% of the cleanup costs
of all the sites referred to above, the cost could be as high as
- 35 -
$212 million. However, we believe that the actual cleanup costs
will be substantially lower than $212 million, that our share of
any cleanup costs will be substantially less than 100% and that
most of the other PRPs are financially able to contribute their
share. We have accrued a $4.8 million liability as of December 31,
1997, based on estimates of the costs of cleanup and our
proportionate responsibility for such cost. We believe that the
ultimate outcome of these matters will not have a material adverse
effect on our financial condition, cash flows or results of
operations.
Impact of the Year 2000 Issue
- -----------------------------
The Year 2000 Issue is the result of computer programs
being written using two digits rather than four to identify the
applicable year. Any of our programs that have date-sensitive
software may recognize a date using "00" as the year 1900 rather
than the year 2000. This could result in system failures or
miscalculations.
We currently believe that with modifications to existing
software and conversions to new software, the Year 2000 Issue will
pose no significant operational problems for our computer systems
as so modified and converted. If these modifications and
conversions are not made, or are not completed on a timely basis,
the Year 2000 Issue could have a material impact on our
operations.
We have initiated formal communications with many of our
major suppliers to determine the extent to which we are vulnerable
to those third parties' failure to resolve their own Year 2000
problems. Our total Year 2000 project cost and estimates to
complete are based on currently available information and do not
include the estimated costs and time associated with the impact of
a third party's Year 2000 issue. There can be no guarantee that the
failure of other companies to resolve their own Year 2000 issues
will not have material adverse effect on us.
We are utilizing both internal and external resources to
reprogram and/or replace and test the software for Year 2000
modifications. Most of our Year 2000 problems will be resolved
through system replacements. The different phases of our Year 2000
project will be completed at various dates, most of which occur in
1999. We plan to complete the entire Year 2000 project by mid-
December 1999. Of the total project cost, approximately $22 million
will be capitalized since those costs are attributable to the
purchase of new software for total system replacements (i.e., the
Year 2000 solution comprises only a portion of the benefit
resulting from the system replacements). The remaining $3 million
will be expensed as incurred over the next two years. To date, we
have incurred approximately $350,000 related to the assessment of,
and preliminary efforts in connection with, our Year 2000 project
and the development of a remediation plan.
The costs of the project and the date on which we plan to
complete the year 2000 modifications are based on management's best
estimates, which were derived from numerous assumptions of future
events including the continued availability of certain resources,
and other factors. However, there can be no guarantee that this
- 36 -
project will be completed as planned and actual results could
differ materially from the estimates. Specific factors that might
cause material differences include, but are not limited to, the
availability and cost of trained personnel, the ability to locate
and correct all relevant computer code, and similar uncertainties.
- 37 -
SIGNATURE
Pursuant to the requirements of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly authorized.
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
/s/Harvey L. Wagner
-----------------------
Harvey L. Wagner
Controller
Dated: March 16, 1998
- 38 -
</TABLE>
EXHIBIT 24
EXHIBIT 24
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report on the consolidated financial statements
of The Cleveland Electric Illuminating Company, dated February 13,
1998 and included in this Form 8-K, into the Company's previously
filed Registration Statement, File No. 33-55513.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
March 16, 1998
