EXHIBIT 99.3

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

FINANCIAL STATEMENTS

Independent Auditors' Report

FINANCIAL STATEMENT SCHEDULES

The information required to be submitted in schedules other than those indicated above has been included in the Balance Sheets, the Statements of Income, related schedules, the notes thereto, or omitted as not required by the Rules of Regulation S-X.

1

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc. and The Union Light, Heat & Power Company:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Cinergy Corp. and subsidiaries and the separate consolidated balance sheets and statements of capitalization of The Cincinnati Gas & Electric Company and subsidiaries and PSI Energy, Inc. and subsidiary and the separate balance sheets and statements of capitalization of The Union Light, Heat and Power Company as of December 31, 2002 and 2001 and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2002.  Our audits also included the financial statement schedules listed in the Table of Contents at Item 7. These financial statements and financial statement schedules are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America.  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, such financial statements present fairly, in all material respects, the consolidated financial position of Cinergy Corp. and subsidiaries and the financial position of The Cincinnati Gas & Electric Company and subsidiaries and PSI Energy, Inc. and subsidiary and the financial position of The Union Light, Heat & Power Company as of December 31, 2002 and 2001, and the respective results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedules, when considered in relation to the respective basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 14 to the financial statements, in 2002 Cinergy Corp. changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

As discussed in Note 20 to the financial statements, in 2003 Cinergy Corp., The Cincinnati Gas & Electric Company and PSI Energy, Inc. adopted the October 2002 consensus of EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” that requires all realized and unrealized gains and losses on energy trading derivatives to be shown net in the statement of income whether or not settled physically.  Amounts for the years 2000, 2001 and 2002 have been reclassified in the accompanying statements of income to conform to this new method of presentation.

Deloitte & Touche LLP

Cincinnati, Ohio

February 12, 2003

(June 9, 2003 as to Notes 20 and 21)

2

CINERGY CORP.
AND SUBSIDIARY COMPANIES

3

CINERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

	2002			2001			2000
	(dollars in thousands, except per share amounts)
Operating Revenues (Note 20)
Electric	$	3,403,240		$	3,315,629		$	3,144,700
Gas	590,471			655,678			540,083
Other	130,813			78,246			95,969
Total Operating Revenues	4,124,524			4,049,553			3,780,752
Operating Expenses
Fuel and purchased and exchanged power (Note 20)	1,035,292			1,092,936			924,616
Gas purchased (Note 20)	309,983			397,310			272,779
Operation and maintenance	1,298,398			1,013,326			1,112,255
Depreciation	414,004			374,399			341,927
Taxes other than income taxes	263,002			227,652			268,346
Total Operating Expenses	3,320,679			3,105,623			2,919,923
Operating Income	803,845			943,930			860,829
Equity in Earnings (Losses) of Unconsolidated Subsidiaries	15,261			1,494			6,231
Miscellaneous - Net	12,288			39,672			13,282
Interest	249,906			265,792			223,615
Preferred Dividend Requirement of Subsidiary Trust (Note 3)	23,832			1,067			—
Income Before Taxes	557,656			718,237			656,727
Income Taxes (Note 10)	157,320			255,978			251,607
Preferred Dividend Requirements of Subsidiaries	3,433			3,433			4,585
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle	396,903			458,826			400,535
Discontinued operations, net of tax (Note 15)	(25,428		)	(16,547		)	(1,069		)
Cumulative effect of a change in accounting principle, net of tax (Note 14)	(10,899		)	—			—
Net Income	$	360,576		$	442,279		$	399,466
Average Common Shares Outstanding	167,047			159,110			158,938
Earnings Per Common Share (Note 17)
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle	$	2.37		$	2.88		$	2.52
Discontinued operations, net of tax	(0.15		)	(0.10		)	(0.01		)
Cumulative effect of a change in accounting principle, net of tax	(0.06		)	—			—
Net Income	$	2.16		$	2.78		$	2.51
Earnings Per Common Share - Assuming Dilution (Note 17)
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle	$	2.34		$	2.85		$	2.51
Discontinued operations, net of tax	(0.15		)	(0.10		)	(0.01		)
Cumulative effect of a change in accounting principle, net of tax	(0.06		)	—			—
Net Income	$	2.13		$	2.75		$	2.50
Dividends Declared Per Common Share	$	1.80		$	1.80		$	1.80

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

4

CINERGY CORP.
CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31
	2002		2001
	(dollars in thousands)
Current Assets
Cash and cash equivalents	$	221,083	$	111,067
Restricted deposits	8,116		8,055
Notes receivable (Note 6)	135,873		31,173
Accounts receivable less accumulated provision for doubtful accounts of $16,374 at December 31, 2002, and $34,110 at December 31, 2001 (Note 6)	1,292,410		1,116,225
Materials, supplies, and fuel (Note 1(f))	319,456		239,648
Energy risk management current assets (Note 1(m))	464,028		449,397
Prepayments and other	118,208		110,102
Total Current Assets	2,559,174		2,065,667
Property, Plant, and Equipment - at Cost
Utility plant in service	8,641,351		8,089,961
Construction work in progress	469,300		464,560
Total Utility Plant	9,110,651		8,554,521
Non-regulated property, plant, and equipment	4,704,904		4,478,087
Accumulated depreciation	5,166,881		4,840,757
Net Property, Plant, and Equipment	8,648,674		8,191,851
Other Assets
Regulatory assets (Note 1(c))	1,022,696		1,015,863
Investments in unconsolidated subsidiaries	417,188		332,027
Energy risk management non-current assets (Note 1(m))	162,773		134,445
Other investments	163,851		164,155
Goodwill	43,717		53,587
Other intangible assets	14,736		22,144
Other	273,099		258,120
Total Other Assets	2,098,060		1,980,341
Assets of Discontinued Operations (Note 15)	1,120		61,954
Total Assets	$	13,307,028	$	12,299,813

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

5

CINERGY CORP.
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

	December 31
	2002			2001
	(dollars in thousands)
Current Liabilities
Accounts payable	$	1,321,968		$	1,024,412
Accrued taxes	254,823			195,976
Accrued interest	64,340			56,216
Notes payable and other short-term obligations (Note 5)	667,973			1,144,955
Long-term debt due within one year (Note 4)	191,454			148,431
Energy risk management current liabilities (Note 1(m))	407,710			429,794
Other	108,056			125,436
Total Current Liabilities	3,016,324			3,125,220
Non-Current Liabilities
Long-term debt (Note 4)	4,080,768			3,596,730
Deferred income taxes (Note 10)	1,471,872			1,302,042
Unamortized investment tax credits	118,095			127,385
Accrued pension and other postretirement benefit costs (Note 9)	626,167			498,801
Energy risk management non-current liabilities (Note 1(m))	143,991			135,619
Other	183,613			187,760
Total Non-Current Liabilities	6,624,506			5,848,337
Liabilities of Discontinued Operations (Note 15)	1,707			15,637
Total Liabilities	9,642,537			8,989,194
Preferred Trust Securities (Note 3)
Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company	308,187			306,327
Cumulative Preferred Stock of Subsidiaries
Not subject to mandatory redemption	62,828			62,833
Common Stock Equity (Note 2)
Common Stock - $.01 par value; authorized shares - 600,000,000; outstanding shares - 168,663,115 at December 31, 2002, and 159,402,839 at December 31, 2001	1,687			1,594
Paid-in capital	1,918,136			1,619,659
Retained earnings	1,403,453			1,337,135
Accumulated other comprehensive income (loss) (Note 19)	(29,800		)	(16,929		)
Total Common Stock Equity	3,293,476			2,941,459
Commitments and Contingencies (Note 11)
Total Liabilities and Shareholders’ Equity	$	13,307,028		$	12,299,813

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

6

CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

	Common Stock		Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(dollars in thousands)
2000
Beginning balance (158,923,399 shares)	$	1,589	$	1,597,554		$	1,064,319		$	(9,741	)	$	2,653,721
Comprehensive income:
Net income	—		—			399,466			—			399,466
Other comprehensive income (loss), net of tax effect of $2,755 (Note 19)
Foreign currency translation adjustment (Note 1(r))	—		—			—			2,074			2,074
Minimum pension liability adjustment	—		—			—			(1,099		)	(1,099		)
Unrealized gain (loss) on investment trusts	—		—			—			(2,129		)	(2,129		)
Total comprehensive income	—		—			—			—			398,312
Issuance of common stock - net (44,262 shares)	1		1,769			—			—			1,770
Treasury shares purchased (1,764,758 shares)	—		(3,969		)	—			—			(3,969		)
Treasury shares reissued (1,764,758 shares)	—		11,008			—			—			11,008
Dividends on common stock ($1.80 per share)	—		—			(285,242		)	—			(285,242		)
Other	—		12,791			570			—			13,361
Ending balance (158,967,661 shares)	$	1,590	$	1,619,153		$	1,179,113		$	(10,895	)	$	2,788,961
2001
Comprehensive income:
Net income	—		—			442,279			—			442,279
Other comprehensive income (loss), net of tax effect of $1,454 (Note 19)
Foreign currency translation adjustment (Note 1(r))	—		—			—			1,641			1,641
Minimum pension liability adjustment	—		—			—			(1,555		)	(1,555		)
Unrealized gain (loss) on investment trusts	—		—			—			(841		)	(841		)
Cumulative effect of change in accounting principle (Note 14)	—		—			—			(2,500		)	(2,500		)
Cash flow hedges (Note 1(l))	—		—			—			(2,779		)	(2,779		)
Total comprehensive income	—		—			—			—			436,245
Issuance of common stock - net (435,178 shares)	4		9,896			—			—			9,900
Treasury shares purchased (344,034 shares)	—		(10,015		)	—			—			(10,015		)
Treasury shares reissued (344,034 shares)	—		9,157			—			—			9,157
Dividends on common stock ($1.80 per share)	—		—			(286,289		)	—			(286,289		)
Stock purchase contracts (Note 2(e))	—		(23,200		)	—			—			(23,200		)
Other	—		14,668			2,032			—			16,700
Ending balance (159,402,839 shares)	$	1,594	$	1,619,659		$	1,337,135		$	(16,929	)	$	2,941,459
2002
Comprehensive income:
Net income	—		—			360,576			—			360,576
Other comprehensive income (loss), net of tax effect of $13,575 (Note 19)
Foreign currency translation adjustment, net of reclassification adjustments (Note 1(r))	—		—			—			25,917			25,917
Minimum pension liability adjustment	—		—			—			(13,763		)	(13,763		)
Unrealized gain (loss) on investment trusts	—		—			—			(5,277		)	(5,277		)
Cash flow hedges (Note 1(l))	—		—			—			(19,748		)	(19,748		)
Total comprehensive income	—		—			—			—			347,705
Issuance of common stock - net (9,260,276 shares)	93		267,768			—			—			267,861
Dividends on common stock ($1.80 per share)	—		—			(298,292		)	—			(298,292		)
Other	—		30,709			4,034			—			34,743
Ending balance (168,663,115 shares)	$	1,687	$	1,918,136		$	1,403,453		$	(29,800	)	$	3,293,476

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

7

CINERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS

	2002			2001			2000
	(dollars in thousands)
Operating Activities
Net income	$	360,576		$	442,279		$	399,466
Items providing or (using) cash currently:
Depreciation	414,004			374,399			341,927
Loss on discontinued operations, net of tax	25,428			16,547			1,069
Cumulative effect of a change in accounting principle	10,899			—			—
Change in net position of energy risk management activities	(43,202		)	(96,850		)	(22,533		)
Deferred income taxes and investment tax credits - net	148,467			123,806			47,404
Gain on sale of investment in unconsolidated subsidiaries	(16,518		)	—			—
Equity in earnings of unconsolidated subsidiaries	(15,261		)	(1,494		)	(6,231		)
Allowance for equity funds used during construction	(12,861		)	(8,628		)	(5,813		)
Regulatory assets deferrals	(110,867		)	(141,324		)	(99,661		)
Regulatory assets amortization	116,512			119,344			92,856
Accrued pension and other postretirement benefit costs	127,366			34,246			58,549
Changes in current assets and current liabilities:
Restricted deposits	(61		)	(1,409		)	(3,567		)
Accounts and notes receivable, net of reserves on receivables sold	(236,226		)	502,902			(960,048		)
Materials, supplies, and fuel	(83,458		)	(81,398		)	46,269
Prepayments	(10,041		)	(14,385		)	(16,046		)
Accounts payable	307,860			(466,973		)	761,708
Accrued taxes and interest	66,971			(42,165		)	25,737
Other assets	(15,793		)	(21,675		)	(24,364		)
Other liabilities	(37,596		)	(19,373		)	(4,677		)
Net cash provided by (used in) operating activities	996,199			717,849			632,045
Financing Activities
Change in short-term debt	(476,982		)	27,954			582,122
Issuance of long-term debt	649,020			940,785			126,420
Issuance of preferred trust securities	—			306,327			—
Redemption of long-term debt	(138,379		)	(131,413		)	(234,247		)
Retirement of preferred stock of subsidiaries	(3		)	(1		)	(29,393		)
Issuance of common stock	267,861			9,900			1,770
Dividends on common stock	(298,292		)	(286,289		)	(285,242		)
Net cash provided by (used in) financing activities	3,225			867,263			161,430
Investing Activities
Construction expenditures (less allowance for equity funds used during construction)	(857,104		)	(858,870		)	(531,896		)
Acquisitions and other investments	(118,375		)	(708,229		)	(250,444		)
Proceeds from sale of subsidiaries and equity investments	86,071			—			—
Net cash provided by (used in) investing activities	(889,408		)	(1,567,099		)	(782,340		)
Net increase (decrease) in cash and cash equivalents	110,016			18,013			11,135
Cash and cash equivalents at beginning of period	111,067			93,054			81,919
Cash and cash equivalents at end of period	$	221,083		$	111,067		$	93,054
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized)	$	253,266		$	271,323		$	236,104
Income taxes	$	57,739		$	153,092		$	216,556

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

8

CINERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

	December 31
	2002			2001
	(dollars in thousands)
Long-term Debt (excludes current portion)
Cinergy Corp.
Other Long-term Debt:
6.53% Debentures due December 16, 2008	$	200,000		$	200,000
6.125% Debentures due April 15, 2004	200,000			200,000
6.25% Debentures due September 1, 2004 (Executed interest rate swaps of $250 million set at London Inter-Bank Offered Rate (LIBOR) plus 2.44%)	512,554			500,341
Total Other Long-term Debt	912,554			900,341
Unamortized Premium and Discount - Net	(165		)	(255		)
Total - Cinergy Corp.	912,389			900,086
Cinergy Global Resources, Inc.
Other Long-term Debt:
6.20% Debentures due November 3, 2008	150,000			150,000
Variable interest rate of LIBOR plus 1.75%, due July 2012	12,792			14,042
Variable interest rate of LIBOR plus 2.5%, due July 2009	5,281			5,840
Variable interest rates ranging between the 3 month Prague Inter-Bank Offered Rate plus 0.55% to the 3 month Euro Inter-Bank Offered Rate (EURIBOR) plus 4.12%, maturing March 2004 to March 2005	—			2,752
Fixed interest rates 6.1% - 7.4%, maturing March 2003 to May 2003	—			10,271
Fixed interest rates ranging between 6.35% and 9.911%, maturing September 2010 to September 2019	33,277			13,420
Fixed interest rate of 11.5%, maturing November 2023 to November 2024	17,850			17,850
Variable interest rate of EURIBOR plus 1.2%, maturing November 2016	63,675			52,274
Total Other Long-term Debt	282,875			266,449
Unamortized Premium and Discount - Net	(193		)	(227		)
Total - Cinergy Global Resources, Inc.	282,682			266,222
Operating Companies (See operating companies’ Consolidated Statements of Capitalization for details)
The Cincinnati Gas & Electric Company (CG&E) and subsidiaries
First Mortgage Bonds	470,200			470,200
Other Long-term Debt	1,101,721			637,721
Unamortized Premium and Discount - Net	(2,208		)	(2,588		)
Total Long-term Debt	1,569,713			1,105,333
PSI Energy, Inc. (PSI)
First Mortgage Bonds	620,720			620,720
Secured Medium-term Notes	104,300			160,300
Other Long-term Debt	598,700			552,079
Unamortized Premium and Discount - Net	(7,736		)	(8,010		)
Total Long-term Debt	1,315,984			1,325,089
Total Consolidated Long-term Debt	$	4,080,768		$	3,596,730
Preferred Trust Securities
Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company (Note 3)	$	308,187		$	306,327
Cumulative Preferred Stock of Subsidiaries (See operating companies’ Consolidated Statements of Capitalization for details)
CG&E and subsidiaries	$	20,485		$	20,486
PSI	42,343			42,347
Total Cumulative Preferred Stock of Subsidiaries	$	62,828		$	62,833
Common Stock Equity
Common Stock - $.01 par value; authorized shares - 600,000,000; outstanding shares - 168,663,115 at December 31, 2002, and 159,402,839  at December 31, 2001	$	1,687		$	1,594
Paid-in capital	1,918,136			1,619,659
Retained earnings	1,403,453			1,337,135
Accumulated other comprehensive income (loss) (Note 19)	(29,800		)	(16,929		)
Total Common Stock Equity	3,293,476			2,941,459
Total Consolidated Capitalization	$	7,745,259		$	6,907,349

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

9

THE CINCINNATI GAS & ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES

10

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME

	2002		2001			2000
	(dollars in thousands)
Operating Revenues (Note 20)
Electric	$	1,700,318		$	1,651,041		$	1,609,824
Gas	437,092			596,429			490,972
Total Operating Revenues	2,137,410			2,247,470			2,100,796
Operating Expenses
Fuel and purchased and exchanged power (Note 20)	472,313			435,656			426,008
Gas purchased	232,558			396,764			266,339
Operation and maintenance	533,255			442,173			491,545
Depreciation	196,539			186,986			180,978
Taxes other than income taxes	197,827			174,320			208,385
Total Operating Expenses	1,632,492			1,635,899			1,573,255
Operating Income	504,918			611,571			527,541
Miscellaneous - Net	9,742			4,657			(2,119		)
Interest	95,623			103,047			99,204
Income Before Taxes	419,037			513,181			426,218
Income Taxes (Note 10)	155,341			186,527			159,398
Net Income	$	263,696		$	326,654		$	266,820
Preferred Dividend Requirement	846			846			847
Net Income Applicable to Common Stock	$	262,850		$	325,808		$	265,973

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

11

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31
	2002		2001
	(dollars in thousands)
Current Assets
Cash and cash equivalents	$	45,336	$	9,074
Restricted deposits	3,071		3,540
Notes receivable from affiliated companies (Note 6)	148,823		—
Accounts receivable less accumulated provision for doubtful accounts of $5,942 at December 31, 2002, and $25,874 at December 31, 2001 (Note 6)	117,269		332,970
Accounts receivable from affiliated companies	97,584		12,112
Materials, supplies, and fuel	121,881		138,119
Energy risk management current assets (Note 1(m))	57,912		44,360
Prepayments and other	8,560		13,087
Total Current Assets	600,436		553,262
Property, Plant, and Equipment - at Cost
Utility plant in service
Electric	2,073,133		2,000,595
Gas	1,003,870		926,381
Common	248,938		253,978
Total Utility Plant In Service	3,325,941		3,180,954
Construction work in progress	84,249		96,247
Total Utility Plant	3,410,190		3,277,201
Non-regulated property, plant, and equipment	3,445,056		3,314,285
Accumulated depreciation	2,712,105		2,555,639
Net Property, Plant, and Equipment	4,143,141		4,035,847
Other Assets
Regulatory assets (Note 1(c))	604,776		592,491
Energy risk management non-current assets (Note 1(m))	64,762		48,982
Other Investments	1,082		1,080
Other	127,550		128,082
Total Other Assets	798,170		770,635
Total Assets	$	5,541,747	$	5,359,744

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

12

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

	December 31
	2002			2001
	(dollars in thousands)
Current Liabilities
Accounts payable	$	195,812		$	350,589
Accounts payable to affiliated companies	146,558			30,419
Accrued taxes	159,199			116,616
Accrued interest	22,872			16,570
Notes payable and other short-term obligations (Note 5)	112,100			196,100
Notes payable to affiliated companies (Note 5)	8,947			444,801
Long-term debt due within one year (Note 4)	120,000			100,000
Energy risk management current liabilities (Note 1(m))	49,288			23,341
Other	37,160			33,217
Total Current Liabilities	851,936			1,311,653
Non-Current Liabilities
Long-term debt (Note 4)	1,569,713			1,105,333
Deferred income taxes (Note 10)	882,628			779,295
Unamortized investment tax credits	85,198			91,246
Accrued pension and other postretirement benefit costs (Note 9)	201,284			180,725
Energy risk management non-current liabilities (Note 1(m))	31,326			41,773
Other	88,843			92,143
Total Non-Current Liabilities	2,858,992			2,290,515
Total Liabilities	3,710,928			3,602,168
Cumulative Preferred Stock
Not subject to mandatory redemption	20,485			20,486
Common Stock Equity (Note 2)
Common Stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares - 89,663,086 at December 31, 2002, and December 31, 2001	762,136			762,136
Paid-in capital	586,292			571,926
Retained earnings	487,652			408,706
Accumulated other comprehensive income (loss) (Note 19)	(25,746		)	(5,678		)
Total Common Stock Equity	1,810,334			1,737,090
Commitments and Contingencies (Note 11)
Total Liabilities and Shareholder’s Equity	$	5,541,747		$	5,359,744

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

13

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(dollars in thousands)
2000
Beginning balance	$	762,136	$	562,851	$	335,144		$	(966	)	$	1,659,165
Comprehensive income:
Net income	—		—		266,820			—			266,820
Other comprehensive income (loss), net of tax effect of $15 (Note 19)
Minimum pension liability adjustment	—		—		—			(28		)	(28		)
Total comprehensive income	—		—		—			—			266,792
Dividends on preferred stock	—		—		(847		)	—			(847		)
Dividends on common stock	—		—		(232,334		)	—			(232,334		)
Contribution from parent company for reallocation of taxes	—		2,894		—			—			2,894
Other	—		32		128			—			160
Ending balance	$	762,136	$	565,777	$	368,911		$	(994	)	$	1,695,830
2001
Comprehensive income:
Net income	—		—		326,654			—			326,654
Other comprehensive income (loss), net of tax effect of $2,970 (Note 19)	—		—		—			134			134
Minimum pension liability adjustment
Unrealized gain (loss) on investment trust	—		—		—			461			461
Cumulative effect of change in accounting principle	—		—		—			(2,500		)	(2,500		)
Cash flow hedges (Note 1(l))	—		—		—			(2,779		)	(2,779		)
Total comprehensive income	—		—		—			—			321,970
Dividends on preferred stock	—		—		(846		)	—			(846		)
Dividends on common stock	—		—		(286,269		)	—			(286,269		)
Contribution from parent company for reallocation of taxes	—		6,149		—			—			6,149
Other	—		—		256			—			256
Ending balance	$	762,136	$	571,926	$	408,706		$	(5,678	)	$	1,737,090
2002
Comprehensive income:
Net income	—		—		263,696			—			263,696
Other comprehensive income (loss), net of tax effect of $13,060 (Note 19)	—		—		—			—
Minimum pension liability adjustment	—		—		—			(872		)	(872		)
Unrealized gain (loss) on investment trusts	—		—		—			(462		)	(462		)
Cash flow hedges (Note 1(l))	—		—		—			(18,734		)	(18,734		)
Total comprehensive income	—		—		—			—			243,628
Dividends on preferred stock	—		—		(846		)	—			(846		)
Dividends on common stock	—		—		(185,909		)	—			(185,909		)
Contribution from parent company for reallocation of taxes	—		14,366		—			—			14,366
Other	—		—		2,005			—			2,005
Ending balance	$	762,136	$	586,292	$	487,652		$	(25,746	)	$	1,810,334

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

14

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

	2002			2001			2000
	(dollars in thousands)
Operating Activities
Net income	$	263,696		$	326,654		$	266,820
Items providing or (using) cash currently:
Depreciation	196,539			186,986			180,978
Deferred income taxes and investment tax credits - net	104,103			43,834			36,238
Change in net position of energy risk management activities	(7,061		)	(67,979		)	(7,077		)
Allowance for equity funds used during construction	(356		)	(2,672		)	(4,459		)
Regulatory assets deferrals	(61,321		)	(116,365		)	(35,777		)
Regulatory assets amortization	44,339			56,703			18,154
Accrued pension and other postretirement benefit costs	20,559			(632		)	4,972
Changes in current assets and current liabilities:
Restricted deposits	469			(3,380		)	(28		)
Accounts and notes receivable, net of reserves on receivables sold	84,193			174,385			(235,094		)
Materials, supplies, and fuel	16,238			(39,058		)	(62		)
Prepayments	1,750			19,192			(3,281		)
Accounts payable	(38,441		)	(183,982		)	248,630
Accrued taxes and interest	48,885			(37,209		)	16,902
Other assets	5,020			8,516			11,648
Other liabilities	(25,583		)	(21,875		)	(28,394		)
Net cash provided by (used in) operating activities	653,029			343,118			470,170
Financing Activities
Change in short-term debt, including net affiliate notes	(587,259		)	305,155			40,684
Issuance of long-term debt	580,570			—			—
Redemption of long-term debt	(100,000		)	(1,200		)	—
Retirement of preferred stock	(1		)	—			(168		)
Dividends on preferred stock	(846		)	(845		)	(847		)
Dividends on common stock	(185,909		)	(286,269		)	(232,334		)
Net cash provided by (used in) financing activities	(293,445		)	16,841			(192,665		)
Investing Activities
Construction expenditures (less allowance for equity funds used during construction)	(323,320		)	(371,885		)	(266,455		)
Other investments	(2		)	363			33
Net cash provided by (used in) investing activities	(323,322		)	(371,522		)	(266,422		)
Net increase (decrease) in cash and cash equivalents	36,262			(11,563		)	11,083
Cash and cash equivalents at beginning of period	9,074			20,637			9,554
Cash and cash equivalents at end of period	$	45,336		$	9,074		$	20,637
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized)	$	86,895		$	101,579		$	94,018
Income taxes	$	28,687		$	147,471		$	121,158

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

15

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

	December 31
	2002			2001
	(dollars in thousands)
Long-term Debt (excludes current portion)
CG&E
First Mortgage Bonds:
6.45% Series due February 15, 2004	$	110,000		$	110,000
7.20% Series due October 1, 2023	265,500			265,500
5.45% Series due January 1, 2024 (Pollution Control)	46,700			46,700
5 ½% Series due January 1, 2024 (Pollution Control)	48,000			48,000
Total First Mortgage Bonds	470,200			470,200
Other Long-term Debt:
Liquid Asset Notes with Coupon Exchange due October 1, 2007 (Executed interest rate swap set at 6.87% through maturity commencing at October 19, 2000)	100,000			100,000
6.40% Debentures due April 1, 2008	100,000			100,000
6.90% Debentures due June 1, 2025 (Redeemable at the option of the holders on June 1, 2005)	150,000			150,000
8.28% Junior Subordinated Debentures due July 1, 2025	100,000			100,000
6.35% Debentures due June 15, 2038 (Interest rate resets June 15, 2003)	—			100,000
5.70% Debentures due September 15, 2012	500,000			—
Series 2002A, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control)	42,000			—
Series 2002B, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control)	42,000			—
Series 1992A, 6.50% Collateralized Pollution Control Revenue Refunding Bonds, due November 15, 2022	12,721			12,721
Total Other Long-term Debt	1,046,721			562,721
Unamortized Premium and Discount - Net	(1,861		)	(2,209		)
Total Long-term Debt	1,515,060			1,030,712
The Union Light, Heat and Power Company (ULH&P)
Other Long-term Debt:
6.11% Debentures due December 8, 2003	—			20,000
6.50% Debentures due April 30, 2008	20,000			20,000
7.65% Debentures due July 15, 2025	15,000			15,000
7.875% Debentures due September 15, 2009	20,000			20,000
Total Other Long-term Debt	55,000			75,000
Unamortized Premium and Discount - Net	(347		)	(379		)
Total Long-term Debt	54,653			74,621
Total Consolidated Long-term Debt	$	1,569,713		$	1,105,333

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

16

							December 31
							2002			2001
							(dollars in thousands)
Cumulative Preferred Stock
Par/Stated Value		Authorized Shares	Shares Outstanding at December 31, 2002	Series		Mandatory Redemption
$	100	6,000,000	204,849	4% - 4 ¾	%	No	$	20,485		$	20,486
Common Stock Equity
Common Stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares - 89,663,086 at December 31, 2002, and December 31, 2001							$	762,136		$	762,136
Paid-in capital							586,292			571,926
Retained earnings							487,652			408,706
Accumulated other comprehensive income (loss)							(25,746		)	(5,678		)
Total Common Stock Equity							1,810,334			1,737,090
Total Consolidated Capitalization							$	3,400,532		$	2,862,909

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.

17

PSI ENERGY, INC.
AND SUBSIDIARY COMPANY

18

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME

	2002				2001			2000
	(dollars in thousands)
Operating Revenues (Note 20)
Electric	$	1,610,578	$	1,573,691		$	1,511,502
Operating Expenses
Fuel and purchased and exchanged power (Note 20)	527,360		631,161			551,961
Operation and maintenance	488,903		413,275			463,649
Depreciation	156,102		149,467			141,512
Taxes other than income taxes	56,695		49,955			56,908
Total Operating Expenses	1,229,060		1,243,858			1,214,030
Operating Income	381,518		329,833			297,472
Miscellaneous - Net	20,582		19,541			4,723
Interest	73,142		80,955			78,250
Income Before Taxes	328,958		268,419			223,945
Income Taxes (Note 10)	114,709		106,086			88,547
Net Income	$	214,249	$	162,333		$	135,398
Preferred Dividend Requirement	2,587		2,587			3,738
Net Income Applicable to Common Stock	$	211,662	$	159,746		$	131,660

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

19

PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31
	2002		2001
	(dollars in thousands)
Current Assets
Cash and cash equivalents	$	2,007	$	1,587
Restricted deposits	20		519
Notes receivable from affiliated companies (Note 6)	53,755		444,801
Accounts receivable less accumulated provision for doubtful accounts of $5,656 at December 31, 2002, and $6,773 at December 31, 2001 (Note 6)	84,819		336,994
Accounts receivable from affiliated companies	437		10,470
Materials, supplies, and fuel	137,292		87,661
Energy risk management current assets (Note 1(m))	8,701		28,201
Prepayments and other	44,725		41,041
Total Current Assets	331,756		951,274
Property, Plant, and Equipment - at Cost
Utility plant in service	5,315,410		4,909,007
Construction work in progress	385,051		368,313
Total Utility Plant	5,700,461		5,277,320
Accumulated depreciation	2,334,157		2,216,908
Net Property, Plant, and Equipment	3,366,304		3,060,412
Other Assets
Regulatory assets (Note 1(c))	417,920		423,372
Energy risk management non-current assets (Note 1(m))	16,590		30,164
Other investments	54,683		57,633
Other	35,703		47,927
Total Other Assets	524,896		559,096
Total Assets	$	4,222,956	$	4,570,782

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

20

PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

	December 31
	2002			2001
	(dollars in thousands)
Current Liabilities
Accounts payable	$	113,563		$	312,707
Accounts payable to affiliated companies	107,364			27,370
Accrued taxes	105,960			102,317
Accrued interest	23,078			23,760
Notes payable and other short-term obligations (Note 5)	35,000			148,600
Notes payable to affiliated companies (Note 5)	138,055			422,263
Long-term debt due within one year (Note 4)	56,000			23,000
Energy risk management current liabilities (Note 1(m))	8,000			23,185
Other	22,335			41,695
Total Current Liabilities	609,355			1,124,897
Non-Current Liabilities
Long-term debt (Note 4)	1,315,984			1,325,089
Deferred income taxes (Note 10)	538,745			486,694
Unamortized investment tax credits	32,897			36,139
Accrued pension and other postretirement benefit costs (Note 9)	184,299			160,169
Energy risk management non-current liabilities (Note 1(m))	17,157			41,773
Other	80,879			58,187
Total Non-Current Liabilities	2,169,961			2,108,051
Total Liabilities	2,779,316			3,232,948
Cumulative Preferred Stock
Not subject to mandatory redemption	42,343			42,347
Common Stock Equity (Note 2)
Common Stock - without par value; $0.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at December 31, 2002, and December 31, 2001	539			539
Paid-in capital	426,931			416,414
Retained earnings	981,946			880,129
Accumulated other comprehensive income (loss) (Note 19)	(8,119		)	(1,595		)
Total Common Stock Equity	1,401,297			1,295,487
Commitments and Contingencies (Note 11)
Total Liabilities and Shareholder’s Equity	$	4,222,956		$	4,570,782

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

21

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

	Common Stock		Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(dollars in thousands)
2000
Beginning balance	$	539	$	411,198		$	642,569		$	1,391		$	1,055,697
Comprehensive income:
Net income	—		—			135,398			—			135,398
Other comprehensive income (loss), net of tax effect of $584 (Note 19)
Minimum pension liability adjustment	—		—			—			(47		)	(47		)
Unrealized gain (loss) on investment trust	—		—			—			(1,864		)	(1,864		)
Total comprehensive income	—		—			—			—			133,487
Dividends on preferred stock	—		—			(3,738		)	—			(3,738		)
Dividends on common stock	—		—			(54,000		)	—			(54,000		)
Contribution from parent company for reallocation of taxes	—		1,989			—			—			1,989
Other	—		336			(76		)	—			260
Ending balance	$	539	$	413,523		$	720,153		$	(520	)	$	1,133,695
2001
Comprehensive income:
Net income	—		—			162,333			—			162,333
Other comprehensive income (loss), net of tax effect of $538 (Note 19)
Minimum pension liability adjustment	—		—			—			(49		)	(49		)
Unrealized gain (loss) on investment trusts	—		—			—			(1,026		)	(1,026		)
Total comprehensive income	—		—			—			—			161,258
Dividends on preferred stock	—		—			(2,587		)	—			(2,587		)
Contribution from parent company for reallocation of taxes	—		2,894			—			—			2,894
Other	—		(3		)	230			—			227
Ending balance	$	539	$	416,414		$	880,129		$	(1,595	)	$	1,295,487
2002
Comprehensive income:
Net income	—		—			214,249			—			214,249
Other comprehensive income (loss), net of tax effect of $4,189 (Note 19)
Minimum pension liability adjustment	—		—			—			(2,138		)	(2,138		)
Unrealized gain (loss) on investment trusts	—		—			—			(4,386		)	(4,386		)
Total comprehensive income	—		—			—			—			207,725
Dividends on preferred stock	—		—			(2,587		)	—			(2,587		)
Dividends on common stock	—		—			(111,842		)	—			(111,842		)
Contribution from parent company for reallocation of taxes	—		10,519			—			—			10,519
Other	—		(2		)	1,997			—			1,995
Ending balance	$	539	$	426,931		$	981,946		$	(8,119	)	$	1,401,297

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

22

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

	2002			2001			2000
	(dollars in thousands)
Operating Activities
Net income	$	214,249		$	162,333		$	135,398
Items providing or (using) cash currently:
Depreciation	156,102			149,467			141,512
Deferred income taxes and investment tax credits - net	33,908			41,543			(6,582		)
Change in net position of energy risk management activities	9,544			(33,158		)	(7,077		)
Allowance for equity funds used during construction	(12,505		)	(5,956		)	(1,354		)
Regulatory assets deferrals	(49,546		)	(24,959		)	(63,884		)
Regulatory assets amortization	72,173			62,641			74,702
Accrued pension and other postretirement benefit costs	24,130			10,597			11,794
Changes in current assets and current liabilities:
Restricted deposits	499			(178		)	(341		)
Accounts and notes receivable, net of reserves on receivables sold	233,040			119,311			(178,453		)
Materials, supplies, and fuel	(49,631		)	(33,823		)	49,652
Prepayments	(2,908		)	(120		)	(677		)
Accounts payable	(119,032		)	(84,577		)	176,820
Accrued taxes and interest	2,961			21,374			(15,342		)
Other assets	(22,161		)	17,074			(4,322		)
Other liabilities	8,224			342			31,192
Net cash provided by (used in) operating activities	499,047			401,911			343,038
Financing Activities
Change in short-term debt, including net affiliate notes	46,993			(195,912		)	143,030
Issuance of long-term debt	47,600			322,471			53,075
Redemption of long-term debt	(23,979		)	(89,248		)	(187,097		)
Retirement of preferred stock	(2		)	(1		)	(29,225		)
Dividends on preferred stock	(2,587		)	(2,587		)	(3,738		)
Dividends on common stock	(111,842		)	—			(54,000		)
Net cash provided by (used in) financing activities	(43,817		)	34,723			(77,955		)
Investing Activities
Construction expenditures (less allowance for equity funds used during construction)	(451,326		)	(427,787		)	(263,317		)
Other investments	(3,484		)	(8,571		)	(9,297		)
Net cash provided by (used in) investing activities	(454,810		)	(436,358		)	(272,614		)
Net increase (decrease) in cash and cash equivalents	420			276			(7,531		)
Cash and cash equivalents at beginning of period	1,587			1,311			8,842
Cash and cash equivalents at end of period	$	2,007		$	1,587		$	1,311
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized)	$	89,865		$	97,917		$	98,283
Income taxes	$	27,401		$	41,419		$	112,210

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

23

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

						December 31
						2002			2001
						(dollars in thousands)
Long-term Debt (excludes current portion)
First Mortgage Bonds:
Series ZZ, 53/4% due February 15, 2028 (Pollution Control)						$	50,000		$	50,000
Series AAA, 71/8% due February 1, 2024						30,000			30,000
Series BBB, 8.0% due July 15, 2009						124,665			124,665
Series CCC, 8.85% due January 15, 2022						53,055			53,055
Series DDD, 8.31% due September 1, 2032						38,000			38,000
Series EEE, 6.65% due June 15, 2006						325,000			325,000
Total First Mortgage Bonds						620,720			620,720
Secured Medium-term Notes:
Series A, 8.37% to 8.81%, due November 8, 2006 to June 1, 2022						34,300			34,300
Series B, 6.37% to 8.24%, due August 15, 2008 to August 22, 2022						70,000			126,000
(Series A and B, 7.623% weighted average interest rate and 13.9 year weighted average remaining life)
Total Secured Medium-term Notes						104,300			160,300
Other Long-term Debt:
Series 2000A, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due May 1, 2035						44,025			44,025
Series 2000B, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due April 1, 2022						10,000			10,000
6.35% Debentures due November 15, 2006						50			50
6.50% Synthetic Putable Yield Securities due August 1, 2026 (Interest rate resets August 1, 2005)						50,000			50,000
7.25% Junior Maturing Principal Securities due March 15, 2028						2,658			2,658
6.00% Rural Utilities Service Obligation payable in annual installments						82,025			83,004
6.52% Senior Notes due March 15, 2009						97,342			97,342
7.85% Debentures due October 15, 2007						265,000			265,000
Series 2002A, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2031						23,000			—
Series 2002B, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2019						24,600			—
Total Other Long-term Debt						598,700			552,079
Unamortized Premium and Discount - Net						(7,736		)	(8,010		)
Total Long-term Debt						1,315,984			1,325,089
Cumulative Preferred Stock
Par/Stated Value		Authorized Shares	Shares Outstanding at December 31, 2002	Series	Mandatory Redemption
$	100	5,000,000	347,545	31/2% - 67/8%	No	$	34,754		$	34,758
$	25	5,000,000	303,544	4.16% - 4.32%	No	7,589			7,589
Total Preferred Stock						42,343			42,347
Common Stock Equity
Common Stock - without par value; $0.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at December 31, 2002, and December 31, 2001						$	539		$	539
Paid-in capital						426,931			416,414
Retained earnings						981,946			880,129
Accumulated other comprehensive income (loss)						(8,119		)	(1,595		)
Total Common Stock Equity						1,401,297			1,295,487
Total Consolidated Capitalization						$	2,759,624		$	2,662,923

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.

24

THE UNION LIGHT, HEAT AND POWER COMPANY

25

THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME

	2002		2001		2000
	(dollars in thousands)
Operating Revenues
Electric	$	226,856	$	230,960	$	225,601
Gas	81,706		109,333		91,950
Total Operating Revenues	308,562		340,293		317,551
Operating Expenses
Electricity purchased from parent company for resale (Note 1(s)(ii))	159,734		151,562		159,915
Gas purchased	46,886		72,593		51,591
Operation and maintenance	50,223		39,501		40,699
Depreciation	17,350		17,039		15,685
Taxes other than income taxes	4,598		3,901		3,938
Total Operating Expenses	278,791		284,596		271,828
Operating Income	29,771		55,697		45,723
Miscellaneous - Net	666		239		(982		)
Interest	5,938		6,313		6,308
Income Before Taxes	24,499		49,623		38,433
Income Taxes (Note 10)	12,349		13,699		13,801
Net Income	$	12,150	$	35,924	$	24,632

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

26

THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS

ASSETS

	December 31
	2002		2001
	(dollars in thousands)
Current Assets
Cash and cash equivalents	$	3,926	$	4,099
Notes receivable from affiliated companies (Note 6)	13,337		—
Accounts receivable less accumulated provision for doubtful accounts of $84 at December 31, 2002, and $1,196 at December 31, 2001 (Note 6)	703		16,785
Accounts receivable from affiliated companies	1,671		2,401
Materials, supplies, and fuel	8,182		10,835
Prepayments and other	316		300
Total Current Assets	28,135		34,420
Property, Plant, and Equipment - at Cost
Utility plant in service
Electric	258,094		248,223
Gas	215,505		197,301
Common	31,679		50,289
Total Utility Plant In Service	505,278		495,813
Construction work in progress	14,745		11,004
Total Utility Plant	520,023		506,817
Accumulated depreciation	187,876		178,567
Net Property, Plant, and Equipment	332,147		328,250
Other Assets
Regulatory assets (Note 1(c))	5,134		7,838
Other	16,811		6,582
Total Other Assets	21,945		14,420
Total Assets	$	382,227	$	377,090

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

27

THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

	December 31
	2002			2001
	(dollars in thousands)
Current Liabilities
Accounts payable	$	8,816		$	7,960
Accounts payable to affiliated companies	22,297			16,156
Accrued taxes	1,487			7,051
Accrued interest	1,226			643
Long-term debt due within one year (Note 4)	20,000			—
Notes payable to affiliated companies (Note 5)	14,076			26,432
Other	6,368			5,322
Total Current Liabilities	74,270			63,564
Non-Current Liabilities
Long-term debt (Note 4)	54,653			74,621
Deferred income taxes (Note 10)	43,360			28,323
Unamortized investment tax credits	3,143			3,411
Accrued pension and other postretirement benefit costs (Note 9)	15,620			13,277
Other	14,017			21,691
Total Non-Current Liabilities	130,793			141,323
Total Liabilities	205,063			204,887
Common Stock Equity (Note 2)
Common Stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares - 585,333 at December 31, 2002, and December 31, 2001	8,780			8,780
Paid-in capital	23,644			21,111
Retained earnings	144,800			142,320
Accumulated other comprehensive income (loss)	(60		)	(8		)
Total Common Stock Equity	177,164			172,203
Commitments and Contingencies (Note 11)
Total Liabilities and Shareholder’s Equity	$	382,227		$	377,090

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

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THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(dollars in thousands)
2000
Beginning balance	$	8,780	$	20,142	$	103,128		$	—		$	132,050
Net income	—		—		24,632			—			24,632
Dividends on common stock	—		—		(9,657		)	—			(9,657		)
Contribution from parent company for reallocation of taxes	—		163		—			—			163
Ending balance	$	8,780	$	20,305	$	118,103		$	—		$	147,188
2001
Comprehensive income:
Net income	—		—		35,924			—			35,924
Other comprehensive income (loss), net of tax effect of $5 Minimum pension liability adjustment	—		—		—			(8		)	(8		)
Total comprehensive income (loss)	—		—		—			—			35,916
Dividends on common stock	—		—		(11,707		)	—			(11,707		)
Contribution from parent company for reallocation of taxes	—		806		—			—			806
Ending balance	$	8,780	$	21,111	$	142,320		$	(8	)	$	172,203
2002
Comprehensive income:
Net income	—		—		12,150			—			12,150
Other comprehensive income (loss), net of tax effect of $36 Minimum pension liability adjustment	—		—		—			(52		)	(52		)
Total comprehensive income (loss)	—		—		—			—			12,098
Dividends on common stock	—		—		(9,670		)	—			(9,670		)
Contribution from parent company for reallocation of taxes	—		2,533		—			—			2,533
Ending balance	$	8,780	$	23,644	$	144,800		$	(60	)	$	177,164

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

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THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CASH FLOWS

	2002			2001			2000
	(dollars in thousands)
Operating Activities
Net income	$	12,150		$	35,924		$	24,632
Items providing or (using) cash currently:
Depreciation	17,350			17,039			15,685
Deferred income taxes and investment tax credits - net	3,116			(7,116		)	8,926
Allowance for equity funds used during construction	(794		)	(143		)	(61		)
Regulatory assets deferrals	3,954			1,098			(12		)
Regulatory assets amortization	(1,452		)	1,038			271
Accrued pension and other postretirement benefit costs	2,343			154			790
Changes in current assets and current liabilities:
Accounts and notes receivable, net of reserves on receivables sold	8,997			12,112			(14,269		)
Materials, supplies, and fuel	2,653			(4,535		)	1,354
Prepayments	(16		)	(26		)	(55		)
Accounts payable	6,997			(20,325		)	15,832
Accrued taxes and interest	(4,981		)	12,239			(6,582		)
Other assets	2,852			(1,838		)	2,158
Other liabilities	7,538			2,145			890
Net cash provided by (used in) operating activities	60,707			47,766			49,559
Financing Activities
Change in short-term debt	(12,356		)	(2,971		)	(8,349		)
Dividends on common stock	(9,670		)	(11,707		)	(9,657		)
Net cash provided by (used in) financing activities	(22,026		)	(14,678		)	(18,006		)
Investing Activities
Construction expenditures (less allowance for equity funds used during construction)	(38,854		)	(35,449		)	(28,734		)
Net cash provided by (used in) investing activities	(38,854		)	(35,449		)	(28,734		)
Net increase (decrease) in cash and cash equivalents	(173		)	(2,361		)	2,819
Cash and cash equivalents at beginning of period	4,099			6,460			3,641
Cash and cash equivalents at end of period	$	3,926		$	4,099		$	6,460
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized)	$	5,067		$	6,594		$	6,103
Income taxes	$	2,398		$	10,848		$	11,760

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

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THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CAPITALIZATION

	December 31
	2002			2001
	(dollars in thousands)
Long-term Debt (excludes current portion)
Other Long-term Debt:
6.11% Debentures due December 8, 2003	$	—		$	20,000
6.50% Debentures due April 30, 2008	20,000			20,000
7.65% Debentures due July 15, 2025	15,000			15,000
7.875% Debentures due September 15, 2009	20,000			20,000
Total Other Long-term Debt	55,000			75,000
Unamortized Premium and Discount - Net	(347		)	(379		)
Total Long-term Debt	54,653			74,621
Common Stock Equity
Common Stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares - 585,333 at December 31, 2002, and December 31, 2001	$	8,780		$	8,780
Paid-in capital	23,644			21,111
Retained earnings	144,800			142,320
Accumulated other comprehensive income (loss)	(60		)	(8		)
Total Common Stock Equity	177,164			172,203
Total Capitalization	$	231,817		$	246,824

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS

In this report Cinergy (which includes Cinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as “we”, “our”, or “us”.

1.Summary of Significant Accounting Policies

(a)Nature of Operations

Cinergy Corp., a Delaware corporation created in October 1994, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utility subsidiaries.  As a result of this ownership, we are considered a utility holding company.  Because we are a holding company with material utility subsidiaries operating in multiple states, we are registered with and are subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA).  Our other principal subsidiaries are:

•Cinergy Services, Inc. (Services);

•Cinergy Investments, Inc. (Investments);

•Cinergy Global Resources, Inc. (Global Resources); and

•Cinergy Wholesale Energy, Inc. (Wholesale Energy).

CG&E, an Ohio corporation, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its subsidiaries, in nearby areas of Kentucky and Indiana.  CG&E’s principal subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation that provides electric and gas service in northern Kentucky.  CG&E’s other subsidiaries are insignificant to its results of operations.

In 2001, CG&E began a transition to electric deregulation and customer choice.  Currently, the competitive retail electric market in Ohio is in the development stage.  CG&E is recovering its Public Utilities Commission of Ohio (PUCO) approved costs and retail electric rates are frozen during this market development period.  See Note 18 for a discussion of key elements of Ohio deregulation.

PSI, an Indiana corporation, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana.

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The following table presents further information related to the operations of our domestic utility companies (our operating companies):

Principal Line(s) of Business
CG&E and subsidiaries	•	Generation, transmission, distribution, and sale of electricity
	•	Sale and/or transportation of natural gas
PSI	•	Generation, transmission, distribution, and sale of electricity
ULH&P	•	Transmission, distribution, and sale of electricity
	•	Sale and transportation of natural gas

Services is a service company that provides our subsidiaries with a variety of centralized administrative, management, and support services.  Investments holds most of our domestic non-regulated, energy-related businesses and investments, including gas marketing and trading operations.  Global Resources holds most of our international businesses and investments.

Wholesale Energy, through a wholly-owned subsidiary, Cinergy Power Generation Services, LLC (Generation Services), provides electric production-related construction, operation, and maintenance services to certain affiliates and non-affiliated third parties.

We conduct operations through our subsidiaries and manage through the following three business units:

•Energy Merchant Business Unit (Energy Merchant);

•Regulated Businesses Business Unit (Regulated Businesses); and

•Power Technology and Infrastructure Services Business Unit (Power Technology).

For further discussion of business units see Note 16.

(b)Presentation

Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles (GAAP).  Actual results could differ, as these estimates and assumptions involve judgment.  These estimates and assumptions affect various matters, including:

•the reported amounts of assets and liabilities in our Balance Sheets at the dates of the financial statements;

•the disclosure of contingent assets and liabilities at the dates of the financial statements; and

•the reported amounts of revenues and expenses in our Statements of Income during the reporting periods.

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Additionally, we have reclassified certain prior-year amounts in the financial statements of Cinergy, CG&E, PSI, and ULH&P to conform to current presentation.

We use three different methods to report investments in subsidiaries or other companies: the consolidation method, the equity method, and the cost method.

(i)Consolidation Method

We use the consolidation method when we own a majority of the voting stock of or have the ability to control a subsidiary.  We eliminate all significant intercompany transactions when we consolidate these accounts.  Our consolidated financial statements include the accounts of Cinergy, CG&E, and PSI, and their wholly-owned subsidiaries.

(ii)Equity Method

We use the equity method to report investments, joint ventures, partnerships, subsidiaries, and affiliated companies in which we do not have control, but have the ability to exercise influence over operating and financial policies (generally, 20 percent to 50 percent ownership).  Under the equity method we report:

•our investment in the entity as Investments in unconsolidated subsidiaries in our Consolidated Balance Sheets; and

•our percentage share of the earnings from the entity as Equity in earnings (losses) of unconsolidated subsidiaries in our Consolidated Statements of Income.

(iii)Cost Method

We use the cost method to report investments, joint ventures, partnerships, subsidiaries, and affiliated companies in which we do not have control and are unable to exercise significant influence over operating and financial policies (generally, up to 20 percent ownership).  Under the cost method we report our investments in the entity as Other investments in our Balance Sheets.

(c)Regulation

Our operating companies and certain of our non-utility subsidiaries must comply with the rules prescribed by the SEC under the PUHCA.  Our operating companies must also comply with the rules prescribed by the Federal Energy Regulatory Commission (FERC) and the state utility commissions of Ohio, Indiana, and Kentucky.

Our operating companies use the same accounting policies and practices for financial reporting purposes as non-regulated companies under GAAP.  However, sometimes actions by the FERC and the state utility commissions result in accounting treatment different from that used by non-regulated companies.  When this occurs, we apply the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71).  In accordance with Statement 71, we record regulatory assets and liabilities (expenses deferred for future recovery from customers or obligations to be refunded to customers) on our Balance Sheets.

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Comprehensive electric deregulation legislation was passed in Ohio on July 6, 1999.  As required by the legislation, CG&E filed its Proposed Transition Plan for approval by the PUCO on December 28, 1999.  On August 31, 2000, the PUCO approved a stipulation agreement relating to CG&E’s transition plan.  This plan created a Regulatory Transition Charge (RTC), designed to recover CG&E’s generation-related regulatory assets and transition costs over a ten-year period which began January 1, 2001.  Accordingly, Statement 71 was discontinued for the generation portion of CG&E’s business and Statement of Financial Accounting Standards No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71 was applied.  The effect of this change on the financial statements was immaterial.  Except with respect to the generation-related assets and liabilities of CG&E, as of December 31, 2002, PSI, CG&E, and ULH&P continue to meet the criteria of Statement 71.  However, to the extent other states implement deregulation legislation, the application of Statement 71 will need to be reviewed.  Based on our operating companies’ current regulatory orders and the regulatory environment in which they currently operate, the recovery of regulatory assets recognized in the accompanying Balance Sheets as of December 31, 2002, is probable.  For a further discussion of Ohio deregulation see Note 18.

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Our regulatory assets and amounts authorized for recovery through regulatory orders at December 31, 2002, and 2001, are as follows:

	2002						2001
	CG&E(1)		PSI		Cinergy		CG&E(1)		PSI		Cinergy
	(in millions)
Amounts due from customers - income taxes(2)	$	53	$	25	$	78	$	57	$	5	$	62
Gasification services agreement buyout costs(3)(7)	—		240		240		—		244		244
Post-in-service carrying costs and deferred operating expenses(7)(8)	1		42		43		—		39		39
Coal contract buyout costs(4)(7)	—		10		10		—		26		26
Deferred demand-side management costs	—		3		3		—		9		9
Deferred merger costs	1		51		52		6		56		62
Unamortized costs of reacquiring debt	9		30		39		10		33		43
Coal gasification services expenses(7)	—		4		4		—		8		8
RTC recoverable assets(5)(7)	537		—		537		511		—		511
Other	4		13		17		9		3		12
Total regulatory assets	$	605	$	418	$	1,023	$	593	$	423	$	1,016
Authorized for recovery(6)	$	598	$	360	$	958	$	573	$	379	$	952

(1)	Includes $5 million at December 31, 2002, and $8 million at December 31, 2001, related to ULH&P.  Of these amounts, $3.6 million at December 31, 2002, and $.6 million at December 31, 2001, have been authorized for recovery.
(2)	The various regulatory commissions overseeing the regulated business operations of our operating companies regulate income tax provisions reflected in customer rates.  In accordance with the provisions of Statement 71, we have recorded net regulatory assets for CG&E and PSI.
(3)	PSI reached an agreement with Dynegy, Inc. to purchase the remainder of its 25-year contract for coal gasification services.  In accordance with an order from the Indiana Utility Regulatory Commission (IURC), PSI began recovering this asset over an 18-year period that commenced upon the termination of the gas services agreement in 2000.
(4)	In August 1996, PSI entered into a coal supply agreement, which expired December 31, 2000.  The agreement provided for a buyout charge, which is being recovered through the fuel adjustment clause.
(5)	In August 2000, CG&E’s deregulation transition plan was approved.  Effective January 1, 2001, a RTC went into effect and provides for recovery of all then existing generation-related regulatory assets and various transition costs over a ten-year period.  Because a separate charge provides for recovery, these assets were aggregated and are included as a single amount in this presentation.  The classification of all transmission and distribution related regulatory assets has remained the same.
(6)	At December 31, 2002, these amounts were being recovered through rates charged to customers over a period ranging from 1 to 50 years for CG&E, 1 to 31 years for PSI, and 1 to 18 years for ULH&P.
(7)	Regulatory assets earning a return at December 31, 2002.
(8)	For PSI amount includes $10 million that is not yet authorized for recovery and currently is not earning a return at December 31, 2002.

(d)Cash and Cash Equivalents

We define Cash equivalents on our Balance Sheets and Statements of Cash Flows as investments with maturities of three months or less when acquired.

(e)Operating Revenues, Energy Purchases, and Fuel Costs

Our operating companies record Operating Revenues and associated expenses for electric and gas service when they provide the service to customers.  Customers are billed throughout the month as both gas and electric meters are read.  We recognize revenues for retail energy sales that have not yet been billed, but where gas or electricity has been consumed.  This is termed

36

“unbilled revenue” and is a widely recognized and accepted practice for utilities.  In making our estimates of unbilled revenue we use complex systems that consider various factors, including weather, in our calculation of retail customer consumption at the end of each month.  Given the use of these systems and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when revenue is billed.  Related receivables are sold under the accounts receivable sales agreement and therefore are not reflected on our Balance Sheets.  See Note 6 for additional information.

The amount of unbilled revenues for Cinergy, CG&E, PSI, and ULH&P as of December 31, 2002, 2001, and 2000, were as follows:

	2002		2001		2000
	(in millions)
Cinergy	$	153	$	172	$	231
CG&E and subsidiaries	89		104		153
PSI	64		68		78
ULH&P	15		18		26

The expenses associated with these electric and gas services include:

•fuel used to generate electricity;

•electricity purchased from others;

•natural gas purchased from others; and

•transportation costs associated with the purchase of fuel, electricity, and natural gas.

These expenses are shown in the Statements of Income of Cinergy, CG&E, and PSI as Fuel and purchased and exchanged power expense and Gas purchased expense.  These expenses are shown in ULH&P’s Statements of Income as Electricity purchased from parent for resale expense and Gas purchased expense.  Any portion of these costs that are recoverable or refundable to customers in future periods is deferred in either Accounts receivable or Accounts payable in our Balance Sheets.

Indiana law limits the amount of fuel costs that PSI can recover to an amount that will not result in earning a return in excess of that allowed by the IURC.  Due to deregulation in the state of Ohio, the recovery of fuel costs in retail electric rates has been frozen.

PSI utilizes a purchased power tracking mechanism (Tracker) approved by the IURC for the recovery of costs related to purchases of power necessary to meet native load requirements to the extent such costs are not recovered through the existing fuel adjustment clause.  See Note 11(m) for additional information.

(f)Inventory

Natural gas inventory for Cinergy Marketing & Trading, LP (Marketing & Trading) is accounted for at fair value.  All other inventory is accounted for at the lower of cost or market, cost being determined through the weighted average method.  Effective January 1, 2003,

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Marketing & Trading’s gas inventory will be adjusted to the cost method with a cumulative effect adjustment, as required by Emerging Issues Task Force (EITF) Issue 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3).  See 1(q)(i) below for additional discussion of the impacts of EITF 02-3.

(g)Property, Plant, and Equipment

Property, Plant, and Equipment includes the utility and non-regulated business property and equipment that is in use, being held for future use, or under construction.  We report our Property, Plant, and Equipment at its original cost, which includes:

•materials;

•salaries;

•payroll taxes;

•fringe benefits;

•financing costs of funds used during construction (described below in (i) and (j)); and

•other miscellaneous amounts.

We capitalize costs for regulated property, plant, and equipment that are associated with the replacement or the addition of equipment that is considered a property unit.  Property units are intended to describe an item or group of items.  The cost of normal repairs and maintenance is expensed as incurred.  When regulated property, plant, and equipment is retired, Cinergy charges the original cost plus the cost of retirement, less salvage, to accumulated depreciation.  A gain or loss is recorded on the sale of regulated property, plant, and equipment if an entire operating unit, as defined by the FERC, is sold.  A gain or loss is recorded on non-regulated property, plant, and equipment whenever there is a related sale or retirement.

In August 2000, the generation assets of CG&E were released from the first mortgage indenture lien.  CG&E’s transmission and distribution assets, and any generating assets added after August 2000, remain subject to the lien of the first mortgage bond indenture.  The utility property of PSI is also subject to the lien of its first mortgage bond indenture.

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(h)Depreciation

We determine the provisions for depreciation expense using the straight-line method.  The depreciation rates are based on periodic studies of the estimated useful lives and the net cost to remove the properties.  Inclusion of cost of removal in depreciation rates will be discontinued for all non-regulated property beginning in 2003 as a result of adopting Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (Statement 143).  See (q)(iii) below for additional discussion of this change.  Our operating companies use composite depreciation rates, which are approved by the respective state commissions.  The average depreciation rates for Property, Plant, and Equipment, excluding software, are presented in the table below.

	2002		2001		2000
Cinergy(1)	3.0	%	3.0	%	3.0	%
CG&E and subsidiaries	2.9		2.9		2.9
PSI	3.0		3.0		3.0
ULH&P	3.2		3.3		3.3

(1) The results of Cinergy also include amounts related to non-registrants.

(i)Allowance for Funds Used During Construction (AFUDC)

Our operating companies finance construction projects with borrowed funds and equity funds.  Regulatory authorities allow us to record the costs of these funds as part of the cost of construction projects.  AFUDC is calculated using a methodology authorized by the regulatory authorities.  The borrowed funds component of AFUDC, which is recorded on a pre-tax basis, for the years ended December 31, 2002, 2001, and 2000, were as follows:

	2002		2001		2000
	(in millions)
Cinergy	$	10.1	$	8.4	$	8.2
CG&E and subsidiaries	1.0		1.0		5.0
PSI	9.1		7.4		3.2
ULH&P	0.2		0.2		0.4

With the deregulation of CG&E’s generation assets, the AFUDC method is no longer used to capitalize the cost of funds used during generation-related construction at CG&E.  See (j) below for a discussion of capitalized interest.

(j)Capitalized Interest

Cinergy capitalizes interest costs for non-regulated construction projects in accordance with Statement of Financial Accounting Standards No. 34, Capitalization of Interest Cost (Statement 34).

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The primary differences from AFUDC are that Statement 34 methodology does not include a component for equity funds and does not emphasize short-term borrowings over long-term borrowings.  Capitalized interest costs, which are recorded on a pre-tax basis, for the years ended December 31, 2002, 2001, and 2000, were as follows:

	2002		2001		2000(1)
	(in millions)
Cinergy(2)	$	7.2	$	7.1	$	—
CG&E and subsidiaries	7.2		5.5		—

(1)	Amounts for 2000 were immaterial.
(2)	The results of Cinergy also include amounts related to non-registrants.

(k)Federal and State Income Taxes

Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, requires an asset and liability approach for financial accounting and reporting of income taxes.  The tax effects of differences between the financial reporting and tax basis of accounting are reported as Deferred income tax assets or liabilities in our Balance Sheets and are based on currently enacted income tax rates.

Investment tax credits, which have been used to reduce our federal income taxes payable, have been deferred for financial reporting purposes.  These deferred investment tax credits are being amortized over the useful lives of the property to which they are related.  For a further discussion of income taxes see Note 10.

(l)Financial Derivatives

We use derivative financial instruments to manage:

•funding costs;

•exposure to fluctuations in interest rates; and

•exposure to foreign currency exchange rates.

We account for derivatives under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133), which requires all derivatives that are not exempted to be accounted for at fair value.  Changes in the derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met.  Gains and losses on derivatives that qualify as hedges can (a) offset related fair value changes on the hedged item in the income statement for fair value hedges; or (b) be recorded in other comprehensive income for cash flow hedges.  To qualify for hedge accounting, financial instruments must be designated as a hedge (for example, an offset of foreign exchange or interest rate risks) at the inception of the contract and must be effective at reducing the risk associated with the hedged item.  Accordingly, changes in the fair values or cash flows of instruments designated as hedges must be highly correlated with changes in the fair values or cash flows of the related hedged items.

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From time to time, we may use foreign currency contracts (for example, a contract obligating one party to buy, and the other to sell, a specified quantity of a foreign currency for a fixed price at a future date) and currency swaps (for example, a contract whereby two parties exchange principal and interest cash flows denominated in different currencies) to hedge foreign currency denominated purchase and sale commitments (cash flow hedges) and certain of our net investments in foreign operations (net investment hedges) against currency exchange rate fluctuations.  Reclassification of unrealized gains or losses on foreign currency cash flow hedges from other comprehensive income occurs when the underlying hedged item is recorded in income.

We also use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for floating-interest rate cash flows) and treasury locks (an agreement that fixes the yield or price on a specific treasury security for a specific period, which we sometimes use in connection with the issuance of fixed rate debt).  Through December 31, 2000, we utilized the accrual method to account for these interest rate swaps and treasury locks.  Accordingly, gains and losses were calculated based on the current period difference between the fixed-rate and the floating-rate interest amounts, using agreed upon notional amounts.  These gains and losses were recognized in our Statements of Income as a component of Interest over the life of the agreement.  Effective with our adoption of Statement 133 in the first quarter of 2001, we began accounting for all derivatives (including interest rate swaps and treasury locks) using fair value accounting, and we assess the effectiveness of any interest rate swaps and/or treasury locks used in hedging activities.

At December 31, 2002, the ineffectiveness of instruments that we have classified as cash flow hedges of variable-rate debt instruments was not material.  Reclassification of unrealized gains or losses on cash flow hedges of debt instruments from Accumulated other comprehensive income (loss) occurs as interest is accrued on the debt instrument.  We currently estimate that on an after-tax basis, $5 million of unrealized losses will be reclassified as a charge to Interest during the twelve-month period ending December 31, 2003.  See (q)(iv) below for further discussion of Statement 133.

(m)Energy Marketing and Trading

We market and trade electricity, natural gas, coal, and other energy-related products.  We designate derivative transactions as trading or non-trading at the time they are originated in accordance with EITF 02-3.  Derivatives are classified as non-trading only when we have the intent and projected ability to fulfill substantially all obligations from company-owned assets.  Such classification is generally limited to the sale of generation to third parties when it is not required to meet native load requirements (end-use customers within our public utility companies’ franchise service territory).  All other energy derivatives (excluding electric, coal, and gas purchase contracts for use in serving our native load requirements) are classified as trading.  Gas trading is comprised of transactions for which gas is physically delivered to a customer (physical gas trading), as well as transactions that are financial in nature for which delivery rarely occurs (financial gas trading).  Since Cinergy owns no gas production and has limited transmission capabilities, all gas transactions (other than

41

procurement and sale of gas to CG&E and ULH&P retail customers) are considered trading whether physical or financial.  Certain gas and coal contracts do not meet the definition of a derivative and therefore are not required to be classified as trading or non-trading. 

We account for most non-trading derivatives and all non-derivative energy contracts on the accrual basis of accounting (accrual contracts).  Non-trading derivatives are accounted for as accrual only if the contract qualifies for the normal purchases and sales scope exception in Statement 133.  We account for all trading derivatives using the fair value method of accounting.  Under the fair value method of accounting, unrealized trading derivatives are shown at fair value in our Balance Sheets as Energy risk management assets and Energy risk management liabilities.  All changes in fair value of such contracts are reflected as gains or losses in our Statements of Income.  In October 2002, the EITF reached a consensus in EITF 02-3 to rescind EITF Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10).  This decision required that non-derivative contracts previously accounted for at fair value be accounted for on an accrual basis in the future.  See (q)(i) below for further discussion.

In 2003, we began reflecting realized and unrealized gains and losses on trading derivatives on a net basis in Operating Revenues pursuant to the requirements of EITF 02-3, regardless of whether the transactions were settled physically.  Prior to 2003, the realized results for trading contracts that were physical in nature were presented as either (a) Operating Revenues,if sales contractsor (b) Fuel and purchased and exchanged power expense and Gas purchased expense, if purchase contracts.  The presentation for 2002, 2001, and 2000 has been reclassified to conform to the new presentation.  Non-trading derivatives, as well as substantially all energy marketing contracts that are not derivatives, are presented on a gross basis in Operating Revenues or Fuel and purchased and exchanged power expense.  See Note 20 for further discussion.

Although we intend to settle accrual contracts with company-owned assets, occasionally we settle these contracts with purchases on the open trading markets.  The cost of these purchases could be in excess of the associated revenues.  We recognize the gains or losses on these transactions as delivery occurs.  Due to the infrequency of such settlements, both historical and projected, and the fact that physical settlement to the customer still occurs, we continue to apply the normal purchases and sales exemption to such physical contracts that constitute derivatives.  Open market purchases may occur for the following reasons:

•generating station outages;

•least-cost alternative;

•native load requirements; and

•extreme weather.

We anticipate that some of the electricity obligations, even though considered trading contracts, will ultimately be settled using company-owned generation.  The cost of this generation is usually below the market price at which the trading portfolio has been valued.  The potential for earnings volatility from period to period is increased due to the risks associated with marketing and trading electricity, natural gas, and other energy-related products.

We value contracts in the trading portfolio using end-of-the-period fair values, utilizing the following factors (as applicable):

•closing exchange prices (that is, closing prices for standardized electricity and natural gas products traded on an organized exchange, such as the New York Mercantile Exchange);

•broker-dealer and over-the-counter price quotations; and

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•model pricing (which considers time value and historical volatility factors of electricity and natural gas).

(n)Business Combinations and Intangible Assets

We account for business combinations using the purchase method.  Goodwill and other intangibles with indefinite lives are no longer amortized.  Prior to January 1, 2002, we amortized goodwill on a straight-line basis over its estimated useful life, not to exceed 40 years.  The discontinuance of this amortization was not material to our financial position or results of operations.  Goodwill is assessed for impairment annually, or when circumstances indicate that the fair value of a reporting unit has declined significantly, by applying a fair-value-based test.  This test is applied at the “reporting unit” level, which is not broader than the current business segments discussed in Note 16.  Acquired intangible assets are separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of intent to do so.

(o)Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets.  If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for an impairment loss if the carrying value is greater than the fair value.  Until the assets are disposed of, their estimated fair value is reevaluated when circumstances or events change.

In 2002, Cinergy sold and/or classified as held for sale, certain non-core investments.  Pursuant to Statement of Financial Accounting Standards No. 144, Accounting for Impairment of Long-Lived Assets (Statement 144), these investments have been classified as Discontinued operations, net of tax in our financial statements.  See Note 15 for further information.

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(p)Stock-Based Compensation

We have historically accounted for our stock-based compensation plans using the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) (see Note 2 for further information on our stock-based compensation plans).  In July 2002, we announced that we would prospectively adopt the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (Statement 123), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure (Statement 148), for all employee awards granted or modified after January 1, 2003.  The following table illustrates the effect on our Net income and Earnings per share (EPS) if the fair value based method had been applied to all outstanding and unvested awards in each period.

		Year Ended December 31
		(dollars in millions, except per share amounts)
		2002		2001		2000
Net income, as reported		$	361	$	442	$	399
Add:	Stock-based employee compensation expense included in reported net income, net of related tax effects.	24		13		9
Deduct:	Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects.	23		13		9
Pro-forma net income		$	362	$	442	$	399
EPS - as reported		$	2.16	$	2.78	$	2.51
EPS - pro-forma		$	2.17	$	2.78	$	2.51
EPS assuming dilution - as reported		$	2.13	$	2.75	$	2.50
EPS assuming dilution - pro-forma		$	2.14	$	2.75	$	2.50

In estimating the pro-forma amounts, the fair value method of accounting was not applied to options granted prior to January 1, 1995.  This is in accordance with the provisions of Statement 123, as amended by Statement 148.  As a result, the pro-forma effect on Net Income and EPS may not be representative of future years.  In addition, the pro-forma amounts reflect certain assumptions used in estimating fair values.  These fair value assumptions are described in Note 2.

(q)Accounting Changes

(i)Energy Trading

The EITF has been discussing several issues related to the accounting and disclosure of energy trading activities under EITF 98-10.  In October 2002, the EITF reached consensus in EITF 02-3, to (a) rescind EITF 98-10, (b) generally preclude the recognition of gains at the inception of new derivatives, and (c) require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically.

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The consensus to rescind EITF 98-10 will require all energy trading contracts that do not qualify as derivatives to be accounted for on an accrual basis, rather than at fair value.  The consensus was immediately effective for all new contracts executed after October 25, 2002, and will require a cumulative effect adjustment to income, net of tax, on January 1, 2003, for all contracts executed on or prior to October 25, 2002.  The cumulative effect adjustment, on a net of tax basis, will be a loss of approximately $13 million, which includes primarily the impact of coal contracts accounted for at fair value, gas inventory accounted for at fair value, and certain gas contracts.  We expect the value of these items to be realized when the contracts settle.  The general restriction on recognition of inception gains is not expected to have a material impact on our future financial position or results of operations.

The consensus to require all gains and losses on energy trading derivatives to be presented net in the Statements of Income was effective beginning January 1, 2003, and requires reclassification for all periods presented.  This reclassification resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense.  However, Operating Income and Net Income were not affected by this change.  See Note 20 of the "Notes to Financial Statements" in "Item 8.  Financial Statements and Supplementary Data" for additional information on this change in accounting principle.

(ii)Business Combinations and Intangible Assets

In June 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (Statement 141), and No. 142, Goodwill and Other Intangible Assets (Statement 142).  Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method.  With the adoption of Statement 142, goodwill and other intangibles with indefinite lives will no longer be subject to amortization.  Statement 142 requires that goodwill be assessed for impairment upon adoption and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under prior accounting standards.  This test must be applied at the “reporting unit” level, which is not permitted to be broader than the current business segments discussed in Note 16.  Under Statement 142, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer’s intent to do so.

We began applying Statement 141 in the third quarter of 2001 and Statement 142 in the first quarter of 2002.  The discontinuance of amortization of goodwill, which began in the first quarter of 2002, was not material to our financial position or results of operations.  We finalized our transition impairment test in the fourth quarter of 2002 and have recognized a non-cash impairment charge of approximately $11 million (net of tax) for goodwill related to certain of

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our international assets.  This charge reflects a general decline in value of international assets.  Additionally, Cinergy’s combined heat and power plants located in the Czech Republic faced downward pressure in their selling prices for electricity due to the continued restructuring of the market in that country.  In calculating this impairment charge, the fair value of the reporting unit was determined through both discounted cash flow analysis and offers being considered on certain businesses within the reporting unit.  This amount is reflected in Cinergy’s Statements of Income as a Cumulative effect of a change in accounting principle.  While Statement 142 did not require the initial transition impairment test to be completed until December 31, 2002, it requires any transition impairment charge to be reflected as of January 1, 2002.  As such, Note 14 reconciles Net Income and EPS from the amounts originally presented in the first quarter of 2002 to the amounts revised for this change.  We will continue to perform goodwill impairment tests annually, as required by Statement 142, or when circumstances indicate that the fair value of a reporting unit has declined significantly.

(iii)Asset Retirement Obligations

In July 2001, the FASB issued Statement 143, which requires fair value recognition of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred.  The initial recognition of this liability will be accompanied by a corresponding increase in property, plant, and equipment.  Subsequent to the initial recognition, the liability will be adjusted for any revisions to the expected cash flows of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time (recognized as an operating expense).  Additional depreciation expense will be recorded prospectively for any property, plant, and equipment increases.  We adopted Statement 143 on January 1, 2003.  The impact of adoption on our results of operations will be reflected as a cumulative effect adjustment to income, net of tax.

We currently accrue costs of removal on many long-lived assets through depreciation expense if we believe removal of the assets at the end of their useful life is likely.  The SEC staff has interpreted Statement 143 to disallow the accrual of cost of removal when no obligation exists under Statement 143, even if removal of the asset is likely.  Any amounts currently recorded in Accumulated depreciation must be removed through the cumulative effect adjustment on January 1, 2003.  However, if accruing cost of removal is allowed for ratemaking purposes and Statement 71 is applicable, accumulated cost of removal will not be reversed upon adoption of Statement 143.  Rather, the amount of accrued cost of removal will remain, but will be disclosed in all future periods.  PSI, CG&E, except for its generation assets, and ULH&P expect to continue to accrue costs of removal under Statement 71.

We are finalizing our evaluation of the impact of adopting Statement 143.  However, we have not determined whether its impact will be material pending (a) resolution of certain legal conclusions and (b) final calculations on the amount of accumulated cost of removal to be reversed upon adoption for CG&E’s generation assets.

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(iv)Derivatives

During 1998, the FASB issued Statement 133.  This standard was effective for Cinergy beginning in 2001, and requires us to record derivative instruments, which are not exempt under certain provisions of Statement 133, as assets or liabilities, measured at fair value (i.e., mark-to-market).  Our financial statements reflect the adoption of Statement 133 in the first quarter of 2001.  Since many of our derivatives were previously required to use fair value accounting, the effects of implementation were not material.

Our adoption did not reflect the potential impact of applying fair value accounting to selected electricity options and capacity contracts.  We had not historically accounted for these instruments at fair value because they were intended as either hedges of peak period exposure or sales contracts served with physical generation, neither of which were considered trading activities.  At adoption, we classified these contracts as normal purchases or sales based on our interpretation of Statement 133 and in the absence of definitive guidance on such contracts.  In June 2001, the FASB staff issued guidance on the application of the normal purchases and sales exemption to electricity contracts containing characteristics of options.  While many of the criteria in this guidance are consistent with the existing guidance in Statement 133, some criteria were added.  We adopted the new guidance in the third quarter of 2001, and the effects of implementation for these contracts were not material to our financial position or results of operations.  We will continue to apply this guidance to any new electricity contracts that meet the definition of a derivative.

In December 2001, the FASB staff revised the current guidance to make the evaluation of whether electricity contracts qualify as normal purchases and sales more qualitative than quantitative.  This new guidance uses several factors to distinguish between capacity contracts, which qualify for the normal purchases and sales exemption, and options, which do not.  These factors include deal tenor, pricing structure, specification of the source of power, and various other factors.  We adopted this guidance in the third quarter of 2002, and its impact was not material to our financial position or results of operations.

In October 2001, the FASB staff released final guidance on the applicability of the normal purchases and sales exemption to contracts that contain a minimum quantity (a forward component) and flexibility to take additional quantity at a fixed price (an option component).  While this guidance was issued primarily to address optionality in fuel supply contracts, it applies to all derivatives (subject to certain exceptions for capacity contracts in electricity discussed in the previous paragraphs).  This guidance concludes that such contracts are not eligible for the normal purchases and sales exemption due to the existence of optionality in the contract.  We adopted this guidance in the second quarter of 2002, consistent with the transition provisions.  Cinergy has certain contracts that contain fixed-price optionality, primarily coal contracts, which we reviewed to determine the impact of this new guidance.  Due to a lack of liquidity with respect to coal markets in our region, we determined that our coal contracts do not meet the net settlement criteria of Statement 133 and thus do not qualify as derivatives.  Given these conclusions, the results of applying this new guidance were not material to our financial position or results of operations.

In May 2002, the FASB issued an exposure draft that would amend Statement 133 to incorporate certain implementation conclusions reached by the FASB staff.  We do not believe the

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amendments, as currently drafted, will have a material effect on our financial position or results of operations.

(v)Asset Impairment

In August 2001, the FASB issued Statement 144, which addresses accounting and reporting for the impairment or disposal of long-lived assets.  Statement 144 was effective beginning with the first quarter of 2002.  The impact of implementation on our financial position or results of operations was not material.

(vi)Exit Activities

In August 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities (Statement 146).  Statement 146 addresses accounting and reporting for the recognition of exit costs, including, but not limited to, one-time employee benefit terminations, contract cancellations, and facility consolidations.  This statement requires that such costs be recognized only when they meet the definition of a liability under GAAP.  However, Statement 146 applies only to exit activities initiated in 2003 and after.  All costs recorded through December 31, 2002, are unaffected by this pronouncement.  The impact of implementation on our financial position or results of operations is not expected to be material.

(vii)Accounting for Stock-Based Compensation

We have historically accounted for our stock-based compensation plans under APB 25.  In July 2002, Cinergy announced that it would adopt Statement 123 for all employee awards granted or modified after January 1, 2003, and would begin measuring the compensation cost of stock-based awards under the fair value method.  In December 2002, the FASB issued Statement 148, which amends Statement 123 and APB Opinion No. 28, Interim Financial Reporting.  Statement 148 provides alternative methods of transition to Statement 123 and more expanded disclosures about the method of accounting for stock-based employee compensation and the effect of the method used on reported results in both annual and interim financial statements.  Cinergy adopted Statement 148 on January 1, 2003, and has adopted the transition provisions that require expensing options prospectively in the year of adoption, consistent with the original pronouncement.  Existing awards will continue to follow the intrinsic value method prescribed by APB 25.  The impact of adoption on our financial position and results of operations, assuming award levels and fair values similar to past years, is not material.  This change will primarily impact the accounting for stock options and other performance based awards related to the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (LTIP) and Cinergy Corp. Employee Stock Purchase and Savings Plan.  See Note 2 for additional information.

(viii)Guarantees

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (Interpretation 45).  Interpretation 45 addresses accounting and reporting obligations under certain guarantees.  It requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.  The initial

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recognition and measurement provisions of Interpretation 45 are applicable to guarantees issued or modified after December 31, 2002.  However, the incremental disclosure requirements in Interpretation 45 are effective for this annual report.  The impact of implementation on our financial position or results of operations is not expected to be material.  For a further discussion of guarantees, see Note 11(b).

(ix)Consolidation of Special Purpose Entities

The FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities in January 2003.  This interpretation will significantly change the consolidation requirements for special purpose entities (SPE).  We have begun reviewing the impact of this interpretation but have not yet concluded whether consolidation of certain SPEs will be required.  There are two SPEs for which consolidation may be required.  These SPEs have individual power sale agreements to an unrelated third party for approximately 45 megawatts (MW), ending in 2009, and 35 MW, ending in 2016.  In addition, the SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading) to supply the power.   Capital & Trading also provides various services, including certain credit support facilities.

Cinergy’s quantifiable exposure to loss as a result of involvement with these two SPEs is $28 million, which includes investments in these entities of $3 million and exposure under the capped credit facilities of approximately $25 million.  There is also a non-capped facility, but it can only be called upon in the event the SPE breaches representations, violates covenants, or other unlikely events.

If appropriate, consolidation of all assets and liabilities of these two SPEs, at their carrying values, will be required in the third quarter of 2003.  Approximately $225 million of non-recourse debt would be included in Cinergy’s Balance Sheets upon initial consolidation.  However, the impact on results of operations would be expected to be immaterial.

Cinergy believes that its accounts receivable sale facility, as discussed in Note 6, would remain unconsolidated since it involves transfers of financial assets to a qualifying SPE, which is exempted from consolidation by Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (Statement 140) and this interpretation.

(r)Translation of Foreign Currency

We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally, the local currency of the country in which the subsidiary is located) is not the United States (U.S.) dollar, using the appropriate exchange rate as of the end of the year.  We translate income and expense items using the average exchange rate prevailing during the month the respective transaction occurs.  We record translation gains and losses in Accumulated other comprehensive income (loss), which is a component of common stock equity.  When a foreign subsidiary is sold, the cumulative translation gain or loss as of the date of sale is removed from Accumulated other comprehensive income (loss) and is recognized as a component of the gain or loss on the sale of the subsidiary in our Statements of Income.

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(s)Related Party Transactions

Cinergy and its subsidiaries engage in related party transactions.  These transactions, which are eliminated upon consolidation, are generally performed at cost and in accordance with the SEC regulations under the PUHCA and the applicable state and federal commission regulations.  The Balance Sheets of our operating companies reflect amounts payable to and/or receivable from related parties as Accounts payable to affiliated companies and Accounts receivable from affiliated companies.  The significant related party transactions are disclosed below.

(i)Services

Services provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services in accordance with agreements approved by the SEC under the PUHCA.  The cost of these services are charged to our operating companies on a direct basis, or for general costs which cannot be directly attributed, based on predetermined allocation factors, including the following ratios:

•sales;

•electric peak load;

•number of employees;

•number of customers;

•construction expenditures; and

•other statistical information.

These costs were as follows for the years ended December 31, 2002, 2001, and 2000:

	2002		2001		2000
	(in millions)
Cinergy(1)	$	472	$	483	$	479
CG&E and subsidiaries	206		240		250
PSI	190		196		187
ULH&P	23		24		25

(1) The results of Cinergy also include amounts related to non-registrants.

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Generation Services, which began operations on January 1, 2001, supplies electric production-related construction, operation and maintenance services to certain of our subsidiaries pursuant to agreements approved by the SEC under the PUHCA.  The cost of these services were as follows for the years ended December 31, 2002 and 2001:

	2002(2)		2001
	(in millions)
Cinergy(1)	$	179	$	92
CG&E	104		67
PSI	58		21

(1)	The results of Cinergy also include amounts related to non-registrants.
(2)	Increase reflects movement of Services’ employees to Generation Services.

(ii)Purchased Energy

ULH&P purchases energy from CG&E pursuant to a new contract effective January 1, 2002, which was approved by the FERC and the Kentucky Public Service Commission (KPSC).  This five-year agreement is a negotiated fixed-rate contract with CG&E and replaces the previous cost-of-service based contract, which expired on December 31, 2001.  ULH&P purchased energy from CG&E for resale in the amounts of $160 million, $152 million, and $160 million for the years ended 2002, 2001, and 2000, respectively.  These amounts are reflected in the Statements of Income for ULH&P as Electricity purchased from parent company for resale.

PSI and CG&E purchase energy from each other under various federal and state approved joint operating agreements.  These sales and purchases are reflected in the Statements of Income of PSI and CG&E as Electric operating revenues and Fuel and purchased and exchanged power expense and were as follows for the years ended December 31, 2002, 2001, and 2000:

	2002		2001		2000
	(in millions)
CG&E
Electric operating revenues	$	59	$	90	$	111
Fuel and purchased and exchanged power (1)	19		39		34
PSI
Electric operating revenues	43		92		94
Fuel and purchased and exchanged power (1)	9		33		48

(1) Does not include intercompany purchases that are presented net in accordance with EITF 02-3 and therefore are no longer reflected as purchased power.  See Note 20 for further information. 

To supplement native load requirements for 2002, CG&E and PSI agreed to purchase peaking power from Capital & Trading, an indirect wholly-owned subsidiary of Cinergy Corp., pursuant to the terms of a wholesale market-based tariff.  For the year ended December 31, 2002, payments under these contracts totaled approximately $27 million for CG&E and $28 million for PSI.  To the extent these payments were deferred for future recovery, the amounts are included in Regulatory assets on the Balance Sheets of CG&E and PSI.  The remaining

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payments are reflected as Fuel and purchased and exchanged power expense on the Statements of Income for CG&E and PSI.

CG&E and PSI have an agreement with Marketing & Trading to purchase gas for certain gas-fired peaking plants pursuant to the terms of the wholesale market-based agreements.  CG&E purchased natural gas from Marketing & Trading in the amount of $9 million and $12 million for the years ended December 31, 2002 and 2001, respectively.  PSI purchased natural gas from Marketing & Trading in the amount of $5 million and $4 million for the years ended December 31, 2002 and 2001, respectively.  The amounts are reflected in the Statements of Income of CG&E and PSI as Fuel and purchased and exchanged power expense.

(iii)Other

In December 2001, CG&E and ULH&P entered into agreements with Mirant Americas Energy Marketing, LP (Mirant) in which CG&E and ULH&P assigned Mirant the rights to CG&E’s and ULH&P’s gas supply contracts, interstate pipeline transportation contracts and gas in storage, and Mirant agreed to deliver gas to meet CG&E’s and ULH&P’s firm gas requirements, and to pay CG&E and ULH&P monthly fees.  Mirant assigned these contracts and the agreements to Marketing & Trading in November 2002, and CG&E and ULH&P consented to such assignments.  The agreements will expire in October 2003.  Payments under these agreements were approximately $33 million and $7 million for CG&E and ULH&P, respectively.  These amounts are recorded in the Statements of Income for CG&E and ULH&P as Gas purchased expense.  The assignment of the Mirant/ULH&P agreements are subject to the approval of the KPSC, and ULH&P has filed an application with the KPSC seeking such approval.  No other regulatory approvals are required.

Cinergy Corp. and our operating companies participate in a money pool arrangement by which those companies with surplus cash provide short-term loans to others.   For a further discussion on the money pool agreement see Note 5.

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2.Common Stock

(a)Changes In Common Stock Outstanding

The following table reflects information related to shares of common stock issued for stock-based plans.

	Shares
	Authorized for		Shares Used to Grant or
	Issuance under		Settle Awards
	Plan		2002	2001	2000
LTIP	14,500,000		674,005	72,225	93,855
Cinergy Corp. Stock Option Plan (SOP)	5,000,000		870,867	263,070	108,941
Cinergy Corp. Employee Stock Purchase and Savings Plan	2,000,000		4,912	227,847	2,718
Cinergy Corp. UK Sharesave Scheme	75,000		8,878	121	—
Cinergy Corp. Retirement Plan for Directors	175,000	(1)	1,768	29,135	9,435
Cinergy Corp. Directors’ Equity Compensation Plan	75,000		196	1,858	150
Cinergy Corp. Directors’ Deferred Compensation Plan	200,000		—	14,211	—
Cinergy Corp. 401(k) Plans	6,469,373	(1)	964,615	69,500	—
Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan (2)	3,000,000	(1)	657,943	649,834	533,932
Cinergy Corp. 401(k) Excess Plan	100,000	(1)	—	—	—
Director, Officer, and Key Employee Stock Purchase Program	2,110,817	(3)	—	—	1,627,788
Cinergy Corp. Long-Term Incentive Compensation Sub-Scheme	7,000,000		—	—	—

(1)Plan does not contain an authorization limit.  The number of shares presented reflects amounts registered with the SEC as of December 31, 2002.

(2)Shares issued prior to April 2001 were for the previous Cinergy Corp. Dividend Reinvestment and Stock Purchase Plan, which is no longer active.

(3)Plan authorized a maximum amount of $50 million of Cinergy Corp. common stock to be purchased.  The number of shares presented reflects amounts registered with the SEC as of December 31, 2002.  See Note 2(d) for additional information.

We retired 422,908 shares of common stock in 2002, 72,739 shares in 2001, and 32,988 shares in 2000, mainly representing shares tendered as payment for the exercise of previously granted stock options.

In April 2001, Cinergy adopted the Direct Stock Purchase and Dividend Reinvestment Plan, a plan designed to provide investors with a convenient method to purchase shares of Cinergy Corp. common stock and to reinvest cash dividends in the purchase of additional shares.  This plan replaced the Dividend Reinvestment and Stock Purchase Plan.

In November 2001, Cinergy chose to reinstitute the practice of issuing new Cinergy Corp. common shares to satisfy obligations under its various employee stock plans and the Cinergy

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Corp. Direct Stock Purchase and Dividend Reinvestment Plan.  This replaces our previous practice of purchasing shares in the open market to fulfill certain plan obligations.

In January 2002, Cinergy registered 100,000 shares of common stock under the Cinergy Corp. 401(k) Excess Plan.

In February 2002, Cinergy sold 6.5 million shares of Cinergy Corp. common stock with net proceeds of approximately $200 million.

Cinergy Corp. owns all of the common stock of CG&E and PSI.  All of ULH&P’s common stock is held by CG&E.

(b)           Dividend Restrictions

Cinergy Corp.’s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. common stock dividends.  Cinergy Corp., CG&E, and PSI cannot pay dividends on their common stock if their respective preferred stock dividends or preferred trust dividends are in arrears.  The amount of common stock dividends that each company can pay is also limited by certain capitalization and earnings requirements under CG&E’s and PSI’s credit instruments.  Currently, these requirements do not impact the ability of either company to pay dividends on its common stock.

(c)           Stock-based Compensation Plans

We currently have the following stock-based compensation plans:

•LTIP;

•SOP;

•Employee Stock Purchase and Savings Plan;

•UK Sharesave Scheme;

•Retirement Plan for Directors;

•Directors’ Equity Compensation Plan;

•Directors’ Deferred Compensation Plan;

•401(k) Excess Plan; and

•2001 Long-Term Incentive Compensation Sub-Scheme.

The LTIP, the SOP, and the Employee Stock Purchase and Savings Plan are discussed below.  The activity in 2002, 2001, and 2000 for the remaining stock-based compensation plans was not significant.

We have historically accounted for our stock-based compensation plans in accordance with APB 25.  However, we will prospectively adopt the fair value recognition provisions of Statement 123, as amended by Statement 148, effective with all employee awards granted or modified after January 1, 2003.  See “Stock-Based Compensation” in Note 1(p) for additional information on costs we recognized in 2002, 2001, and 2000, related to stock-based compensation plans, and for our pro-forma disclosure assuming compensation costs for these plans had been determined at fair value, consistent with Statement 123, as amended by Statement 148.

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(i)LTIP

The LTIP was originally adopted in 1996 and was subsequently amended effective January 2002.  Under this plan, certain key employees may be granted incentive and non-qualified stock options, stock appreciation rights (SAR), restricted stock, dividend equivalents, the opportunity to earn performance-based shares and certain other stock-based awards.  Stock options are granted to participants with an option price equal to or greater than the fair market value on the grant date, and generally with a vesting period of either three or five years.  The vesting period begins on the grant date and all options expire within 10 years from that date.  The number of shares of common stock issuable under the LTIP is limited to a total of 14.5 million shares.

Entitlement to performance-based shares is based on Cinergy’s total shareholder return (TSR) over designated Cycles as measured against a pre-defined peer group.  Target grants of performance-based shares were made for the following Cycles:

Cycle	Grant Date	Performance Period	Target Grant of Shares
			(in thousands)
V	1/2001	2001-2003	301
VI	1/2002	2002-2004	343
VII	1/2003	2003-2005	371

Participants may earn additional performance shares if Cinergy’s TSR exceeds that of the peer group.  For the three-year performance period ended December 31, 2002 (Cycle IV), approximately 817,000 shares were earned, based on our relative TSR.

(ii)SOP

The SOP is designed to align executive compensation with shareholder interests.  Under the SOP, incentive and non-qualified stock options, SARs, and SARs in tandem with stock options may be granted to key employees, officers, and outside directors.  The activity under this plan has predominantly consisted of the issuance of stock options.  Options are granted with an option price equal to the fair market value of the shares on the grant date.  Options generally vest over five years at a rate of 20 percent per year, beginning on the grant date, and expire 10 years from the grant date.  The total number of shares of common stock issuable under the SOP may not exceed 5,000,000 shares.  No stock options may be granted under the plan after October 24, 2004.

(iii)Employee Stock Purchase and Savings Plan

The Employee Stock Purchase and Savings Plan allows essentially all full-time, regular employees to purchase shares of common stock pursuant to a stock option feature.  Under the Employee Stock Purchase and Savings Plan, after-tax funds are withheld from a participant’s compensation during a 26-month offering period and are deposited in an interest-bearing account.  At the end of the offering period, participants may apply amounts deposited in the account, plus interest, toward the purchase of shares of common stock.  The purchase price is equal to 95 percent of the fair market value of a share of common stock on the first date of the

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offering period.  Any funds not applied toward the purchase of shares are returned to the participant.  A participant may elect to terminate participation in the plan at any time.  Participation also will terminate if the participant’s employment ceases.  Upon termination of participation, all funds, including interest, are returned to the participant without penalty.  The sixth (current) offering period began May 1, 2001, and ends June 30, 2003.  The purchase price for all shares under this offering is $32.78.  The fifth offering period ended April 30, 2001, with 227,968 shares purchased and the remaining cash distributed to the respective participants.  The total number of shares of common stock issuable under the Employee Stock Purchase and Savings Plan may not exceed 2,000,000.

Activity for 2002, 2001, and 2000 for the LTIP, SOP, and Employee Stock Purchase and Savings Plan is summarized as follows:

	LTIP and SOP				Employee Stock Purchase and Savings Plan
	Shares Subject to Option		Weighted Average Exercise Price		Shares Subject to Option		Weighted Average Exercise Price
Balance at December 31, 1999	6,187,249		$	27.17	359,305		$	27.73
Options granted	1,329,800		24.59		—		—
Options exercised	(123,978	)	23.50		(2,718	)	27.73
Options forfeited	(402,200	)	26.68		(76,261	)	27.73
Balance at December 31, 2000	6,990,871		26.77		280,326		27.73
Options granted	811,700		33.90		299,793		32.78
Options exercised	(275,393	)	24.39		(227,968	)	27.73
Options forfeited	(79,400	)	27.29		(73,826	)	29.20
Balance at December 31, 2001	7,447,778		27.63		278,325		32.78
Options granted	1,241,200	(2)	32.27		—		—
Options exercised	(1,308,738	)	23.96		(4,912	)	32.78
Options forfeited	(18,540	)	31.57		(55,243	)	32.78
Balance at December 31, 2002	7,361,700		$	29.06	218,170		$	32.78
Options Exercisable(1):
At December 31, 2000	3,195,191		$	26.20
At December 31, 2001	3,763,558		$	27.32
At December 31, 2002	3,744,420		$	28.98

(1)The options under the Employee Stock Purchase and Savings Plan are only exercisable at the end of the offering period.

(2)Options were not granted under the SOP during 2002.

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The weighted average fair value of options granted under the combined LTIP and the SOP plans was $4.95 in 2002, $5.42 in 2001, and $2.75 in 2000.  The weighted average fair value of options granted under the Employee Stock Purchase and Savings Plan was $5.85 in 2001 (no options were granted in 2002 or 2000).  The fair values of options granted were estimated as of the grant date using the Black-Scholes option-pricing model and the following assumptions:

	LTIP and SOP(1)						Employee Stock Purchase and Savings Plan(2)
	2002		2001		2000		2001
Risk-free interest rate	3.92	%	4.78	%	6.57	%	4.22%
Expected dividend yield	5.66	%	5.42	%	7.32	%	5.26%
Expected lives	5.42	yrs.	5.37	yrs.	4.86	yrs.	2.17 yrs.
Expected volatility	26.45	%	25.01	%	20.18	%	30.67%

(1)	Options were not granted under the SOP in 2002.
(2)	Options were not granted under the Employee Stock Purchase and Savings Plan in 2002 or 2000.

Price ranges, along with certain other information, for options outstanding under the combined LTIP and SOP plans at December 31, 2002, were as follows:

					Outstanding				Exercisable
Exercise Price Range					Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Number of Shares	Weighted Average Exercise Price
$	22.88	-	$	23.81	2,100,970	$	23.69	6.33 yrs.	1,433,890	$	23.64
$	23.88	-	$	32.65	2,492,830	$	26.82	6.70 yrs.	768,330	$	25.63
$	33.31	-	$	38.59	2,767,900	$	35.15	6.69 yrs.	1,542,200	$	35.62

(d)           Director, Officer, and Key Employee Stock Purchase Program

In December 1999, Cinergy Corp. adopted the Director, Officer, and Key Employee Stock Purchase Program (Stock Purchase Program).  The purpose of the Stock Purchase Program is to facilitate the purchase and ownership of Cinergy Corp.’s common stock by its directors, officers, and key employees, thereby further aligning their interests with those of its shareholders.

In February 2000, Cinergy Corp. purchased approximately 1.6 million shares of common stock on behalf of the participants at an average price of $24.82 per share.

Participants had the option of financing the purchases through a five-year credit facility arranged by Cinergy Corp. with a bank.  Each participant is obligated to repay the bank any loan principal, interest, and prepayment fees, and each has assigned his or her dividend rights on the purchased shares to the bank to be applied to interest payments as due on the loan.

Services, and in part, Cinergy Corp., have guaranteed repayment to the bank of 100 percent of each participant’s loan obligations and the associated interest, and each participant has agreed to indemnify the guarantor for any payments made by it under the guaranty on the participant’s

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behalf.  A participant’s obligations to the bank are unsecured and no restrictions are placed on the participant’s ability to sell, pledge, or otherwise encumber or dispose of his or her purchased shares.

(e)Stock Purchase Contracts

In December 2001, Cinergy Corp. issued approximately $316 million notional amount of combined securities, a component of which was stock purchase contracts.  These contracts obligate the holder to purchase common shares of Cinergy Corp. stock in, and/or before, February 2005.  The number of shares to be issued is contingent upon the market price of Cinergy Corp. stock, but subject to predetermined ceiling and floor prices.  See Note 3 for further discussion of these combined securities.

3.Preferred Trust Securities

In December 2001, Cinergy Corp. issued approximately $316 million notional amount of combined securities consisting of (a) 6.9 percent preferred trust securities, due February 2007, and (b) stock purchase contracts obligating the holders to purchase between 9.2 and 10.8 million shares of Cinergy Corp. common stock in, and/or before, February 2005.  A $50 preferred trust security and stock purchase contract were sold together as a single security unit (Unit).  The proceeds of $306 million, which is net of approximately $10 million of issuance costs, were used to pay down Cinergy Corp.’s short-term indebtedness.  In February 2005, the preferred trust securities will be remarketed and the dividend rate reset, no lower than 6.9 percent, to yield $316 million in the remarketing.  The holders will use the proceeds from this remarketing to fund their obligation to purchase shares of Cinergy Corp. common stock under the stock purchase contract.  The holders will pay the market price for the stock at that time, subject to a ceiling of $34.40 per share and a floor of $29.15 per share.  The number of shares to be issued will vary according to the stock price, subject to the total proceeds equaling $316 million.  These preferred trust securities were issued through a wholly-owned trust of Cinergy Corp. and are recorded on Cinergy Corp.’s Balance Sheets, net of discount and expense, as Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company.  The fair value of the stock purchase contracts was charged to Paid-in capital with a corresponding credit to Non-Current Liabilities-Other.

Each Unit will receive quarterly cash payments of 9.5 percent per annum of the notional amount, which includes the preferred trust security dividend of 6.9 percent and payment of 2.6 percent, which represents principal and interest on the stock purchase contracts.  Upon delivery of the shares, these stock purchase contract payments will cease.

4.Long-Term Debt

Refer to the Statements of Capitalization for detailed information for Cinergy’s, CG&E’s, PSI’s, and ULH&P’s long-term debt.

In January 2002, PSI repaid at maturity $23 million principal amount of its Medium-Term Notes, Series A.  The securities were not replaced by new issues of long-term debt.

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In May 2002, an indirect, wholly-owned subsidiary of Global Resources entered into a senior term loan and a junior term loan, borrowing $13.8 million and $7.1 million, respectively.  Each of the loans have periodic principal reduction payments, with the senior loan having a final maturity of March 15, 2019, and the junior loan having a final maturity of March 15, 2012.  The annual interest rate on the senior loan is fixed at 6.97 percent and the junior loan is fixed at 6.35 percent.

On September 1, 2002, CG&E repaid at maturity $100 million principal amount of its First Mortgage Bonds, 7 ¼% Series.

On September 10, 2002, CG&E borrowed the proceeds from the issuance by the Ohio Air Quality Development Authority of $84 million principal amount of its State of Ohio Air Quality Development Revenue Refunding Bonds 2002 Series A, due September 1, 2037.  The issuance consists of two $42 million tranches, with the interest rate on one tranche being reset every 35 days by auction and the interest rate on the other tranche being reset every 7 days by auction.  The initial interest rates for the 35-day and 7-day tranches were 1.40 percent and 1.35 percent, respectively.  Proceeds from the borrowing were used on October 7, 2002 to redeem, at par, two $42 million Series 1985 A&B Air Quality Development Authority State of Ohio Customized Purchase Revenue Bonds, due December 1, 2015.  The redeemed bonds had been classified in Notes payable and other short-term obligations.

On September 12, 2002, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $23 million principal amount of its Environmental Refunding Revenue Bonds Series 2002A, due March 1, 2031.  The initial interest rate for the bonds was 1.40 percent.  The interest rate resets every 35 days by auction.  Proceeds from the borrowing were used on October 1, 2002 to redeem, at par, the $23 million principal amount of Indiana Development Finance Authority Environmental Refunding Revenue Bonds Series 1998, due August 1, 2028.  The redeemed bonds had been classified in Notes payable and other short-term obligations.

On September 12, 2002, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $24.6 million principal amount of its Environmental Refunding Revenue Bonds Series 2002B, due March 1, 2019.  The initial interest rate for the bonds was 1.35 percent.  The interest rate resets every 7 days by auction.  Proceeds from the issuance were used on October 1, 2002 to redeem, at par, the $24.6 million principal amount of City of Princeton, Indiana Pollution Control Revenue Refunding Bonds 1996 Series, due March 1, 2019.  The redeemed bonds had been classified in Notes payable and other short-term obligations.

The holders of the newly issued Ohio Air Quality Development Authority and Indiana Development Finance Authority bonds mentioned above have the benefit of a financial guaranty insurance policy that insures the payment of principal of, and interest on, the bonds when due.  CG&E and PSI have each entered into an insurance agreement with the bond insurer and have pledged first mortgage bonds to secure their respective reimbursement obligations under such agreements.

On September 23, 2002, CG&E issued $500 million principal amount of its 5.70 percent Debentures due September 15, 2012.  Proceeds from the offering were used to repay short-term

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indebtedness incurred in connection with general corporate purposes including capital expenditures related to environmental compliance construction, and the repayment at maturity of $100 million principal amount of CG&E’s First Mortgage Bonds, 7 ¼% Series.  In July 2002, CG&E executed a treasury lock with a notional amount of $250 million, which was designated as a cash flow hedge of 50 percent of the forecasted interest payments on this debt offering.  With the issuance of the debt, the treasury lock was settled.  See Note 8(a) for additional information on this treasury lock.

The following table reflects the long-term debt maturities excluding any redemptions due to the exercise of call provisions or capital lease obligations.  Callable means the issuer has the right to buy back a given security from the holder at a specified price before maturity.  Putable means the holder has the right to sell a given security back to the issuer at a specified price before maturity.

Long-term Debt Maturities

	Cinergy(1)		CG&E and subsidiaries			PSI
			(in millions)
2003	$	191	$	120	(2)	$	56
2004	815		110			2
2005(3)	204		150			51
2006	335		—			328
2007	374		100			267
Thereafter	2,351		1,212		(4)	676
	$	4,270	$	1,692		$	1,380

(1)	The results of Cinergy also include amounts related to non-registrants.
(2)	Includes $100 million of CG&E’s long-term debt with a periodic put provision beginning in June 2003, and ULH&P’s $20 million maturing in 2003.
(3)	CG&E and subsidiaries includes long-term debt with put provisions of $150 million in 2005.  PSI includes long-term debt with put provisions of $50 million in 2005.
(4)	Includes ULH&P’s $55 million of long-term debt.

Maintenance and replacement fund provisions contained in PSI’s first mortgage bond indenture require:  (1) cash payments, (2) bond retirements, or (3) pledges of unfunded property additions each year based on an amount related to PSI’s net revenues.

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5.Notes Payable and Other Short-term Obligations

Short-term obligations may include:

•short-term notes;

•commercial paper;

•variable rate pollution control notes; and

•money pool.

Short-term Notes

Short-term borrowings mature within one year from the date of issuance.  We primarily use unsecured revolving lines of credit and the sale of commercial paper for short-term borrowings.  A portion of each company’s revolving lines is used to provide credit support for commercial paper.  When revolving lines are reserved for commercial paper or backing letters of credit, they are not available for additional borrowings.  The fees we paid to secure short-term borrowings were immaterial during each of the years ended December 31, 2002, 2001, and 2000.

At December 31, 2002, Cinergy Corp. had $494 million remaining unused and available capacity relating to its $1 billion revolving credit facilities.  These revolving credit facilities include the following:

Credit Facility	Expiration	Established Lines		Outstanding and Committed		Unused and Available
				(in millions)
364-day senior revolving	April 2003
Direct borrowing		$		$	—	$
Commercial Paper support				473
Total 364-day facility		600		473		127
Three-year senior revolving	May 2004
Direct borrowing				25
Commercial Paper support				—
Letter of Credit support				8
Total Three-year facility		400		33		367
Total Credit Facilities		$	1,000	$	506	$	494

In addition to revolving credit facilities, Cinergy Corp., CG&E, and PSI also maintain uncommitted lines of credit.  These facilities are not guaranteed sources of capital and represent an informal agreement to lend money, subject to availability, with pricing to be determined at the time of advance.  Cinergy Corp., CG&E, and PSI have established uncommitted lines of $65 million, $15 million, and $60 million, respectively, all of which remained unused as of December 31, 2002.

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Commercial Paper

Cinergy Corp.’s $800 million commercial paper program is supported by Cinergy Corp.’s $1 billion revolving credit facilities.  The commercial paper program at the Cinergy Corp. level supports, in part, the short-term borrowing needs of CG&E and PSI and eliminates their need for separate commercial paper programs.  As of December 31, 2002, Cinergy Corp. had $473 million in commercial paper outstanding.

Variable Rate Pollution Control Notes

CG&E and PSI have issued certain variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes).  Because the holders of these notes have the right to have their notes redeemed on a daily, monthly, or annual basis, they are reflected in Notes payable and other short-term obligations on the Balance Sheets of Cinergy, CG&E, and PSI.

In October 2002, CG&E and PSI caused the redemption of certain series’ of variable rate pollution control notes with a principal amount of $84 million and $47.6 million, respectively.  Holders of the notes had the option of having their notes redeemed at various times ranging from any business day to annually.  The notes were redeemed with proceeds from the issuance of new series’ of variable rate pollution control notes that do not have the redemption features mentioned above, and are therefore classified as Long-term debt obligations.  See Note 4 for further discussion of this redemption.

Money Pool

Cinergy Corp., Services, and our operating companies participate in a money pool arrangement to better manage cash and working capital requirements.  Under this arrangement, those companies with surplus short-term funds provide short-term loans to affiliates (other than Cinergy Corp.) participating under this arrangement.  This surplus cash may be from internal or external sources.  The amounts outstanding under this money pool arrangement are shown as a component of Notes receivable from affiliated companies and/or Notes payable to affiliated companies on the Balance Sheets of CG&E, PSI, and ULH&P.  Any money pool borrowings outstanding reduce the unused and available short-term debt regulatory authority of CG&E, PSI, and ULH&P.

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The following table summarizes our Notes payable and other short-term obligations, and Notes payable to affiliated companies.

	December 31, 2002						December 31, 2001
	Established Lines		Outstanding		Weighted Average Rate		Established Lines			Outstanding			Weighted Average Rate
	(in millions)
Cinergy
Cinergy Corp.
Revolving lines	$	1,000	$	25	2.02	%		$	1,175		$	599		2.55	%
Uncommitted lines(1)	65		—		—			40			—			—
Commercial paper(2)	800		473		1.81			800			125			3.49
Operating companies
Uncommitted lines(1)	75		—		—			75			66			3.73
Pollution control notes			147		1.82						279			2.10
Non-regulated subsidiaries
Revolving lines	7		1		3.28			46			32			2.94
Short-term debt	22		22		2.93			49			44			4.81
Cinergy Total			$	668	1.86	%					$	1,145		2.71	%
CG&E and subsidiaries
Uncommitted lines(1)	$	15	$	—	—	%		$	15		$	—		—	%
Pollution control notes			112		1.87						196			2.00
Money Pool			9		1.29						445			2.73
CG&E Total			$	121							$	641
PSI
Uncommitted lines(1)	$	60	$	—	—	%		$	60		$	66		3.73	%
Pollution control notes			35		1.65						83			2.33
Money Pool			138		1.29						422			2.58
PSI Total			$	173							$	571
ULH&P
Money Pool			$	14	1.29	%					$	26		2.73	%
ULH&P Total			$	14							$	26

(1)	Outstanding amounts may be greater than established lines as uncommitted lenders are, at times, willing to loan funds in excess of the established lines.
(2)	The commercial paper program is supported by Cinergy Corp.’s revolving lines.

In our credit facilities, Cinergy Corp. has covenanted to maintain:

•a consolidated net worth of $2 billion; and

•a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.

A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness.  In addition to breaches of covenants, certain other

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events that could result in the termination of available credit and acceleration of the related indebtedness include:

•bankruptcy;

•defaults in the payment of other indebtedness; and

•judgments against the company that are not paid or insured.

The latter two events, however, are subject to dollar-based materiality thresholds.

6.Sales of Accounts Receivable

During 2001, CG&E, PSI, and ULH&P had an agreement to sell, on a revolving basis, undivided percentage interests in certain of their accounts receivable and the related collections up to an aggregate maximum of $350 million.  CG&E retained servicing responsibilities for its role as a collection agent of the amounts due on the sold receivables.  However, the purchaser assumed the risk of collection on the sold receivables without recourse to CG&E, PSI, and ULH&P in the event of a loss.  Proceeds from a portion of the sold receivables were held back as a reserve to reduce the purchaser’s credit risk.  CG&E, PSI, and ULH&P did not retain any ownership interest in the sold receivables, but did retain undivided interests in their remaining balances of accounts receivable.  The recorded amounts of the retained interests were measured at net realizable value.  The Accounts receivable on the Balance Sheets of Cinergy, CG&E, PSI, and ULH&P were net of the amounts sold at December 31, 2001.

In February 2002, CG&E, PSI, and ULH&P replaced their previous agreement to sell certain of their accounts receivable and related collections.  Cinergy Corp. formed Cinergy Receivables Company, LLC (Cinergy Receivables) to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections of CG&E, PSI, and ULH&P.  Cinergy Corp. does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying SPE.  The sales of receivables are accounted for under Statement 140.

The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25 percent of the total proceeds).  The note is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions.  Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables.  However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time.  As such, these senior loans do not have recourse to all assets of Cinergy Receivables.  These loans provide the cash portion of the proceeds paid to CG&E, PSI, and ULH&P.

This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under Statement 140 and is classified within Notes receivable from affiliated companies in the accompanying Balance Sheets of CG&E, PSI, and ULH&P and is classified within Notes receivable on Cinergy Corp.’s Balance Sheets.  In addition, Cinergy Corp.’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the

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retained interests held by CG&E, PSI, and ULH&P.  The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value.  The key assumptions in estimating fair value are credit losses and selection of discount rates.  Because (a) the receivables generally turn in less than two months, (b) credit losses are reasonably predictable due to each company’s broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated basis of the subordinated notes are not materially different than their face value.  Interest accrues to CG&E, PSI, and ULH&P on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent.  Cinergy Corp. records income from Cinergy Receivables in a similar manner.  We record an impairment charge against the carrying value of both the retained interests and purchased beneficial interest whenever we determine that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).

The key assumptions used in measuring the retained interests for sales since the inception of the new agreement are as follows (all amounts are averages of the assumptions used in each sale during the period):

	Cinergy		CG&E and subsidiaries		PSI		ULH&P
Anticipated credit loss rate	0.6	%	0.6	%	0.5	%	1.0	%
Discount rate on expected cash flows	5.0	%	5.0	%	5.0	%	5.0	%
Receivables turnover rate(1)	12.9	%	13.7	%	11.8	%	13.5	%

(1) Receivables at each month-end divided by annualized sales for the month.

The hypothetical effect on the fair value of the retained interests assuming both a 10 percent and 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.

CG&E retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables.  However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to CG&E, PSI, and ULH&P in the event of a loss.  While no direct recourse to CG&E, PSI, and ULH&P exists, these entities risk loss in the event collections are not sufficient to allow for full recovery of their retained interests.  No servicing asset or liability is recorded since the servicing fee paid to CG&E approximates a market rate.

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The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales during the period, and cash flows during the period as of December 31, 2002.

	Cinergy		CG&E and subsidiaries		PSI		ULH&P
	(dollars in millions)
Receivables sold as of period end	$	483	$	299	$	184	$	45
Less:  Retained interests	135		81		54		13
Net receivables sold as of period end	$	348	$	218	$	130	$	32
Purchased beneficial interests	$	10	$	—	$	—	$	—
Sales during period
Receivables sold	$	3,233	$	1,840	$	1,392	$	287
Loss recognized on sale	32		19		13		3
Cash flows during period
Cash proceeds from sold receivables	$	3,184	$	1,813	$	1,371	$	283
Collection fees received	2		1		1		—
Return received on retained interests	16		9		7		1

A decline in the long-term senior unsecured credit ratings of CG&E, PSI, or ULH&P below investment grade would result in a termination of the sale program and discontinuance of future sales of receivables, and could prevent Cinergy Receivables from borrowing additional funds from commercial paper conduits.

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7.Leases

(a)Operating Leases

We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space.  Total rental payments on operating leases for each of the past three years are detailed in the table below.  This table also shows future minimum lease payments required for operating leases with remaining non-cancelable lease terms in excess of one year as of December 31, 2002:

	Actual Payments						Estimated Minimum Payments
	2000		2001		2002		2003		2004		2005		2006		2007		After 2007		Total
	(in millions)
Cinergy(1)	$	56	$	61	$	64	$	43	$	33	$	26	$	22	$	18	$	52	$	194
CG&E and subsidiaries	30		33		30		9		7		7		6		5		12		46
PSI	21		21		23		10		8		7		7		6		19		57
ULH&P(2)	4		5		4		—		—		—		—		—		—		—

(1)	The results of Cinergy also include amounts related to non-registrants.
(2)	Estimated minimum lease payments are immaterial.

(b)Capital Leases

In each of the years 1999 through 2002, CG&E, PSI, and ULH&P entered into capital lease agreements to fund the purchase of gas and electric meters.  The lease terms are for 120 months commencing with the date of purchase and contain various buyout options ranging from 48 to 105 months.  It is our objective to own the meters indefinitely and the operating companies plan to exercise the buyout option at month 105.  The effective lease rates given the early buyout option at 105 months are 6.71 percent for the 1999 leases, 6.09 percent for the 2000 leases, 6.00 percent for the 2001 leases, and 4.48 percent for the 2002 leases.  The meters are depreciated at the same rate as if owned by the operating companies.  CG&E, PSI, and ULH&P each recorded a capital lease obligation, included in Non-Current Liabilities-Other.

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The total minimum lease payments and the present values for these capital lease items are shown below:

	Total Minimum Lease Payments
	Cinergy			CG&E and subsidiaries			PSI			ULH&P
	(in millions)
Total minimum lease payments(1)	$	55		$	32		$	23		$	8
Less: amount representing interest	(12		)	(7		)	(5		)	(2		)
Present value of minimum lease payments	$	43		$	25		$	18		$	6

(1) Annual minimum lease payments are immaterial.

8.Financial Instruments

(a)Financial Derivatives

We have entered into financial derivative contracts for the purpose described below.

Interest Rate Risk Management

Our current policy of managing exposure to fluctuations in interest rates is to maintain approximately 30 percent of the total amount of outstanding debt in floating interest rate debt instruments.  In maintaining this level of exposure, we use interest rate swaps.  Under the swaps, we agree with other parties to exchange, at specified intervals, the difference between fixed-rate and floating-rate interest amounts calculated on an agreed notional amount.  CG&E has an outstanding interest rate swap agreement that decreased the percentage of floating-rate debt.  Under the provisions of the swap, which has a notional amount of $100 million, CG&E pays a fixed-rate and receives a floating-rate through October 2007.  This swap qualifies as a cash flow hedge under the provisions of Statement 133.  As the terms of the swap agreement mirror the terms of the debt agreement that it is hedging, we anticipate that this swap will continue to be effective as a hedge.  Changes in fair value of this swap are recorded in Accumulated other comprehensive income (loss), beginning with our adoption of Statement 133 on January 1, 2001.  Cinergy Corp. has three outstanding interest rate swaps with a combined notional amount of $250 million.  Under the provisions of the swaps, Cinergy Corp. receives fixed-rate interest payments and pays floating-rate interest payments through September 2004.  These swaps qualify as fair value hedges under the provisions of Statement 133.  We anticipate that these swaps will continue to be effective as hedges.

Treasury locks are agreements that fix the yield or price on a specified treasury security for a specified period, which we sometimes use in connection with the issuance of fixed-rate debt.  On September 23, 2002, CG&E issued $500 million principal amount senior unsecured debentures due September 15, 2012, with an interest rate of 5.70 percent.  In July 2002, CG&E executed a treasury lock with a notional amount of $250 million, which was designated as a cash flow hedge of 50 percent of the forecasted interest payments on this debt offering.  The treasury lock effectively fixed the benchmark interest rate (i.e., the treasury component of the interest rate, but

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not the credit spread) for 50 percent of the offering from July 2002 through the issuance date in order to reduce the exposure associated with treasury rate volatility.  With the issuance of the debt, the treasury lock was settled.  Given the use of hedge accounting, this settlement is reflected in Accumulated other comprehensive income (loss) on an after-tax basis in the amount of $13 million, rather than a charge to net income.  This amount will be reclassified to Interest expense over the 10-year life of the related debt as interest is accrued.

See Note 1(l) for additional information on financial derivatives.   In the future, we will continually monitor market conditions to evaluate whether to modify our level of exposure to fluctuations in interest rates.

(b)Fair Value of Other Financial Instruments

The estimated fair values of other financial instruments were as follows (this information does not claim to be a valuation of the companies as a whole):

	December 31, 2002				December 31, 2001
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(in millions)
Cinergy(1)
First mortgage bonds and other long-term debt(2)	$	4,272	$	4,483	$	3,745	$	3,805
CG&E and subsidiaries
First mortgage bonds and other long-term debt(2)	$	1,690	$	1,743	$	1,205	$	1,214
PSI
First mortgage bonds and other long-term debt(2)	$	1,372	$	1,473	$	1,348	$	1,379
ULH&P
Other long-term debt(2)	$	75	$	78	$	75	$	76

(1)The results of Cinergy also include amounts related to non-registrants.

(2)Includes amounts reflected as Long-term debt due within one year.

The following methods and assumptions were used to estimate the fair values of each major class of instruments:

(i)Cash and cash equivalents, Restricted deposits, and Notes payable and other short-term obligations

Due to the short period to maturity, the carrying amounts reflected on the Balance Sheets approximate fair values.

(ii)Long-term debt

The fair values of long-term debt issues were estimated based on the latest quoted market prices or, if not listed on the New York Stock Exchange, on the present value of future cash flows.  The discount rates used approximate the incremental borrowing costs for similar instruments.

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(c)Concentrations of Credit Risk

Credit risk is the exposure to economic loss that would occur as a result of nonperformance by counterparties, pursuant to the terms of their contractual obligations.  Specific components of credit risk include counterparty default risk, collateral risk, concentration risk, and settlement risk.

(i)Trade Receivables and Physical Power Portfolio

Our concentration of credit risk with respect to trade accounts receivable from electric and gas retail customers is limited.  The large number of customers and diversified customer base of residential, commercial, and industrial customers significantly reduces our credit risk.  Contracts within the physical portfolio of power marketing and trading operations are primarily with the traditional electric cooperatives and municipalities and other investor-owned utilities.  At December 31, 2002, we believe the likelihood of significant losses associated with credit risk in our trade accounts receivable or physical power portfolio is remote.

(ii)Energy Trading Credit Risk

Cinergy’s extension of credit for energy marketing and trading is governed by a Corporate Credit Policy.  Written guidelines document the management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation procedures.  Exposures to credit risks are monitored daily by the Corporate Credit Risk function.  As of December 31, 2002, approximately 96 percent of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or the counterparties’ obligations were guaranteed by a parent company or other entity rated Investment Grade.  No single non-investment grade counterparty accounts for more than one percent of our total credit exposure.  Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity.  Because of these issues, credit risk is generally greater than with other commodity trading.

In December 2001, Enron Corp. (Enron) filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of New York.  We decreased our trading activities with Enron in the months prior to its bankruptcy filing.  We intend to resolve any contract differences pursuant to the terms of those contracts, business practices, and the applicable provisions of the Bankruptcy Code, as approved by the court.  While we cannot predict the resolution of these matters, we do not believe that any exposure relating to those contracts would have a material impact on our financial position or results of operations.

We continually review and monitor our credit exposure to all counterparties and secondary counterparties.  If appropriate, we may adjust our credit reserves to attempt to compensate for increased credit risk within the industry.  Counterparty credit limits may be adjusted on a daily basis in response to changes in a counterparty’s financial status or public debt ratings.

(iii)Financial Derivatives

Potential exposure to credit risk also exists from our use of financial derivatives such as currency swaps, foreign exchange forward contracts, interest rate swaps, and treasury locks.  Because

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these financial instruments are transacted with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.

9.Pension and Other Postretirement Benefits

We provide benefits to retirees in the form of pensions and other postretirement benefits.

Our qualified defined benefit pension plans cover substantially all U.S. employees meeting certain minimum age and service requirements.  A final average pay formula determines plan benefits.  These plan benefits are based on:

•years of participation;

•age at retirement; and

•the applicable average Social Security wage base or benefit amount.

Our pension plan funding policy for U.S. employees is to contribute at least the amount required by the Employee Retirement Income Security Act of 1974, and up to the amount deductible for income tax purposes.  The pension plans’ assets consist of investments in equity and fixed income securities.

We provide certain health care and life insurance benefits to retired U.S. employees and their eligible dependents.  These benefits are subject to minimum age and service requirements.  The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments.  Neither CG&E nor ULH&P pre-fund their obligations for these postretirement benefits.  In 1999, PSI began pre-funding its obligations through a grantor trust as authorized by the IURC.  This trust, which consists of equity and fixed income securities, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions.  At December 31, 2002 and 2001, trust assets were approximately $52 million and $53 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.

In addition, we sponsor non-qualified pension plans (plans that do not meet the criteria for tax benefits) that cover officers, certain other key employees, and non-employee directors.  We began funding certain of these non-qualified plans through a rabbi trust in 1999.  This trust, which consists of equity and fixed income securities, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions.  At December 31, 2002 and 2001, trust assets were approximately $8 million and are reflected in Cinergy’s Balance Sheets as Other investments.

In 2000 and 2002, Cinergy offered voluntary early retirement programs to certain individuals.  In accordance with Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88), Cinergy recognized an expense of $12.8 million and $39.1 million in 2000 and 2002, respectively.

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Our benefit plans’ costs for the past three years included the following components:

	Qualified Pension Benefits									Non-Qualified Pension Benefits						Other Postretirement Benefits
	2002			2001			2000			2002		2001		2000		2002			2001		2000
	(in millions)
Service cost	$	27.3		$	27.9		$	27.4		$	2.7	$	2.1	$	2.0	$	3.5		$	3.8	$	3.4
Interest cost	79.2			77.5			73.0			5.1		4.8		4.1		19.6			17.9		17.0
Expected return on plans’ assets	(86.3		)	(81.9		)	(77.0		)	—		—		—		(0.3		)	—		—
Amortization of transition (asset) obligation	(1.3		)	(1.3		)	(1.3		)	0.1		0.1		0.1		5.0			5.0		5.0
Amortization of prior service cost	6.2			4.6			4.5			0.9		1.1		1.1		—			—		—
Recognized actuarial (gain) loss	(5.4		)	(3.2		)	(2.4		)	0.8		0.6		0.1		1.1			0.1		—
Voluntary early retirement costs (Statement 88)	38.6			—			11.9			0.5		—		0.9		—			—		—
Net periodic benefit cost	$	58.3		$	23.6		$	36.1		$	10.1	$	8.7	$	8.3	$	28.9		$	26.8	$	25.4

The net periodic benefit cost by registrant was as follows:

	Qualified Pension Benefits						Non-Qualified Pension Benefits						Other Postretirement Benefits
	2002		2001		2000		2002		2001		2000		2002		2001		2000
	(in millions)
Cinergy(1)	$	58.3	$	23.6	$	36.1	$	10.1	$	8.7	$	8.3	$	28.9	$	26.8	$	25.4
CG&E and subsidiaries	7.2		1.9		5.3		1.1		1.7		1.3		7.2		6.9		8.8
PSI	12.2		7.5		9.4		0.6		0.7		0.7		15.3		13.5		12.9
ULH&P	1.7		0.3		0.5		—		—		—		0.4		0.4		0.4

(1)  The results of Cinergy also include amounts related to non-registrants.

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The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets over the two-year period ended December 31, 2002, and a statement of the funded status as of December 31 of both years.

	Qualified Pension Benefits						Non-Qualified Pension Benefits						Other Postretirement Benefits
	2002			2001			2002			2001			2002			2001
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of period	$	1,083.5		$	1,064.5		$	70.9		$	67.0		$	270.4		$	247.1
Service cost	27.3			27.9			2.7			2.1			3.5			3.8
Interest cost	79.2			77.5			5.1			4.8			19.6			17.9
Amendments(1)	43.3			18.0			4.5			(1.8		)	(12.3		)	—
Actuarial (gain) loss	156.5			(43.6		)	20.6			4.3			80.2			17.9
Benefits paid	(74.9		)	(60.8		)	(6.0		)	(5.5		)	(18.2		)	(16.3		)
Benefit obligation at end of period	1,314.9			1,083.5			97.8			70.9			343.2			270.4
Change in plan assets
Fair value of plan assets at beginning of period	875.4			1,043.6			—			—			—			—
Actual return on plan assets	(48.0		)	(108.1		)	—			—			—			—
Employer contribution	4.0			0.7			6.0			5.5			18.2			16.3
Benefits paid	(74.9		)	(60.8		)	(6.0		)	(5.5		)	(18.2		)	(16.3		)
Fair value of plan assets at end of period	756.5			875.4			—			—			—			—
Funded status	(558.4		)	(208.1		)	(97.8		)	(70.9		)	(343.2		)	(270.4		)
Unrecognized prior service cost	48.4			50.0			13.5			10.2			—			—
Unrecognized net actuarial (gain) loss	196.2			(100.1		)	37.6			17.7			125.5			45.7
Unrecognized net transition (asset) obligation	(1.9		)	(3.2		)	0.1			0.1			33.5			50.8
Benefit cost at December 31	$	(315.7	)	$	(261.4	)	$	(46.6	)	$	(42.9	)	$	(184.2	)	$	(173.9	)
Amounts recognized in balance sheets
Accrued benefit liability	$	(353.0	)	$	(261.4	)	$	(89.0	)	$	(63.3	)	$	(184.2	)	$	(173.9	)
Intangible asset	32.6			—			13.6			10.3			—			—
Accumulated other comprehensive income (pre-tax)	4.7			—			28.8			10.1			—			—
Net recognized at end of period	$	(315.7	)	$	(261.4	)	$	(46.6	)	$	(42.9	)	$	(184.2	)	$	(173.9	)

(1)For 2002, the amounts of $43.3 million and $4.5 million include $38.6 million and $.5 million, respectively of voluntary early retirement expenses in accordance with Statement 88, as previously discussed.

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The following table provides the weighted average actuarial assumptions.

	Qualified Pension Benefits							Non-Qualified Pension Benefits									Other Postretirement Benefits
	2002		2001		2000			2002			2001			2000			2002			2001			2000
Actuarial assumptions:
Discount rate	6.75	%	7.50	%	7.50	%	6.75		%	7.50		%	7.50		%	6.75		%	7.50		%	7.50		%
Rate of future compensation increase	4.00		4.00		4.50		4.00			4.00			4.50			N/A			N/A			N/A
Rate of return on plans’ assets	9.00		9.25		9.00		N/A			N/A			N/A			N/A			3.00			N/A

For measurement purposes, we assumed a seven percent annual rate of increase in the per capita cost of covered health care benefits for 2002.  It was assumed that the rate would decrease gradually to five percent in 2008 and remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(in millions)
Effect on total of service and interest cost components	$	3.4	$	(2.9	)
Effect on postretirement benefit obligation	44.3		(38.7		)

During 2002, eligible Cinergy employees were offered the opportunity to make a one-time election, effective January 1, 2003, to either continue to have their pension benefit determined by the current defined benefit pension formula or to have their benefit determined using a cash balance formula.  Participants in the cash balance plan may request a lump-sum cash payment based upon termination of their employment which may result in increased cash requirements from pension plan assets.

Since 85 percent of eligible employees chose to continue with the traditional pension formula, we do not believe the cash balance features will have a material effect on our financial position or results of operations.

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10.Income Taxes

The following table shows the significant components of Cinergy’s, CG&E’s, and PSI’s net deferred income tax liabilities as of December 31:

	Cinergy(1)				CG&E and subsidiaries				PSI
	2002		2001		2002		2001		2002		2001
	(in millions)
Deferred Income Tax Liability
Property, plant, and equipment	$	1,356.5	$	1,172.0	$	803.1	$	708.0	$	520.3	$	453.2
Unamortized costs of reacquiring debt	13.9		13.4		2.8		3.2		11.0		10.2
Deferred operating expenses and carrying costs	4.4		10.3		—		—		4.4		10.3
Purchased power tracker	11.6		9.7		—		—		11.6		9.7
RTC	213.2		206.0		213.2		206.0		—		—
Net energy risk management assets	8.8		12.2		1.0		8.4		—		—
Amounts due from customers-income taxes	37.4		22.9		20.1		16.0		17.3		6.9
Gasification services agreement buyout costs	89.8		92.3		—		—		89.8		92.3
Other	45.2		48.2		10.9		8.7		1.2		2.3
Total Deferred Income Tax Liability	1,780.8		1,587.0		1,051.1		950.3		655.6		584.9
Deferred Income Tax Asset
Unamortized investment tax credits	42.5		45.9		32.9		36.0		9.6		10.0
Accrued pension and other postretirement benefit costs	196.3		162.4		107.5		96.6		60.1		47.2
Net energy risk management liabilities	—		—		—		—		9.0		5.5
Rural Utilities Service obligation	28.2		28.2		—		—		28.2		28.2
Other	41.9		48.5		28.1		38.4		10.0		7.3
Total Deferred Income Tax Asset	308.9		285.0		168.5		171.0		116.9		98.2
Net Deferred Income Tax Liability	$	1,471.9	$	1,302.0	$	882.6	$	779.3	$	538.7	$	486.7

(1)The results of Cinergy also include amounts related to non-registrants.

We will file a consolidated federal income tax return for the year ended December 31, 2002.  The current tax liability is allocated among the members of the Cinergy consolidated group, pursuant to a tax sharing agreement filed with the SEC under the PUHCA.

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The following table summarizes federal and state income taxes charged (credited) to income for Cinergy, CG&E, and PSI:

	Cinergy(1)									CG&E and subsidiaries									PSI
	2002			2001			2000			2002			2001			2000			2002			2001			2000
	(in millions)
Current Income Taxes
Federal	$	13.3		$	122.9		$	187.3		$	50.6		$	135.1		$	121.5		$	71.1		$	59.9		$	84.4
State	(4.1		)	9.3			16.9			0.6			7.6			1.6			9.7			4.6			10.8
Total Current Income Taxes	9.2			132.2			204.2			51.2			142.7			123.1			80.8			64.5			95.2
Deferred Income Taxes
Federal
Depreciation and other property, plant, and equipment-related items(2)	172.2			42.7			26.1			73.6			23.3			19.0			79.6			10.7			7.1
Pension and other benefit costs	(17.4		)	(11.8		)	(21.3		)	(4.7		)	(4.2		)	(7.5		)	(7.4		)	(7.6		)	(11.5		)
Deferred excise taxes	—			14.5			—			—			14.5			—			—			—			—
Unrealized energy risk management transactions	9.0			44.0			10.9			2.2			23.9			5.6			(2.8		)	11.6			2.0
Fuel costs	(22.7		)	5.7			28.7			8.8			(8.0		)	26.7			(31.5		)	13.7			2.0
Purchased power tracker	1.5			8.5			—			—			—			—			1.5			8.5			—
Gasification services agreement buyout costs	(2.6		)	(2.2		)	(0.1		)	—			—			—			(2.6		)	(2.2		)	(0.1		)
Other-net	(14.1		)	16.1			11.0			8.3			(4.8		)	(3.0		)	(7.5		)	5.3			(1.2		)
Total Deferred Federal Income Taxes	125.9			117.5			55.3			88.2			44.7			40.8			29.3			40.0			(1.7		)
State	30.4			15.4			1.7			20.8			5.0			1.5			7.8			4.8			(1.4		)
Total Deferred Income Taxes	156.3			132.9			57.0			109.0			49.7			42.3			37.1			44.8			(3.1		)
Investment Tax Credits-Net	(8.2		)	(9.1		)	(9.6		)	(4.9		)	(5.9		)	(6.0		)	(3.2		)	(3.2		)	(3.6		)
Total Income Taxes	$	157.3		$	256.0		$	251.6		$	155.3		$	186.5		$	159.4		$	114.7		$	106.1		$	88.5

(1)The results of Cinergy also include amounts related to non-registrants.

(2)The increase in deferred income taxes for depreciation and other property, plant, and equipment-related items includes a change in accounting method for tax purposes related to capitalized costs.

Internal Revenue Code Section 29 provides a tax credit (nonconventional fuel source credit) for qualified fuels produced and sold by a taxpayer to an unrelated person during the taxable year.  The nonconventional fuel source credit reduced current federal income tax expense $41.6 million and $1.1 million for 2002 and 2001, respectively.

Internal Revenue Code Section 45 provides a tax credit for electricity produced from certain renewable resources during the taxable year.  The renewable resource credit reduced current federal income tax expense $4.1 million, $3.2 million, and $2.5 million for 2002, 2001, and 2000, respectively.

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The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the federal income tax expense reported in the Statements of Income for Cinergy, CG&E, and PSI.

	Cinergy(1)									CG&E and subsidiaries									PSI
	2002			2001			2000			2002			2001			2000			2002			2001			2000
	(in millions)
Statutory federal income tax provision	$	184.8		$	235.6		$	221.3		$	139.2		$	175.2		$	148.1		$	109.0		$	90.7		$	75.1
Increases (reductions) in taxes resulting from:
Amortization of investment tax credits	(8.2		)	(9.1		)	(9.6		)	(4.9		)	(5.9		)	(6.0		)	(3.2		)	(3.2		)	(3.6		)
Depreciation and other property, plant, and equipment-related differences	0.2			3.2			17.7			1.0			2.6			14.0			(0.8		)	0.6			3.6
Preferred dividend requirements of subsidiaries	1.2			1.2			1.6			—			—			—			—			—			—
Income tax credits	(45.7		)	(4.3		)	(2.5		)	—			—			—			—			—			—
Foreign tax adjustments	5.0			(1.3		)	—			—			—			—			—			—			—
Employee Stock Option Plan dividend	(3.0		)	—			—			—			—			—			—			—			—
Other-net	(3.3		)	6.0			4.5			(1.4		)	2.0			0.2			(7.8		)	8.6			4.0
Federal Income Tax Expense	$	131.0		$	231.3		$	233.0		$	133.9		$	173.9		$	156.3		$	97.2		$	96.7		$	79.1

(1)The results of Cinergy also include amounts related to non-registrants.

The following table shows the significant components of ULH&P’s net deferred income tax liability as of December 31, 2002 and 2001:

	ULH&P
	2002		2001
	(in thousands)
Deferred Income Tax Liability
Property, plant, and equipment	$	44,309	$	34,218
Unamortized costs of reacquiring debt	652		699
Amounts due from customers-income taxes	2,194		—
Deferred fuel costs	—		—
Other	6,340		4,158
Total Deferred Income Tax Liability	53,495		39,075
Deferred Income Tax Asset
Unamortized investment tax credits	1,309		1,035
Amounts due to customers-income taxes	—		2,524
Deferred fuel costs	1,987		520
Accrued pension and other postretirement benefit costs	4,410		3,947
Other	2,429		2,726
Total Deferred Income Tax Asset	10,135		10,752
Net Deferred Income Tax Liability	$	43,360	$	28,323

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The following table summarizes federal and state income taxes charged (credited) to income for ULH&P:

	ULH&P
	2002			2001			2000
	(in thousands)
Current Income Taxes
Federal	$	3,250		$	23,109		$	5,003
State	5,984			(2,293		)	(129		)
Total Current Income Taxes	9,234			20,816			4,874
Deferred Income Taxes
Federal
Depreciation and other property, plant, and equipment-related items	2,797			1,042			1,059
Pension and other benefit costs	(309		)	(140		)	(605		)
Fuel costs	(696		)	(7,338		)	8,564
Unamortized costs of reacquiring debt	(70		)	(30		)	(30		)
Service company allocations	—			192			251
Other-net	1,138			212			(338		)
Total Deferred Federal Income Taxes	2,860			(6,062		)	8,901
Deferred State Income Taxes	522			(781		)	303
Total Deferred Income Taxes	3,382			(6,843		)	9,204
Investment Tax Credits-Net	(267		)	(274		)	(277		)
Total Income Taxes	$	12,349		$	13,699		$	13,801

The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the federal income tax expense reported in the Statements of Income for ULH&P.

	ULH&P
	2002			2001			2000
	(in thousands)
Statutory federal income tax provision	$	6,298		$	18,444		$	13,391
Increases (reductions) in taxes resulting from:
Amortization of investment tax credits	(267		)	(274		)	(277		)
Depreciation and other property, plant, and equipment- related differences	(387		)	23			830
Other-net	199			(1,420		)	(317		)
Federal Income Tax Expense	$	5,843		$	16,773		$	13,627

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11.Commitments and Contingencies

(a)Construction and Other Commitments

Forecasted construction and other committed expenditures, including capitalized financing costs, for the year 2003 and for the five-year period 2003-2007 (in nominal dollars) are presented in the table below:

	2003		2003-2007
	(in millions)
Cinergy(1)	$	759	$	3,102
CG&E and subsidiaries	326		1,477
PSI(2)	367		1,369
ULH&P	43		242

(1)The results of Cinergy also include amounts related to non-registrants.

(2)Excludes intercompany purchase of peaking plants from a non-regulated affiliate.

This forecast includes an estimate of expenditures in accordance with the companies’ plans regarding nitrogen oxide (NO_X) emission control standards and other environmental compliance (excluding implementation of the tentative U.S. Environmental Protection Agency (EPA) Agreement), as discussed below.

(b)Guarantees

In the ordinary course of business, Cinergy enters into various agreements providing financial or performance assurances to third parties on behalf of certain unconsolidated subsidiaries and joint ventures.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these entitieson a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish their intended commercial purposes.  The guarantees have various termination dates, from short-term (less than one year) to open-ended.

In many cases, the maximum potential amount of an outstanding guarantee is an express term, set forth in the guarantee agreement, representing the maximum potential obligation of Cinergy under that guarantee (excluding, at times, certain legal fees to which a guaranty beneficiary may be entitled).  In those cases where there is no maximum potential amount expressly set forth in the guarantee agreement, we calculate the maximum potential amount by considering the terms of the guaranteed transactions, to the extent such amount is estimable.

Cinergy has guaranteed the payment of $33 million as of December 31, 2002, for unconsolidated subsidiaries’ debt and for borrowings by individuals under the Director, Officer, and Key Employee Stock Purchase Program (see Note 2(d) for further information).  Cinergy may be obligated to pay the debt’s principal and any related interest in the event of an unexcused breach of a guaranteed payment obligation by the unconsolidated subsidiary or an unexcused breach of guaranteed payment obligations by certain directors, officers, and key employees.  The majority of these guarantees expire in three years.

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Cinergy Corp. has also provided performance guarantees on behalf of certain unconsolidated subsidiaries and joint ventures.  These guarantees support performance under various agreements and instruments (such as construction contracts, operations and maintenance agreements and energy service agreements).  Cinergy Corp. may be liable in the event of an unexcused breach of a guaranteed performance obligation by an unconsolidated subsidiary.  Cinergy Corp. has estimated its maximum potential amount to be $133 million under these guarantees as of December 31, 2002.  Cinergy Corp. may also have recourse to third parties for claims required to be paid under certain of these guarantees.  The majority of these guarantees expire at the completion of the underlying performance agreement, generally 15 to 20 years.

Cinergy has entered into contracts that include indemnification provisions as a routine part of its business activities.  Examples of thesecontracts include purchase and sale agreements and operating agreements.  In general, these provisions indemnify the counterparty for matters such as breaches of representations and warranties and covenants contained in the contract.  In some cases, particularly with respect to purchase and sale agreements, the potential liability for certain indemnification obligations is capped, in whole or in part (generally at an aggregate amount not exceeding the sale price), and subject to a deductible amount beforeany payments would become due.In other cases (such as indemnifications for willful misconduct of employees in a joint venture), the maximum potential amount is not estimable given that the magnitude of any claims under those indemnifications would be a function of the extent of damages actually incurred, which is not practicable to estimate unless and until the event occurs.  Cinergy has estimated the maximum potential amount, where estimable, to be $131 million under these indemnification provisions and considers the likelihood of making any material payments under these provisions to be remote.  The termination period for the majority of matters covered under indemnification provisions in purchase and sale agreements generally ranges from two to seven years.

We believe the likelihood that Cinergy would be required to perform or otherwise incur any significant losses associated with any or all of the guarantees described in the preceding paragraphs is remote.

(c)Ozone Transport Rulemakings

In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the EPA to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant with ozone standards) in the Northeast, Midwest, and South.  Ozone transport refers to wind-blown movement of ozone and ozone-causing materials across city and state boundaries.

(i)NO_X State Implementation Plan (SIP) Call

In October 1998, the EPA finalized its ozone transport rule, also known as the NO_X SIP Call.  It applied to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate, and proposed a model NO_X emission allowance trading program.  This rule recommended that states reduce NO_X emissions primarily from industrial and utility sources to a certain level by May 2003.

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Ohio, Indiana, a number of other states, and various industry groups (some of which we are a member), filed legal challenges to the NO_X SIP Call with the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals).  In August 2000, the Court of Appeals extended the deadline for NO_X reductions to May 31, 2004.  In June 2001, the Court of Appeals remanded portions of the NO_X SIP Call to the EPA for reconsideration of how growth was factored into the state NO_X budgets.  On May 1, 2002, the EPA published, in the Federal Register, a final rule reaffirming its growth factors and state NO_X budgets, with additional explanation.  The states of West Virginia and Illinois, along with various industry groups (some of which we are a member), have challenged the growth factors and state NO_X budgets in an action filed in the Court of Appeals.  It is unclear when the Court of Appeals will reach a decision in this case, or whether this decision will result in an increase or decrease in the size of the NO_X reduction requirement, or a deferral of the May 31, 2004 compliance deadline.

The states of Indiana and Kentucky developed final NO_X SIP rules in response to the NO_X SIP Call, through cap and trade programs, in June and July of 2001, respectively.  On November 8, 2001, the EPA approved Indiana’s SIP rules, which became effective December 10, 2001.  On April 11, 2002, the EPA proposed direct final approval of Kentucky’s rules and they became effective on June 10, 2002.  The state of Ohio completed its NO_X SIP rules in response to the NO_X SIP Call on July 8, 2002, with an effective date of July 18, 2002.  On January 16, 2003, the EPA proposed a direct final rule to approve Ohio’s SIP.  The rule will be effective March 17, 2003, assuming no adverse comments are received.  Cinergy’s current plans for compliance with the EPA’s NO_X SIP Call would also satisfy compliance with Indiana’s, Kentucky’s, and Ohio’s SIP rules.

On September 25, 2000, Cinergy announced a plan for its subsidiaries, CG&E and PSI, to invest in pollution control equipment and other methods to reduce NO_X emissions.  This plan includes the following:

•complete installation of 9 selective catalytic reduction units at several different generating stations;

•install other pollution control technologies, including new computerized combustion controls, at all generating stations;

•make combustion improvements; and

•utilize the NO_X allowance market to buy or sell NO_X allowances as appropriate.

The current estimate for additional expenditures for this investment is approximately $275 million and is in addition to the $578 million already incurred to comply with this program.

(ii)Section 126 Petitions

In February 1998, several northeast states filed petitions seeking the EPA’s assistance in reducing ozone in the Eastern U.S. under Section 126 of the Clean Air Act (CAA).  The EPA believes that Section 126 petitions allow a state to claim that sources in another state are contributing to its air quality problem and request that the EPA require the upwind sources to reduce their emissions.

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In December 1999, the EPA granted four Section 126 petitions relating to NO_X emissions.  This ruling affected all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and requires us to reduce our NO_X emissions to a certain level by May 2003.  In May 2001, the Court of Appeals substantially upheld a challenge to the Section 126 requirements, and remanded portions of the rule to the EPA for reconsideration of how growth was factored into the emission limitations.  On August 24, 2001, the Court of Appeals temporarily suspended the Section 126 compliance deadline, pending the EPA’s reconsideration of growth factors.  On May 1, 2002, the EPA issued a final rule extending the Section 126 rule compliance deadline to May 31, 2004, thus harmonizing the deadline with that for the NO_X SIP Call.

The Section 126 rule will not apply, however, in states with approved SIPs under the NO_X SIP Call, which include the states of Indiana and Kentucky.  In addition, the EPA has issued a direct final rule approving Ohio’s SIP.  As a result of these actions, we anticipate that the Section 126 rule will not affect any of our facilities.

(iii)State Ozone Plans

On November 15, 1999, the states of Indiana and Kentucky (along with Jefferson County, Kentucky) jointly filed an amendment to their attainment demonstration on how they intend to bring the Greater Louisville Area (including Floyd and Clark Counties in Indiana) into attainment with the one-hour ozone standard.  The Greater Louisville Area has since attained the one-hour ozone standard, and on October 23, 2001, the EPA re-designated the area as being in attainment with that standard.  Previous SIP amendments called for, among other things, statewide NO_X reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA’s NO_X SIP Call.  In lieu of continuing rulemakings for NO_X emission reductions under this demonstration, the states completed more stringent NO_X emission reduction regulations in response to the NO_X SIP Call.

See (f) below for a discussion of the tentative EPA Agreement, the implementation of which could affect our strategy for compliance with the final NO_X SIP Call.

(d)New Source Review (NSR)

The CAA’s NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major modification to an existing facility, unless the changes are exempt.

On November 3, 1999, the United States sued a number of holding companies and electric utilities, including Cinergy, CG&E, and PSI, in various U.S. District Courts (District Court).  The Cinergy, CG&E, and PSI suit alleged violations of the CAA at two of our generating stations relating to NSR and New Source Performance Standards requirements.  The suit sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at CG&E’s W.C. Beckjord Generating Station (Beckjord Station) and at PSI’s Cayuga Generating Station, and (2) civil penalties in amounts of up to $27,500 per day for each violation.  Since that time, two amendments to the complaint have been filed by the United States, alleging additional violations of the CAA, including allegations involving different generating units.  In addition, three northeast states and two environmental groups have intervened in the case.

On December 21, 2000, Cinergy, CG&E, and PSI reached an agreement in principle with the parties in the litigation for a negotiated resolution of the CAA claims in the litigation.  See (f) below for a discussion of the tentative EPA Agreement, which relates to matters discussed within this note.

On October 4, 2002, the Indiana District Court issued a Revised Case Management Plan in Cinergy’s case that sets forth the dates by which various events in the litigation, such as discovery and the filing of dispositive motions, must be completed.  Consistent with the plan, on October 9, 2002, the Indiana District Court set the case for trial by jury commencing on October 4, 2004.

At this time, it is not possible to predict whether a final agreement implementing the agreement in principle can be reached.  The parties continue to negotiate.  If the settlement is not completed, we intend to defend against the allegations vigorously in court.  In such an event, it is not possible to determine the likelihood that the plaintiffs would prevail upon their claims or whether resolution of these matters would have a material effect on our financial position or results of operations.

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(e)Beckjord Station NOV

On November 30, 1999, the EPA filed an NOV against Cinergy and CG&E, alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit.  The allegations contained in this NOV were incorporated within the March 1, 2000 amended complaint, as discussed in (d) above.  On June 22, 2000, the EPA issued an NOV and a finding of violation (FOV) alleging additional particulate emission violations at Beckjord Station.  The NOV/FOV indicated the EPA may issue an administrative compliance order, issue an administrative penalty order, or bring a civil or criminal action.

See (f) below for a discussion of the tentative EPA Agreement, which relates to matters discussed within this note.

(f)EPA Agreement

On December 21, 2000, Cinergy, CG&E, and PSI reached an agreement in principle with the United States, three northeast states, and two environmental groups for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated by Cinergy’s operating subsidiaries.  The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties.  If a final agreement is reached with these parties, it would resolve past claims of alleged NSR violations as well as the Beckjord Station NOVs/FOV discussed previously under (d) and (e).

In addition, the intent of the tentative agreement is that we would be allowed to continue on-going activities to maintain reliability and availability without subjecting the plants to future litigation regarding federal NSR permitting requirements.

In return for resolution of claims regarding past maintenance activities, as well as future operational certainty, we have tentatively agreed to:

•shut down or repower with natural gas, nine small coal-fired boilers at three power plants beginning in 2004;

•build four additional sulfur dioxide (SO₂) scrubbers, the first of which must be operational by December 31, 2007;

•upgrade existing particulate control systems;

•phase in the operation of NO_X reduction technology year-round starting in 2004;

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•reduce our existing Title IV SO₂ cap by 35 percent in 2013;

•pay a civil penalty of $8.5 million to the U.S. government; and

•implement $21.5 million in environmental mitigation projects, including retiring 50,000 tons of SO₂ allowances by 2005.

The estimated cost for these capital expenditures is expected to be approximately $700 million through 2013. These capital expenditures are in addition to our previously announced commitment to install NO_X controls as discussed in (c) above, but does include capital costs that Cinergy would expect to spend regardless of the settlement due to new environmental requirements expected in the second half of this decade.

Cinergy, CG&E, and PSI have accrued costs related to certain aspects of the tentative agreement.  In reaching the tentative agreement, we did not admit any wrongdoing and remain free to continue our current maintenance practices, as well as implement future projects for improved reliability.

At this time, it is not possible to predict whether a final agreement implementing the agreement in principle can be reached.  The parties continue to negotiate.  If the settlement is not completed, we intend to defend against the allegations, discussed in (d) and (e) above, vigorously in court.  In such an event, it is not possible to determine the likelihood that the plaintiffs would prevail upon their claims or whether resolution of these matters would have a material effect on our financial position or results of operations.

(g)Manufactured Gas Plant (MGP) Sites

Prior to the 1950s, gas was produced at MGP sites through a process that involved the heating of coal and/or oil.  The gas produced from this process was sold for residential, commercial, and industrial uses.

Coal tar residues, related hydrocarbons, and various metals associated with MGP sites have been found at former MGP sites in Indiana, including at least 21 sites which PSI or its predecessors previously owned.  PSI acquired four of the sites from NIPSCO in 1931.  At the same time, PSI sold NIPSCO the sites located in Goshen and Warsaw, Indiana.  In 1945, PSI sold 19 of these sites (including the four sites it acquired from NIPSCO) to the predecessor of the Indiana Gas Company, Inc. (IGC).  IGC later sold the site located in Rochester, Indiana to NIPSCO.

IGC and NIPSCO have both made claims against PSI alleging that PSI is a Potentially Responsible Party with respect to the 21 MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).  The claims further asserted that PSI was legally responsible for the costs of investigating and remediating the sites.  In August 1997, NIPSCO filed suit against PSI in federal court, claiming recovery (pursuant to CERCLA) of NIPSCO’s past and future costs of investigating and remediating MGP-related contamination at the Goshen, Indiana MGP site.

In November 1998, NIPSCO, IGC, and PSI entered into a Site Participation and Cost Sharing Agreement (Agreement).  This Agreement allocated CERCLA liability for past and future costs at seven MGP sites in Indiana among the three companies.  As a result of the Agreement, NIPSCO’s lawsuit against PSI was dismissed.  Similar agreements were reached between IGC and PSI that allocate CERCLA liability at 14 MGP sites with which NIPSCO was not involved.  These agreements concluded all CERCLA and similar claims between the three companies related to MGP sites.  The parties continue to investigate and remediate the sites, as appropriate, under the agreements and applicable laws.  The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of some of the sites.

PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and IDEM.  In April 1998, PSI filed suit in Hendricks County Circuit Court in the State of Indiana against its general liability insurance carriers.  PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI, or (2) pay PSI’s costs of defense and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites.  The lawsuit was moved to the Hendricks County Superior Court (Superior Court) in July 1998.  The trial court issued a variety of rulings with respect to the claims and defenses in the litigation.  PSI has appealed certain adverse rulings to the Indiana Court of Appeals.  At the present time, PSI cannot predict the outcome of this litigation, including the outcome of the appeals to the Indiana Court of Appeals.

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PSI and CG&E, including its utility subsidiaries, have accrued costs for the sites related to investigation, remediation, and groundwater monitoring to the extent such costs are probable and can be reasonably estimated.  PSI and CG&E, including its utility subsidiaries, do not believe they can provide an estimate of the reasonably possible total remediation costs for any site before a remedial investigation/feasibility study is performed.  To the extent remediation is necessary, the timing of the remediation activities impacts the cost of remediation.  Therefore, PSI and CG&E, including its utility subsidiaries, currently cannot determine the total costs that may be incurred in connection with remediation of all sites, to the extent that remediation is required.  Until investigation and remediation activities have been completed on these sites, and the extent of insurance coverage for these costs, if any, is determined, we are unable to reasonably estimate the total costs and impact on our financial position or results of operations.

(h)Asbestos Claims Litigation

CG&E and PSI have been named in lawsuits related to Asbestos at their electric generating stations.  In these lawsuits, plaintiffs claim to have been exposed to Asbestos containing products in the course of their work at the CG&E and PSI generating stations.  The plaintiffs further claim that as the property owner of the generating stations, CG&E and PSI should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any Asbestos exposure.  A majority of the lawsuits to date have been brought against PSI.  The impact on CG&E’s and PSI’s financial position or results of operations of these cases to date has not been material.

One specific case filed against PSI has been tried to verdict.  Following a 10 week trial of the case entitled William Lee Roberts, Jr. and Beverly Roberts v. AC&S, Inc., et al., PSI Energy, Inc., Marion Superior Court 2, on May 24, 2002, the jury returned a verdict against PSI in the amount of approximately $500,000 on a negligence claim and for PSI on punitive damages.  PSI is appealing the judgment in this case.  The total damages were immaterial to PSI’s financial position and results of operations.  However, future verdicts in any of the pending lawsuits could be material.  At this time, CG&E and PSI are not able to predict the ultimate outcome of these lawsuits or the impact on CG&E’s and PSI’s financial position or results of operations.

(i)Gas Customer Choice

In January 2000, Investments sold Cinergy Resources, Inc. (Resources), a former subsidiary, to Licking Rural Electrification, Inc., doing business as The Energy Cooperative (Energy Cooperative).  In February 2001, Cinergy, CG&E, and Resources were named as defendants in

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three class action lawsuits brought by customers relating to Energy Cooperative’s removal from the Ohio Gas Customer Choice program and the failure to deliver gas to customers.

Subsequently, these class action suits were amended and consolidated into one suit.  CG&E has been dismissed as a defendant in the consolidated suit.  In March 2001, Cinergy, CG&E, and Investments were named as defendants in a lawsuit filed by both Energy Cooperative and Resources.  This lawsuit concerns any obligations or liabilities Investments may have to Energy Cooperative following its sale of Resources.  This lawsuit is pending in the Licking County Common Pleas Court.  Trial is anticipated to occur in late 2003 or early 2004.  In October 2001, Cinergy, CG&E, and Investments initiated litigation against the Energy Cooperative requesting indemnification by the Energy Cooperative for the claims asserted by former customers in the class action litigation.  This customer litigation is pending in the Hamilton County Common Pleas Court.  A trial date has not been set.  We intend to vigorously defend these lawsuits.  At the present time, we cannot predict the outcome of these suits.

(j)PSI Fuel Adjustment Charge

PSI defers fuel costs that are recoverable in future periods subject to IURC approval under a fuel recovery mechanism.  In June 2001, the IURC issued an order in a PSI fuel recovery proceeding, disallowing approximately $14 million of deferred costs.  On June 26, 2001, PSI formally requested that the IURC reconsider its disallowance decision.  In August 2001, the IURC indicated that it would reconsider its decision.  In August 2002, the IURC issued its final ruling allowing PSI to fully recover the $14 million.

In June 2001, PSI filed a petition with the IURC requesting authority to recover $16 million in under billed deferred fuel costs incurred from March 2001 through May 2001.  The IURC approved recovery of these costs subject to refund pending the findings of an investigative sub-docket.  The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under billed deferred fuel costs.  A hearing was held in July 2002, and we anticipate a decision in the first quarter of 2003.

(k)PSI Retail Rate Case

In December 2002, PSI filed a petition with the IURC seeking approval of a base retail electric rate increase.  PSI’s proposed increase reflects an average increase of approximately 16 to 19 percent over PSI’s current retail electric rates.  If approved by regulators, PSI estimates the rate request will become effective in early 2004.  PSI plans to file initial testimony in this case in March 2003.  An IURC decision is expected in the first quarter of 2004.

(l)Construction Work in Progress (CWIP) Ratemaking Treatment for NO_X Equipment

During the third quarter of 2001, PSI filed an application with the IURC requesting CWIP ratemaking treatment for costs related to NO_X equipment currently being installed at certain PSI generation facilities.  CWIP ratemaking treatment allows for the recovery of carrying costs on the equipment during the construction period.  PSI filed its case-in-chief testimony in January 2002.  In July 2002, the IURC approved the application allowing PSI to commence CWIP ratemaking treatment for its NO_X equipment investments made through December 31, 2001.

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Initially this rate adjustment will result in approximately a one percent increase in customer rates.  Under the IURC’s CWIP rules, PSI may update its CWIP tracker at six-month intervals.  The IURC’s July order also authorized PSI to defer, for subsequent recovery, post-in-service depreciation and to continue the accrual for AFUDC.  Pursuant to Statement of Financial Accounting Standards No. 92, Regulated Enterprises-Accounting for Phase-in Plans, the equity component of AFUDC will not be deferred for financial reporting.

In October 2002, PSI filed its first six-month CWIP tracker update with the IURC requesting approximately $11 million of additional revenue associated with investments made January 1, 2002, through June 30, 2002, for NO_X emission reduction equipment.  The IURC authorized the recovery of these incremental expenditures in an order issued on January 29, 2003.  The cumulative annual revenue to be recovered under this tracker is $28 million.

(m)Purchased Power Tracker

In May 1999, PSI filed a petition with the IURC seeking approval of a Tracker.  This request was designed to provide for the recovery of costs related to purchases of power necessary to meet native load requirements to the extent such costs are not recovered through the existing fuel adjustment clause.

A hearing was held before the IURC in February 2001, to determine whether it was appropriate for PSI to continue the Tracker for future periods.  In April 2001, a favorable order was received extending the Tracker for two years, through the summer of 2002.  PSI is authorized to seek recovery of 90 percent of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portion), with the remaining 10 percent deferred for subsequent recovery in PSI’s nextgeneral rate case.  In March 2002, PSI filed a petition with the IURC seeking approval to extend the Tracker process beyond the summer of 2002.  A hearing was held on January 16, 2003.  We cannot predict the outcome of this proceeding at this time.

In June 2002, PSI also filed a petition with the IURC seeking approval of the recovery through the Tracker of its actual summer 2002 purchased power costs.  A hearing on this matter is scheduled for the first quarter of 2003.

(n)CG&E Gas Rate Case

In the third quarter of 2001, CG&E filed a retail gas rate case with the PUCO seeking to increase base rates for natural gas distribution service and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $716 million over the next 10 years.  CG&E entered into a settlement agreement with most of the parties and a hearing on this matter was held in April 2002.  An order was issued in May 2002, in which the PUCO approved the settlement agreement and authorized a base rate increase of approximately $15 million, or 3.3 percent overall, to be effective on May 30, 2002.  In addition, the PUCO authorized CG&E to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program, subject to certain rate caps that increase in amount annually through May 2007, through the effective date of new rates in CG&E’s next retail gas rate case.  The

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PUCO’s order was not appealed.  In the fourth quarter of 2002, CG&E filed an application to increase its rates under the tracking mechanism by approximately $8 million or 2.4 percent.  The PUCO is investigating the application and CG&E expects that the increase will become effective in May 2003.

(o)ULH&P Gas Rate Case

In the second quarter of 2001, ULH&P filed a retail gas rate case with the KPSC seeking to increase base rates for natural gas distribution services and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $112 million over the next 10 years.  A hearing on this matter was held in November 2001 and an order was issued in January 2002.  In the order, the KPSC authorized a base rate increase of $2.7 million, or 2.8 percent overall, to be effective on January 31, 2002.  In addition, the KPSC authorized ULH&P to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program for an initial period of three years, with the possibility of renewal for the full 10 years.  Per the terms of the order, the tracking mechanism will be set annually.  The first filing was made in March 2002 and was approved by the KPSC in an order issued in August 2002.  ULH&P filed an application for a certificate for public convenience and necessity with the KPSC in November 2002, to do cast iron and bare steel main replacement work in 2003 at an estimated cost of $14.1 million.  The Kentucky Attorney General (Attorney General) has appealed the KPSC’s approval of the tracking mechanism to the Franklin Circuit Court (Court) and has also appealed the KPSC’s August 2002 order approving the new tracking mechanism rates.  The KPSC’s August 2002 order requires ULH&P to maintain records of the revenues collected under the tracking mechanism to enable ULH&P to refund such revenues, in case the Attorney General’s appeal is upheld and the KPSC orders a refund.  Amounts collected to date under this tracking mechanism are not material.  ULH&P filed an application for rehearing with the KPSC in September 2002, in which ULH&P requested that the KPSC eliminate this requirement.  In October 2002, the KPSC issued an order granting ULH&P’s application for rehearing in part.  The KPSC’s order clarified that ULH&P must maintain its records of the revenues collected under the tracking mechanism in case a refund is ordered at a later date; however, the KPSC’s order stated that it will not address the issue of whether to order a refund unless the Court rules that the KPSC lacked the requisite authority to approve the tracking mechanism.  As a result, ULH&P will not record these revenues as subject to refund unless the Court so rules.  At the present time, ULH&P cannot predict the outcome of this litigation.

(p)Contract Disputes

Cinergy, through a subsidiary of Investments, is currently involved in negotiations to resolve a customer billing dispute.  The primary issue of contention between the parties relates to the determinants used in calculating the monthly charge billed for electricity.  Cinergy has reserved for a portion of the amount billed based on our current estimate of net realizable value.

Cinergy, through a subsidiary of Capital & Trading, is involved in a billing dispute with respect to billings for the supply of wholesale natural gas to a customer.  This dispute, if not satisfactorily resolved by the parties, is subject to arbitration.  Cinergy has reserved for a portion of the amount billed based on the current estimate of net realizable value.

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Although we cannot predict the outcome of these matters, we believe the ultimate impact on Cinergy’s financial position and results of operations, beyond amounts reserved, will not be material.

12. Jointly-Owned Plant

CG&E, CSP, and DP&L jointly own electric generating units and related transmission facilities.  PSI is a joint-owner of Gibson Station Unit No. 5 with Wabash Valley Power Association, Inc. (WVPA), and Indiana Municipal Power Agency (IMPA).  Additionally, PSI is a joint-owner with WVPA and IMPA of certain transmission property and local facilities.  These facilities constitute part of the integrated transmission and distribution systems, which are operated and maintained by PSI.  The Statements of Income reflect CG&E’s and PSI’s portions of all operating costs associated with the jointly-owned facilities.

As of December 31, 2002, CG&E’s and PSI’s investments in jointly-owned plant or facilities were as follows:

(in millions)

	Ownership Share		Property, Plant, and Equipment	Accumulated Depreciation	Construction Work in Progress
CG&E
Production:
Miami Fort Station (Units 7 and 8)	64.00	%	$288	$135	$34
Beckjord Station (Unit 6)	37.50		46	30	—
Stuart Station(1)	39.00		298	157	67
Conesville Station (Unit 4)(1)	40.00		77	48	—
Zimmer Station	46.50		1,239	402	23
East Bend Station	69.00		398	200	—
Killen Station(1)	33.00		187	110	17
Transmission	Various		85	38	—
PSI
Production:
Gibson Station (Unit 5)	50.05		215	119	14
Transmission and local facilities	94.37		2	1	—

(1)Station is not operated by CG&E.

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13. Quarterly Financial Data (unaudited)

	First Quarter			Second Quarter		Third Quarter			Fourth Quarter			Total
	(in millions, except per share amounts)
Cinergy(1)
2002
Results of Operations:
Operating Revenues(2)	$	986		$	923	$	1,134		$	1,082		$	4,125
Operating Income	213			137		239			215			804
Income before discontinued operations and cumulative effect of a change in accounting principle	96			45		131			125			397
Discontinued operations, net of tax(3)	—			—		—			(25		)	(25		)
Cumulative effect of a change in accounting principle, net of tax(4)	(11		)	—		—			—			(11		)
Net Income	$	85		$	45	$	131		$	100		$	361
Per Share Data:
EPS
Income before discontinued operations and cumulative effect of a change in accounting principle	0.58			0.27		0.78			0.74			2.37
Discontinued operations, net of tax(3)	—			—		—			(0.15		)	(0.15		)
Cumulative effect of a change in accounting principle, net of tax(4)	(0.06		)	—		—			—			(0.06		)
Net Income	$	0.52		$	0.27	$	0.78		$	0.59		$	2.16
EPS - assuming dilution
Income before discontinued operations and cumulative effect of a change in accounting principle	0.58			0.26		0.77			0.73			2.34
Discontinued operations, net of tax(3)	—			—		—			(0.15		)	(0.15		)
Cumulative effect of a change in accounting principle, net of tax(4)	(0.06		)	—		—			—			(0.06		)
Net Income	$	0.52		$	0.26	$	0.77		$	0.58		$	2.13
2001
Results of Operations:
Operating Revenues(2)	$	1,147		$	907	$	1,041		$	955		$	4,050
Operating Income	249			178		278			239			944
Income before discontinued operations	121			82		130			126			459
Discontinued operations, net of tax(3)	(1		)	1		(2		)	(15		)	(17		)
Net Income	$	120		$	83	$	128		$	111		$	442
Per Share Data:
EPS
Income before discontinued operations	0.76			0.50		0.82			0.80			2.88
Discontinued operations, net of tax(3)	—			0.01		(0.01		)	(0.10		)	(0.10		)
Net Income	$	0.76		$	0.51	$	0.81		$	0.70		$	2.78
EPS - assuming dilution
Income before discontinued operations	0.75			0.50		0.81			0.79			2.85
Discontinued operations, net of tax(3)	—			0.01		(0.01		)	(0.10		)	(0.10		)
Net Income	$	0.75		$	0.51	$	0.80		$	0.69		$	2.75
CG&E and subsidiaries
2002
Results of Operations:
Operating Revenues(2)	$	577		$	466	$	534		$	560		$	2,137
Operating Income	155			101		135			114			505
Net Income	78			53		72			61			264
2001
Results of Operations:
Operating Revenues(2)	$	718		$	469	$	514		$	546		$	2,247
Operating Income	154			98		166			194			612
Net Income	82			49		89			107			327
PSI
2002
Results of Operations:
Operating Revenues(2)	$	366		$	378	$	471		$	396		$	1,611
Operating Income	74			52		120			136			382
Net Income	38			30		68			78			214
2001
Results of Operations:
Operating Revenues(2)	$	361		$	369	$	469		$	375		$	1,574
Operating Income	85			66		110			69			330
Net Income	41			34		57			30			162

(1)The results of Cinergy also include amounts related to non-registrants.

(2)See Note 20 for further information.

(3)See Note 15 for further explanation.

(4)Upon implementation of Statement 142, Cinergy recognized a non-cash impairment charge of $11 million, net of tax, for goodwill related to certain international assets.  See Note 14 for further information.

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14. Effects of a Change in Accounting Principle

Cinergy finalized its transition goodwill impairment test, as required by Statement 142, in the fourth quarter of 2002 and recognized a non-cash impairment charge of $11 million (net of tax) for goodwill related to certain of our international assets.  This amount is reflected in Cinergy Corp.’s Statements of Income as a Cumulative effect of a change in accounting principle.  While Statement 142 did not require the initial transition impairment test to be completed until December 31, 2002, it does require any transition impairment charge to be reflected as of January 1, 2002.  The condensed financial results below revise previously reported results of Cinergy Corp. as filed in the Form 10-Q for the quarter ended March 31, 2002, to reflect the impairment charge as of January 1, 2002.

	Year to Date March 31, 2002
	Net Income			EPS(1)
	(in millions, except for EPS)
	(unaudited)
Reported results	$	96		$	0.58
Cumulative effect of a change in accounting principle	(11		)	(0.06		)
Revised results	$	85		$	0.52

(1)Represents EPS and EPS - assuming dilution.

15. Monetization of Non-Core Investments

During 2002, Cinergy began taking steps to monetize certain non-core investments, including renewable and international investments within the Energy Merchant business unit.   During the second half of the year, Cinergy either sold or initiated plans to dispose of generation and electric and gas distribution operations in the Czech Republic, Estonia, and South Africa.  Cinergy also sold investments, which were accounted for under the equity method, in renewable investments located in Spain and California.  In total, Cinergy disposed of approximately $125 million of investments at a net loss of $7 million in 2002.  Included in this net loss were cumulative foreign currency translation losses of approximately $4 million.

GAAP requires different accounting treatment for investment disposals involving entities which are consolidated and entities which are accounted for under the equity method.  The consolidated entities have been presented as Discontinued operations, net of tax in Cinergy’s accompanying financial statements, and prior year financial statements have been reclassified to account for these entities as such.  The disposal of the entities accounted for using the equity method are not allowed to be presented as discontinued operations.  A gain of approximately $17 million on the sale of these entities is included in Miscellaneous-Net in Cinergy’s Statements of Income.

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The table below reflects the assets and liabilities of the investments accounted for as discontinued operations as of December 31, 2002 and 2001, and the results of operations and the loss on disposal for the years then ended.

	December 31
	2002		2001
	(in millions)
Revenues(1)	$	30	$	38
Loss on Discontinued Operations
Loss on operations	$	1	$	17
Loss on disposal(2)	24		—
Total Loss on Discontinued Operations	$	25	$	17
Assets
Current assets	$	—	$	8
Property, plant, and equipment-net	—		45
Other assets	1		9
Total Assets	$	1	$	62
Liabilities
Current liabilities	$	2	$	16
Total Liabilities	$	2	$	16

(1)Presented for informational purposes only.  All results of operations are reported net in our Statements of Income.

(2)Approximately $17 million of this amount represents a write-down to fair value, less cost to sell, on assets classified as held for sale.  The remainder represents actual losses on completed sales.  Included in the loss on disposal are cumulative foreign currency translation losses of approximately $4 million.

The losses included in discontinued operations primarily pertain to two investments.  In one case, the primary customer of a combined heat and power plant filed for bankruptcy resulting in a significant reduction in future expected revenues from the investment.  In the second case, the retail market of a gas distribution business did not develop as expected, and we have elected to exit the business rather than invest the additional capital which would be required to reach a sustainable level of market penetration.

16.Financial Information by Business Segment

We conduct operations through our subsidiaries and manage through the following three business units:

•Energy Merchant;

•Regulated Businesses; and

•Power Technology.

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The following section describes the activities of our business units as of December 31, 2002.

Energy Merchant manages wholesale generation and energy marketing and trading of energy commodities.  Energy Merchant operates and maintains our regulated and non-regulated electric generating plants, including some of our jointly-owned plants.  Energy Merchant is also responsible for our international operations and performs the following activities:

•energy risk management;

•proprietary arbitrage activities; and

•customized energy solutions.

Regulated Businesses consists of PSI’s regulated, integrated utility operations, and Cinergy’s other regulated electric and gas transmission and distribution systems.  Regulated Businesses plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers.  Regulated Businesses also earns revenues from wholesale customers primarily by transmitting electric power through Cinergy’s transmission system.

Power Technology primarily manages the development, marketing, and sales of our non-regulated retail energy and energy-related businesses.  This is accomplished through various subsidiaries and joint ventures.  Power Technology also manages Cinergy Ventures, LLC (Ventures), Cinergy’s venture capital subsidiary.  Ventures invests in emerging energy technologies that can benefit future Cinergy business development activities.

Following are the financial results by business unit.  Certain amounts for prior years have been restated to reflect segment restructuring, which includes the consolidation of all of our international operations into Energy Merchant.  This restructuring became effective January 1, 2002.

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Financial results by business unit for the years ended December 31, 2002, 2001, and 2000, are as indicated below:

Business Units

	2002
	Cinergy Business Units
	Energy Merchant			Regulated Businesses		Power Technology			Total			All Other(1)		Reconciling Eliminations(2)			Consolidated
	(in millions)
Operating revenues (10)
External customers	$	1,448		$	2,640	$	37		$	4,125		$	—	$	—		$	4,125
Intersegment revenues (3)	160			—		—			160			—		(160		)	—
Cost of sales (10) -
Fuel and purchased and exchanged power	577			458		—			1,035			—		—			1,035
Gas purchased	77			233		—			310			—		—			310
Depreciation(4)	158			249		7			414			—		—			414
Equity in earnings (losses) of unconsolidated subsidiaries	20			5		(10		)	15			—		—			15
Interest(5)	103			133		14			250			—		—			250
Income taxes	21		(6)	151		(15		)	157			—		—			157
Discontinued operations, net of tax(7)	(25		)	—		—			(25		)	—		—			(25		)
Cumulative effect of a change in accounting principle, net of tax(8)	(11		)	—		—			(11		)	—		—			(11		)
Segment profit (loss)(9)	126			270		(35		)	361			—		—			361
Total segment assets	5,703			7,284		227			13,214			93		—			13,307
Investments in unconsolidated subsidiaries	337			10		70			417			—		—			417
Total expenditures for long-lived assets	188			681		1			870			—		—			870

(1)	The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.
(2)	The Reconciling Eliminations category eliminates the intersegment revenues and expenses of Energy Merchant.
(3)	In connection with deregulation in Ohio, beginning in 2001, certain revenues, which were previously recorded through intersegment transfer pricing, are now directly recorded to the business segment.
(4)	The components of Depreciation include depreciation of fixed assets and amortization of intangible assets.
(5)	Interest income is deemed immaterial.
(6)	The decrease in 2002, as compared to 2001, in part reflects the effect of tax credits associated with production of synthetic fuel beginning in July 2002.
(7)	For further information, see Note 15.
(8)	Upon implementation of Statement 142, Cinergy recognized a non-cash impairment charge of $11 million, net of tax, for goodwill related to certain international assets.  See Note 14 for further information.
(9)	Management utilizes Segment profit (loss), after taxes, to evaluate segment performance.
(10)	See Note 20 for further information.

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	2001
	Cinergy Business Units
	Energy Merchant			Regulated Businesses		Power Technology			Total			All Other(1)		Reconciling Eliminations(2)			Consolidated
	(in millions)
Operating revenues (8) -
External customers	$	1,298		$	2,703	$	49		$	4,050		$	—	$	—		$	4,050
Intersegment revenues(3)	144			—		—			144			—		(144		)	—
Cost of sales (8) -
Fuel and purchased and exchanged power	624			469		—			1,093			—		—			1,093
Gas purchased	—			397		—			397			—		—			397
Depreciation(4)	135			236		3			374			—		—			374
Equity in earnings (losses) of unconsolidated subsidiaries	9			—		(8		)	1			—		—			1
Interest(5)	110			142		14			266			—		—			266
Income taxes	96			169		(9		)	256			—		—			256
Discontinued operations, net of tax(6)	(17		)	—		—			(17		)	—		—			(17		)
Segment profit (loss)(7)	195			266		(19		)	442			—		—			442
Total segment assets	4,957			7,084		213			12,254			46		—			12,300
Investments in unconsolidated subsidiaries	256			—		76			332			—		—			332
Total expenditures for long-lived assets	764			633		—			1,397			—		—			1,397

(1)The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.

(2)The Reconciling Eliminations category eliminates the intersegment revenues and expenses of Energy Merchant.

(3)In connection with deregulation in Ohio, beginning in 2001, certain revenues, which were previously recorded through intersegment transfer pricing, are now directly recorded to the business segment.

(4)The components of Depreciation include depreciation of fixed assets and amortization of intangible assets.

(5)Interest income is deemed immaterial.

(6)For further information, see Note 15.

(7)Management utilizes Segment profit (loss), after taxes, to evaluate segment performance.

(8)See Note 20 for further information.

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	2000
	Cinergy Business Units
	Energy Merchant			Regulated Businesses		Power Technology			Total			All Other(1)		Reconciling Eliminations(2)			Consolidated
	(in millions)
Operating revenues (7)-
External customers	$	358		$	3,347	$	76		$	3,781		$	—	$	—		$	3,781
Intersegment revenues	1,021			—		—			1,021			—		(1,021		)	—
Cost of sales (7) -
Fuel and purchased and exchanged power	511			414		—			925			—		—			925
Gas purchased	—			267		6			273			—		—			273
Depreciation(3)	119			220		3			342			—		—			342
Equity in earnings (losses) of unconsolidated subsidiaries	7			—		(1		)	6			—		—			6
Interest(4)	82			133		9			224			—		—			224
Income taxes	93			166		(7		)	252			—		—			252
Discontinued operations, net of tax(5)	(1		)	—		—			(1		)	—		—			(1		)
Segment profit (loss)(6)	157			255		(13		)	399			—		—			399
Total segment assets	5,995			6,116		177			12,288			42		—			12,330
Investments in unconsolidated subsidiaries	488			—		52			540			—		—			540
Total expenditures for long-lived assets	138			397		—			535			3		—			538

(1)The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.

(2)The Reconciling Eliminations category eliminates the intersegment revenues and expenses of Energy Merchant.

(3)The components of Depreciation include depreciation of fixed assets and amortization of intangible assets.

(4)Interest income is deemed immaterial.

(5)For further information, see Note 15.

(6)Management utilizes Segment profit (loss), after taxes, to evaluate segment performance.

(7)See Note 20 for further information.

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Products and Services

(in millions)

	Revenues (1)
	Utility						Energy Marketing and Trading
Year	Electric		Gas		Total		Electric		Gas		Total		Other		Consolidated
2002	$	2,197	$	436	$	2,633	$	1,206	$	154	$	1,360	$	132	$	4,125
2001	2,101		595		2,696		1,214		61		1,275		79		4,050
2000	2,851		497		3,348		294		43		337		96		3,781

(1)  See Note 20 for further information. 

Geographic Areas

Revenues (1)

(in millions)

Year	Domestic		International		Consolidated
2002	$	4,011	$	114	$	4,125
2001	3,913		137		4,050
2000	3,721		60		3,781

Long-Lived Assets

(in millions)

Year	Domestic		International		Consolidated
2002	$	10,276	$	393	$	10,669
2001	9,682		428		10,110
2000	8,267		290		8,557

(1)  See Note 20 for further information. 

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17. Earnings Per Common Share

A reconciliation of EPS to EPS - assuming dilution is presented below:

	Income			Shares	EPS
	(in thousands, except per share amounts)
Year ended December 31, 2002
EPS:
Income before discontinued operations and cumulative effect of a change in accounting principle	$	396,903			$	2.37
Discontinued operations, net of tax	(25,428		)		(0.15		)
Cumulative effect of a change in accounting principle, net of tax	(10,899		)		(0.06		)
Net income	$	360,576		167,047	$	2.16
Effect of dilutive securities:
Common stock options				899
Employee Stock Purchase and Savings Plan				3
Directors’ compensation plans				169
Contingently issuable common stock				934
EPS - assuming dilution:
Net income plus assumed conversions	$	360,576		169,052	$	2.13
Year ended December 31, 2001
EPS:
Income before discontinued operations and cumulative effect of a change in accounting principle	$	458,826			$	2.88
Discontinued operations, net of tax	(16,547		)		(0.10		)
Net income	$	442,279		159,110	$	2.78
Effect of dilutive securities:
Common stock options				975
Directors’ compensation plans				152
Contingently issuable common stock				810
EPS - assuming dilution:
Net income plus assumed conversions	$	442,279		161,047	$	2.75
Year ended December 31, 2000
EPS:
Income before discontinued operations and cumulative effect of a change in accounting principle	$	400,535			$	2.52
Discontinued operations, net of tax	(1,069		)		(0.01		)
Net income	$	399,466		158,938	$	2.51
Effect of dilutive securities:
Common stock options				491
Directors’ compensation plans				177
Contingently issuable common stock				262
EPS - assuming dilution:
Net income plus assumed conversions	$	399,466		159,868	$	2.50

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Options to purchase shares of common stock are excluded from the calculation of EPS - assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period.  For the years 2002, 2001, and 2000, approximately 3 million, 2.1 million, and 1.9 million shares, respectively, were excluded from the EPS - assuming dilution calculation.

Also excluded from the EPS - assuming dilution calculation for the years ended December 31, 2002 and 2001, are up to 10.8 million shares issuable pursuant to the stock purchase contracts associated with the preferred trust securities issued by Cinergy Corp. in December 2001.  These stock purchase contracts would impact EPS - assuming dilution only to the extent that Cinergy’s average stock price were to exceed $34.40 per share, which is the maximum price payable by the holders of the stock purchase contracts, during any period for which earnings per share are presented.  As discussed in Note 2(e), the number of shares issued pursuant to the stock purchase contracts is contingent upon the market price of Cinergy Corp. stock in February 2005 and could range between 9.2 and 10.8 million shares.

18. Ohio Deregulation

On July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill), beginning the transition to electric deregulation and customer choice for the state of Ohio.  The Electric Restructuring Bill created a competitive electric retail service market effective January 1, 2001.  The legislation provided for a market development period that began January 1, 2001, and ends no later than December 31, 2005.

On May 8, 2000, CG&E reached a stipulated agreement with the PUCO staff and various other interested parties with respect to its proposal to implement electric customer choice in Ohio effective January 1, 2001.  On August 31, 2000, the PUCO approved CG&E’s stipulation agreement.  The major features of the agreement include:

•Residential customer rates are frozen through December 31, 2005;

•Residential customers received a five-percent reduction in the generation portion of their electric rates, effective January 1, 2001;

•CG&E will provide $4 million from 2001 to 2005 in support of energy efficiency and weatherization services for low income customers;

•CG&E will provide shopping credits to switching customers;

•The creation of a RTC designed to recover CG&E’s regulatory assets and other transition costs over a ten-year period;

•Authority for CG&E to transfer its generation assets to one or more, non-regulated affiliates to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;

•Authority for CG&E to apply the proceeds of transition cost recovery to costs incurred during the transition period, including implementation costs and purchased power costs that may be incurred by CG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;

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•Authority for CG&E to adjust the amortization of its regulatory assets and other transition costs to reflect the effects of any shopping incentives provided to customers; and

•CG&E will provide standard offer default supplier service (i.e., CG&E will be the supplier of last resort, so that no customer will be without an electric supplier).

Subsequent to the PUCO’s approval of CG&E’s stipulation agreement, two parties filed applications for rehearing with the PUCO.  In October 2000, the PUCO denied these applications.  One of the parties appealed to the Ohio Supreme Court in the fourth quarter of 2000 and CG&E subsequently intervened in that case.  In April 2002, the Ohio Supreme Court affirmed the PUCO’s stipulated agreement with CG&E with respect to implementing electric customer choice.  The Ohio Supreme Court ruling leaves CG&E’s transition plan entirely intact.

Under CG&E’s transition plan, retail customers continue to receive transportation services from CG&E, but may purchase electricity from another supplier.  Retail customers that purchase electricity from another supplier receive shopping credits from CG&E.  The shopping credits generally reflect the costs of electric generation included in CG&E’s frozen rates.  However, shopping credits for the first 20 percent of electricity usage in each customer class to switch suppliers are higher than CG&E’s electric generation costs in order to stimulate the development of the competitive retail electric service market.

CG&E recovers its regulatory assets and other transition costs through a RTC paid by all retail customers.  As the RTC is collected from customers, CG&E amortizes the deferred balance of regulatory assets and other transition costs.  A portion of the RTC collected from customers is recognized currently as a return on the deferred balance of regulatory assets and other transition costs and as reimbursement for the difference in the shopping credits provided to customers and the wholesale revenues from switched generation.  The ability of CG&E to recover its regulatory assets and other transition costs is dependent on several factors, including, but not limited to, the level of CG&E’s electric sales, prices in the wholesale power markets, and the amount of customers switching to other electric suppliers.

On January 10, 2003, CG&E filed an application with the PUCO for approval of a methodology to establish how market-based rates for non-residential customers will be determined when the market development period ends.  In the filing, CG&E seeks to establish a market-based standard service offer rate for non-residential customers that do not switch suppliers and a process for establishing the competitively-bid generation service option required by the Electric Restructuring Bill.  As of December 31, 2002, more than 20 percent of the load in each of CG&E’s non-residential customer classes has switched to other electric suppliers.  Under its transition plan, CG&E may end the market development period for those classes of customers once 20 percent switching has been achieved; however, PUCO approval of the standard service offer rate and competitive bidding process is required before the market development period can be ended.  CG&E is not requesting to end the market development period for non-residential customers at this time.  CG&E is unable to predict the outcome of this proceeding.

In its transition plan, CG&E proposed to transfer its generating stations and their related assets and obligations to an Exempt Wholesale Generator (EWG) affiliate, subject to receipt of FERC, SEC, and applicable third-party approvals and consents.

100

To facilitate this transfer, the generation assets of CG&E, as of August 2000, were released from the first mortgage indenture lien allowing them to move unencumbered to the EWG affiliate.  Generation assets added after August 2000 remain subject to the lien of CG&E’s first mortgage bond indenture and would require release at some future date prior to being transferred.  A FERC order, that was effective April 2002, allowed Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E.  FERC has also authorized the transfer of the CG&E generating assets to a non-regulated affiliate.  However, Cinergy has determined that it can realize the benefits of the new joint dispatch agreement without transferring CG&E’s generation assets to an EWG affiliate, and therefore Cinergy does not plan to transfer CG&E’s generation assets to a non-regulated affiliate in the foreseeable future.

101

19. Comprehensive Income

The elements of Comprehensive income and their related tax effects for the years ended December 31, 2002, 2001, and 2000 are as follows:

	Comprehensive Income
	2002									2001									2000
	Before-tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount			Before-tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount			Before-tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
										(dollars in thousands)
Cinergy(1)
Net income	$	518,840		$	(158,264	)	$	360,576		$	697,785		$	(255,506	)	$	442,279		$	651,023		$	(251,557	)	$	399,466
Other comprehensive income (loss)
Foreign currency translation adjustment	35,574			(14,034		)	21,540			4,996			(3,355		)	1,641			721			1,353			2,074
Reclassification adjustments	4,377			—			4,377			—			—			—			—			—			—
Total foreign currency translation adjustment	39,951			(14,034		)	25,917			4,996			(3,355		)	1,641			721			1,353			2,074
Minimum pension liability adjustment	(23,031		)	9,268			(13,763		)	(2,636		)	1,081			(1,555		)	(1,852		)	753			(1,099		)
Unrealized gain (loss) on investment trusts	(8,637		)	3,360			(5,277		)	(1,345		)	504			(841		)	(2,778		)	649			(2,129		)
Cumulative effect of change in accounting principle	—			—			—			(4,026		)	1,526			(2,500		)	—			—			—
Cash flow hedges	(32,663		)	12,915			(19,748		)	(4,477		)	1,698			(2,779		)	—			—			—
Total other comprehensive income (loss)	(24,380		)	11,509			(12,871		)	(7,488		)	1,454			(6,034		)	(3,909		)	2,755			(1,154		)
Total comprehensive income	$	494,460		$	(146,755	)	$	347,705		$	690,297		$	(254,052	)	$	436,245		$	647,114		$	(248,802	)	$	398,312
CG&E
Net income	$	419,037		$	(155,341	)	$	263,696		$	513,181		$	(186,527	)	$	326,654		$	426,218		$	(159,398	)	$	266,820
Other comprehensive income (loss)
Minimum pension liability adjustment	(1,423		)	551			(872		)	106			28			134			(43		)	15			(28		)
Unrealized gain (loss) on investment trusts	(745		)	283			(462		)	743			(282		)	461			—			—			—
Cumulative effect of change in accounting principle	—			—			—			(4,026		)	1,526			(2,500		)	—			—			—
Cash flow hedges	(30,960		)	12,226			(18,734		)	(4,477		)	1,698			(2,779		)	—			—			—
Total other comprehensive income (loss)	(33,128		)	13,060			(20,068		)	(7,654		)	2,970			(4,684		)	(43		)	15			(28		)
Total comprehensive income	$	385,909		$	(142,281	)	$	243,628		$	505,527		$	(183,557	)	$	321,970		$	426,175		$	(159,383	)	$	266,792
PSI
Net income	$	328,958		$	(114,709	)	$	214,249		$	268,419		$	(106,086	)	$	162,333		$	223,945		$	(88,547	)	$	135,398
Other comprehensive income (loss)
Minimum pension liability adjustment	(3,534		)	1,396			(2,138		)	(76		)	27			(49		)	(76		)	29			(47		)
Unrealized gain (loss) on investment trusts	(7,179		)	2,793			(4,386		)	(1,537		)	511			(1,026		)	(2,419		)	555			(1,864		)
Total other comprehensive income (loss)	(10,713		)	4,189			(6,524		)	(1,613		)	538			(1,075		)	(2,495		)	584			(1,911		)
Total comprehensive income	$	318,245		$	(110,520	)	$	207,725		$	266,806		$	(105,548	)	$	161,258		$	221,450		$	(87,963	)	$	133,487

(1)The results of Cinergy also include amounts related to non-registrants.  Individual amounts for ULH&P are immaterial.

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The after-tax components of Accumulated other comprehensive income (loss) as of December 31, 2002, 2001, and 2000 are as follows:

	Accumulated Other Comprehensive Income (Loss) Classification
	Foreign Currency Translation Adjustment			Minimum Pension Liability Adjustment			Unrealized Gain (Loss) on Investment Trusts			Cash Flow Hedges			Total Other Comprehensive Income (Loss)
	(dollars in thousands)
Cinergy(1)
Balance at December 31, 1999	$	(8,146	)	$	(3,681	)	$	2,086		$	—		$	(9,741	)
Current-period change	2,074			(1,099		)	(2,129		)	—			(1,154		)
Balance at December 31, 2000	$	(6,072	)	$	(4,780	)	$	(43	)	$	—		$	(10,895	)
Cumulative effect of change in accounting principle	—			—			—			(2,500		)	(2,500		)
Current-period change	1,641			(1,555		)	(841		)	(2,779		)	(3,534		)
Balance at December 31, 2001	$	(4,431	)	$	(6,335	)	$	(884	)	$	(5,279	)	$	(16,929	)
Current-period change	25,917			(13,763		)	(5,277		)	(19,748		)	(12,871		)
Balance at December 31, 2002	$	21,486		$	(20,098	)	$	(6,161	)	$	(25,027	)	$	(29,800	)
CG&E
Balance at December 31, 1999	$	—		$	(966	)	$	—		$	—		$	(966	)
Current-period change	—			(28		)	—			—			(28		)
Balance at December 31, 2000	$	—		$	(994	)	$	—		$	—		$	(994	)
Cumulative effect of change in accounting principle	—			—			—			(2,500		)	(2,500		)
Current-period change	—			134			461			(2,779		)	(2,184		)
Balance at December 31, 2001	$	—		$	(860	)	$	461		$	(5,279	)	$	(5,678	)
Current-period change	—			(872		)	(462		)	(18,734		)	(20,068		)
Balance at December 31, 2002	$	—		$	(1,732	)	$	(1	)	$	(24,013	)	$	(25,746	)
PSI
Balance at December 31, 1999	$	—		$	(658	)	$	2,049		$	—		$	1,391
Current-period change	—			(47		)	(1,864		)	—			(1,911		)
Balance at December 31, 2000	$	—		$	(705	)	$	185		$	—		$	(520	)
Current-period change	—			(49		)	(1,026		)	—			(1,075		)
Balance at December 31, 2001	$	—		$	(754	)	$	(841	)	$	—		$	(1,595	)
Current-period change	—			(2,138		)	(4,386		)	—			(6,524		)
Balance at December 31, 2002	$	—		$	(2,892	)	$	(5,227	)	$	—		$	(8,119	)

(1)The results of Cinergy also include amounts related to non-registrants.  Individual amounts for ULH&P are immaterial.

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20.Change in Method of Revenue Presentation for Energy Trading Derivatives

In October 2002, the EITF reached consensus in EITF 02-3 to require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically. This consensus was effective beginning January 1, 2003, and required reclassification for all periods presented.  See Note 1 for discussion of accounting policies, including revisions to reflect the adoption of EITF 02-3.

We have reclassified amounts in our Statements of Income, as well as segment disclosures in Note 16, in accordance with EITF 02-3.  The table below presents the effect of the change in revenue presentation on Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense for the years ended December 31.  Operating Income and Net Income were not affected by this change.

	2002			2001			2000
	(in thousands)
Cinergy(1)
Electric Operating Revenues as previously reported	$	6,912,349		$	8,255,847		$	5,359,358
Adjustment for effect of EITF 02-3 implementation	(3,509,109		)	(4,940,218		)	(2,214,658		)
Electric Operating Revenues as adjusted	3,403,240			3,315,629			3,144,700
Gas Operating Revenues as previously reported	4,916,919			4,662,916			2,941,753
Adjustment for effect of EITF 02-3 implementation	(4,326,448		)	(4,007,238		)	(2,401,670		)
Gas Operating Revenues as adjusted	590,471			655,678			540,083
Fuel and purchased and exchange power expense as previously reported	4,511,891			6,005,803			3,139,274
Adjustment for effect of EITF 02-3 implementation	(3,476,599		)	(4,912,867		)	(2,214,658		)
Fuel and purchased and exchanged power expense as adjusted	1,035,292			1,092,936			924,616
Gas purchased expense as previously reported	4,668,941			4,431,899			2,674,449
Adjustment for effect of EITF 02-3 implementation	(4,358,958		)	(4,034,589		)	(2,401,670		)
Gas purchased expense as adjusted	309,983			397,310			272,779

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CG&E	2002			2001			2000
	(in thousands)
Electric Operating Revenues as previously reported	$	4,514,283		$	4,155,827		$	2,745,852
Adjustment for effect of EITF 02-3 implementation	(2,813,965		)	(2,504,786		)	(1,136,028		)
Electric Operating Revenues as adjusted	1,700,318			1,651,041			1,609,824
Fuel and purchased and exchange power expense as previously reported	3,286,278			2,940,442			1,562,036
Adjustment for effect of EITF 02-3 implementation	(2,813,965		)	(2,504,786		)	(1,136,028		)
Fuel and purchased and exchanged power expense as adjusted	472,313			435,656			426,008
PSI
Electric Operating Revenues as previously reported	$	2,359,178		$	4,108,182		$	2,691,274
Adjustment for effect of EITF 02-3 implementation	(748,600		)	(2,534,491		)	(1,179,772		)
Electric Operating Revenues as adjusted	1,610,578			1,573,691			1,511,502
Fuel and purchased and exchange power expense as previously reported	1,275,960			3,165,652			1,731,733
Adjustment for effect of EITF 02-3 implementation	(748,600		)	(2,534,491		)	(1,179,772		)
Fuel and purchased and exchanged power expense as adjusted	527,360			631,161			551,961

(1)The results of Cinergy also include amounts related to non-registrants and includes the elimination of certain intercompany amounts.

21.Subsequent Events

(a)Common Stock

On January 15, 2003, Cinergy Corp. filed a registration statement with respect to the issuance of common stock, preferred stock, and other securities with an aggregate amount of $750 million.  On February 5, 2003, Cinergy sold 5.7 million shares of common stock of Cinergy Corp. with net proceeds of approximately $175 million under this registration statement.  The net proceeds from the transaction will be used to reduce short-term debt of Cinergy Corp. and for other general corporate purposes.

As discussed in Note 2(a), Cinergy currently issues new Cinergy Corp. common stock shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan.  During the five month period ended May 31, 2003, Cinergy issued approximately 2.5 million shares under these plans.

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(b)Transfer of Generating Assets

On February 4, 2003, the FERC issued an order under Section 203 of the Federal Power Act authorizing PSI’s proposed acquisition of the Henry County, Indiana, and Butler County, Ohio, gas-fired peaking power plants from two non-regulated affiliates.  This action was the final regulatory approval needed for the transfer, which occurred on February 5, 2003.  In December 2002, the IURC approved a settlement agreement among PSI, the Indiana Office of the Utility Consumer Counselor, and the IURC Testimonial Staff authorizing PSI’s purchase of the plants.  Subsequently, in April 2003, the FERC issued a tolling order allowing additional time to consider a request for rehearing filed in response to the February 2003 FERC order.  At this time, we cannot predict the outcome of this matter.

(c)Long-term Debt

In October 2002, PSI filed a petition with the IURC for the purpose of securing authorization and approval to issue two promissory notes to Cinergy Corp. for the acquisition of the Butler County, Ohio and Henry County, Indiana peaking plants.  In January 2003, the IURC granted this request, and in February 2003, PSI issued the notes.  One promissory note was for the principal amount of $200 million with an annual interest rate of 6.302% and will mature on April 15, 2004.  The second promissory note was for $176 million with an annual interest rate of 6.403% and will mature on September 1, 2004.

(d)PSI Fuel Adjustment Charge

In March 2003 the IURC issued an order giving final approval to PSI’s recovery of $16 million in under billed deferred fuel costs, see Note 11(j) for further information.

(e)Asset Retirement Obligations

We adopted Statement 143 on January 1, 2003, and Cinergy and CG&E both recognized a gain of $39 million (net of tax) for the cumulative effect of this change in accounting principle.  Substantially all of this adjustment reflects the reversal of previously accrued cost of removal for CG&E’s generating assets, which do not apply Statement 71.  Accumulated Depreciation at adoption includes $316 million, $25 million, and $146 million of accumulated cost of removal related to PSI’s, ULH&P’s, and CG&E’s utility plant in service assets, respectively, which represent regulatory liabilities and were not included as part of the cumulative effect adjustment.  The increases in assets and liabilities from adopting Statement 143 were not material to our financial position.

Pro-forma results as if Statement 143 was applied retroactively for the years ended December 31, 2002, 2001, and 2000 are not materially different from reported results.

(f)Revolving Credit Facility

In April 2003, Cinergy Corp. successfully placed a $600 million, 364-day senior unsecured revolving credit facility.  This facility replaces a $600 million, 364-day facility that expired April 30, 2003.

106

FINANCIAL STATEMENT SCHEDULES

107

CINERGY CORP. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2002

(in thousands)

Col. A	Col. B		Col. C				Col. D				Col. E
			Additions				Deductions
Description	Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions
Deducted from Applicable Assets
Allowance for Doubtful Accounts
2002	$	34,110	$	7,883	$	9,270	$	34,867	$	22	$	16,374
2001	$	29,951	$	39,693	$	5,254	$	40,788	$	—	$	34,110
2000	$	26,811	$	22,746	$	4,486	$	24,092	$	—	$	29,951

108

THE CINCINNATI GAS & ELECTRIC COMPANY AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2002

(in thousands)

Col. A	Col. B		Col. C				Col. D				Col. E
			Additions				Deductions
Description	Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions
Deducted from Applicable Assets
Allowance for Doubtful Accounts
2002	$	25,874	$	2,029	$	6,096	$	28,057	$	—	$	5,942
2001	$	19,044	$	30,166	$	4,089	$	27,425	$	—	$	25,874
2000	$	16,740	$	14,056	$	4,486	$	16,238	$	—	$	19,044

109

PSI ENERGY, INC. AND SUBSIDIARY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2002

(in thousands)

Col. A	Col. B		Col. C				Col. D				Col. E
			Additions				Deductions
Description	Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions
Deducted from Applicable Assets
Allowance for Doubtful Accounts
2002	$	6,773	$	2,310	$	3,174	$	6,579	$	22	$	5,656
2001	$	9,317	$	8,339	$	1,165	$	12,048	$	—	$	6,773
2000	$	9,934	$	7,088	$	—	$	7,705	$	—	$	9,317

110

THE UNION LIGHT, HEAT AND POWER COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2002

(in thousands)

Col. A	Col. B		Col. C				Col. D				Col. E
			Additions				Deductions
Description	Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions
Deducted from Applicable Assets
Allowance for Doubtful Accounts
2002	$	1,196	$	392	$	2,383	$	3,887	$	—	$	84
2001	$	1,492	$	3,050	$	4	$	3,350	$	—	$	1,196
2000	$	1,513	$	2,555	$	746	$	3,322	$	—	$	1,492

111