Duke Energy Indiana 8K Financial statements and exhibits | SEC 19 Feb 02

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the financial statements of Cinergy Corp. (a Delaware Corporation), The Cincinnati Gas & Electric Company (an Ohio Corporation), PSI Energy, Inc. (an Indiana Corporation) and The Union Light, Heat and Power Company (a Kentucky Corporation), as of December 31, 2001 and 2000, and each of the three years in the period ended December 31, 2001, as listed under Exhibit 99.1 in the exhibit index. These financial statements referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

Arthur Andersen LLP
Cincinnati, Ohio
January 24, 2002

CINERGY CORP.
AND SUBSIDIARY COMPANIES

CINERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME

			2001		2000		1999
			(dollars in thousands, except per share amounts)
Operating Revenues
	Electric		$	8,181,233	$	5,384,082	$	4,312,899
	Gas			4,662,916		2,941,753		1,596,146
	Other			78,388		96,129		28,843

		Total Operating Revenues		12,922,537		8,421,964		5,937,888

Operating Expenses
	Fuel and purchased and exchanged power			5,910,959		3,154,213		2,260,297
	Gas purchased			4,431,899		2,674,449		1,383,993
	Operation and maintenance			1,032,031		1,119,379		1,011,606
	Depreciation			378,140		343,949		323,268
	Taxes other than income taxes			227,652		268,346		265,501

		Total Operating Expenses		11,980,681		7,560,336		5,244,665

Operating Income				941,856		861,628		693,223

Equity in Earnings (Losses) of Unconsolidated Subsidiaries				2,266		5,048		58,021
Gain on Sale of Investment in Unconsolidated Subsidiary(Note 11)				—		—		99,272
Miscellaneous — Net				26,290		13,391		2,031
Interest				268,127		224,459		234,778
Preferred Dividend Requirement of Subsidiary Trust(Note 4)				1,067		—		—

Income Before Taxes				701,218		655,608		617,769

Income Taxes(Note 12)				255,506		251,557		208,671
Preferred Dividend Requirements of Subsidiaries				3,433		4,585		5,457

Net Income			$	442,279	$	399,466	$	403,641

Average Common Shares Outstanding				159,110		158,938		158,863

Earnings Per Common Share(Note 17)
	Net Income		$	2.78	$	2.51	$	2.54

Earnings Per Common Share — Assuming Dilution(Note 17)
	Net Income		$	2.75	$	2.50	$	2.53

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.

CINERGY CORP.
CONSOLIDATED BALANCE SHEETS

				December 31
				2001		2000
				(dollars in thousands)
ASSETS
Current Assets
	Cash and cash equivalents			$	111,067	$	93,054
	Restricted deposits				8,055		4,195
	Notes receivable				31,173		35,945
	Accounts receivable less accumulated provision for doubtful accounts of $35,580 at December 31, 2001, and $29,951 at December 31, 2000 (Note 7)				1,123,214		1,623,402
	Materials, supplies, and fuel — at average cost				240,812		159,340
	Energy risk management current assets (Note 1(k))				449,397		1,438,233
	Prepayments and other				110,311		116,257

			Total Current Assets		2,074,029		3,470,426
Property, Plant, and Equipment — at Cost
	Utility plant in service				8,089,961		7,681,612
	Construction work in progress				464,560		323,350

		Total Utility Plant			8,554,521		8,004,962
	Non-regulated property, plant, and equipment				4,527,994		3,401,203
	Accumulated depreciation				4,845,620		4,586,089

			Net Property, Plant, and Equipment		8,236,895		6,820,076
Other Assets
	Regulatory assets (Note 1(c))				1,015,863		976,614
	Investments in unconsolidated subsidiaries				339,059		538,322
	Energy risk management non-current assets (Note 1(k))				134,445		37,228
	Other investments				164,155		146,986
	Goodwill				53,587		58,997
	Other intangible assets				22,250		18,500
	Other				259,530		262,579

			Total Other Assets		1,988,889		2,039,226
Total Assets				$	12,299,813	$	12,329,728

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

CINERGY CORP.
CONSOLIDATED BALANCE SHEETS

			December 31
			2001			2000
			(dollars in thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts payable		$	1,029,173		$	1,496,494
	Accrued taxes			195,976			247,006
	Accrued interest			56,216			47,351
	Notes payable and other short-term obligations (Note 6)			1,155,786			1,128,657
	Long-term debt due within one year (Note 5)			148,431			40,545
	Energy risk management current liabilities (Note 1(k))			429,794			1,456,375
	Other			127,375			106,679

		Total Current Liabilities		3,142,751			4,523,107
Non-Current Liabilities
	Long-term debt (Note 5)			3,596,730			2,876,367
	Deferred income taxes (Note 12)			1,301,407			1,185,968
	Unamortized investment tax credits			127,385			137,965
	Accrued pension and other postretirement benefit costs (Note 10)			438,962			404,764
	Energy risk management non-current liabilities (Note 1(k))			135,619			97,507
	Other			246,340			252,255

		Total Non-Current Liabilities		5,846,443			4,954,826
Total Liabilities				8,989,194			9,477,933
Preferred Trust Securities (Note 4)
	Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company			306,327			—
Cumulative Preferred Stock of Subsidiaries(Note 3)
	Not subject to mandatory redemption			62,833			62,834
Common Stock Equity(Note 2)
	Common Stock — $.01 par value; authorized shares — 600,000,000; outstanding shares — 159,402,839 at December 31, 2001, and 158,967,661 at December 31, 2000			1,594			1,590
	Paid-in capital			1,619,659			1,619,153
	Retained earnings			1,337,135			1,179,113
	Accumulated other comprehensive income (loss) (Note 19)			(16,929	)		(10,895	)

		Total Common Stock Equity		2,941,459			2,788,961
Commitments and Contingencies(Note 13)
Total Liabilities and Shareholders' Equity			$	12,299,813		$	12,329,728

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

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)
1999
Beginning balance			$	1,587	$	1,595,237		$	945,214		$	(807	)	$	2,541,231
Comprehensive income:
	Net income			—		—			403,641			—			403,641
	Other comprehensive income (loss), net of tax effect of $5,289 (Note 19)
		Foreign currency translation adjustment		—		—			—			(9,781	)		(9,781	)
		Minimum pension liability adjustment		—		—			—			(1,239	)		(1,239	)
		Unrealized gain (loss) on investment trusts		—		—			—			2,086			2,086

	Total comprehensive income			—		—			—			—			394,707
Issuance of 258,867 shares of common stock — net				2		6,720			—			—			6,722
Treasury shares purchased				—		(233	)		—			—			(233	)
Treasury shares reissued				—		3,660			—			—			3,660
Dividends on common stock ($1.80 per share)				—		—			(284,545	)		—			(284,545	)
Other				—		(7,830	)		9			—			(7,821	)

Ending balance			$	1,589	$	1,597,554		$	1,064,319		$	(9,741	)	$	2,653,721
2000
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		—		—			—			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 44,262 shares of common stock — net				1		1,769			—			—			1,770
Treasury shares purchased				—		(3,969	)		—			—			(3,969	)
Treasury shares reissued				—		11,008			—			—			11,008
Dividends on common stock ($1.80 per share)				—		—			(285,242	)		—			(285,242	)
Other				—		12,791			570			—			13,361

Ending balance			$	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		—		—			—			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		—		—			—			(2,500	)		(2,500	)
		Cash flow hedges(Note 1(l))		—		—			—			(2,779	)		(2,779	)

	Total comprehensive income			—		—			—			—			436,245
Issuance of 435,178 shares of common stock — net				4		9,896			—			—			9,900
Treasury shares purchased				—		(10,015	)		—			—			(10,015	)
Treasury shares reissued				—		9,157			—			—			9,157
Dividends on common stock($1.80 per share)				—		—			(286,289	)		—			(286,289	)
Stock purchase contracts(Note 4)				—		(23,200	)		—			—			(23,200	)
Other				—		14,668			2,032			—			16,700

Ending balance			$	1,594	$	1,619,659		$	1,337,135		$	(16,929	)	$	2,941,459

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

CINERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS

					2001			2000			1999
					(dollars in thousands)
Operating Activities
	Net income				$	442,279		$	399,466		$	403,641
	Items providing or (using) cash currently:
		Depreciation				378,140			343,949			323,268
		Change in net position of energy risk management activities				(96,850	)		(22,533	)		(47,192	)
		Deferred income taxes and investment tax credits — net				124,577			47,404			96,067
		Gain on sale of investment in unconsolidated subsidiary				—			—			(99,272	)
		Equity in earnings of unconsolidated subsidiaries				(2,266	)		(5,048	)		(44,904	)
		Allowance for equity funds used during construction				(8,628	)		(5,813	)		(3,633	)
		Regulatory assets deferrals				(141,324	)		(99,661	)		(306,340	)
		Regulatory assets amortization				118,508			92,856			103,116
		Changes in current assets and current liabilities:
				Restricted deposits		(1,409	)		(3,567	)		2,959
				Accounts and notes receivable, net of reserves on receivables sold		492,183			(963,309	)		(118,561	)
				Materials, supplies, and fuel		(81,465	)		46,409			(3,002	)
				Accounts payable		(469,965	)		761,557			61,590
				Accrued taxes and interest		(42,165	)		25,737			(11,406	)
	Other items — net					(17,203	)		554			121,936

			Net cash provided by (used in) operating activities			694,412			618,001			478,267
Financing Activities
	Change in short-term debt					27,129			578,463			(353,506	)
	Issuance of long-term debt					940,785			126,420			829,948
	Issuance of preferred trust securities					306,327			—			—
	Redemption of long-term debt					(131,413	)		(234,247	)		(553,191	)
	Retirement of preferred stock of subsidiaries					(1	)		(29,393	)		(34	)
	Issuance of common stock					9,900			1,770			6,722
	Dividends on common stock					(286,289	)		(285,242	)		(285,925	)

			Net cash provided by (used in) financing activities			866,438			157,771			(355,986	)
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)					(846,159	)		(514,193	)		(434,294	)
	Acquisitions and other investments					(696,678	)		(250,444	)		(396,491	)
	Sale of investment in unconsolidated subsidiary					—			—			690,269

		Net cash provided by (used in) investing activities				(1,542,837	)		(764,637	)		(140,516	)
Net increase (decrease) in cash and cash equivalents						18,013			11,135			(18,235	)
Cash and cash equivalents at beginning of period						93,054			81,919			100,154

Cash and cash equivalents at end of period					$	111,067		$	93,054		$	81,919

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)			$	264,213		$	223,666		$	232,019
		Income taxes			$	153,092		$	216,556		$	130,179

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

THE CINCINNATI GAS & ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME

			2001		2000			1999
			(dollars in thousands)
Operating Revenues
	Electric		$	4,097,347	$	2,738,775		$	2,174,861
	Gas			596,429		490,972			376,013

		Total Operating Revenues		4,693,776		3,229,747			2,550,874
Operating Expenses
	Fuel and purchased and exchanged power			2,881,962		1,554,959			1,066,490
	Gas purchased			396,764		266,339			171,997
	Operation and maintenance			442,173		491,545			445,737
	Depreciation			186,986		180,978			174,988
	Taxes other than income taxes			174,320		208,385			212,193

		Total Operating Expenses		4,082,205		2,702,206			2,071,405
Operating Income				611,571		527,541			479,469
Miscellaneous — Net				4,657		(2,119	)		(2,480	)
Interest				103,047		99,204			99,737
Income Before Taxes				513,181		426,218			377,252
Income Taxes (Note 12)				186,527		159,398			143,676

Net Income			$	326,654	$	266,820		$	233,576
Preferred Dividend Requirement				846		847			856

Net Income Applicable to Common Stock			$	325,808	$	265,973		$	232,720

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

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS

					December 31
					2001		2000
					(dollars in thousands)
ASSETS
Current Assets
	Cash and cash equivalents				$	9,074	$	20,637
	Restricted deposits					3,540		160
	Notes receivable from affiliated companies					—		91,732
	Accounts receivable less accumulated provision for doubtful accounts of $25,874 at December 31, 2001, and $19,044 at December 31, 2000 (Note 7)					332,970		494,501
	Accounts receivable from affiliated companies					12,112		26,743
	Materials, supplies, and fuel — at average cost					138,119		99,061
	Energy risk management current assets (Note 1(k))					44,360		697,488
	Prepayments and other					13,087		39,320

				Total Current Assets		553,262		1,469,642
Property, Plant, and Equipment — at Cost
	Utility plant in service
		Electric				2,000,595		1,905,795
		Gas				926,381		865,303
		Common				253,978		211,424

			Total Utility Plant In Service			3,180,954		2,982,522
	Construction work in progress					96,247		132,577

			Total Utility Plant			3,277,201		3,115,099
	Non-regulated property, plant, and equipment					3,314,285		3,181,076
	Accumulated depreciation					2,555,639		2,444,867

				Net Property, Plant, and Equipment		4,035,847		3,851,308
Other Assets
	Regulatory assets (Note 1(c))					592,491		502,328
	Energy risk management non-current assets (Note 1(k))					48,982		7,000
	Other					129,162		156,692

				Total Other Assets		770,635		666,020
Total Assets					$	5,359,744	$	5,986,970

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

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS

				December 31
				2001			2000
				(dollars in thousands)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
	Accounts payable			$	352,450		$	543,006
	Accounts payable to affiliated companies				30,419			23,927
	Accrued taxes				116,616			152,750
	Accrued interest				16,570			17,645
	Notes payable and other short-term obligations (Note 6)				196,100			264,000
	Notes payable to affiliated companies				444,801			163,478
	Long-term debt due within one year (Note 5)				100,000			1,200
	Energy risk management current liabilities (Note 1(k))				23,341			717,902
	Other				33,217			37,603

			Total Current Liabilities		1,313,514			1,921,511
Non-Current Liabilities
	Long-term debt (Note 5)				1,105,333			1,205,061
	Deferred income taxes (Note 12)				779,295			735,799
	Unamortized investment tax credits				91,246			98,624
	Accrued pension and other postretirement benefit costs (Note 10)				165,326			164,901
	Energy risk management non-current liabilities (Note 1(k))				41,773			26,337
	Other				105,681			118,421

			Total Non-Current Liabilities		2,288,654			2,349,143
Total Liabilities					3,602,168			4,270,654
Cumulative Preferred Stock
	Not subject to mandatory redemption				20,486			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, 2001, and December 31, 2000			762,136			762,136
		Paid-in capital			571,926			565,777
		Retained earnings			408,706			368,911
		Accumulated other comprehensive income (loss)			(5,678	)		(994	)

			Total Common Stock Equity		1,737,090			1,695,830
Commitments and Contingencies(Note 13)
Total Liabilities and Shareholder's Equity				$	5,359,744		$	5,986,970

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

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)
1999
Beginning balance			$	762,136	$	553,926	$	351,505		$	(1,124	)	$	1,666,443
Comprehensive income:
	Net income			—		—		233,576			—			233,576
	Other comprehensive income (loss), net of tax effect of $(85)
		Minimum pension liability adjustment		—		—		—			158			158

	Total comprehensive income			—		—		—			—			233,734
Dividends on preferred stock				—		—		(856	)		—			(856	)
Dividends on common stock				—		—		(250,100	)		—			(250,100	)
Contribution from parent company for reallocation of taxes				—		8,920		—			—			8,920
Other				—		5		1,019			—			1,024

Ending balance			$	762,136	$	562,851	$	335,144		$	(966	)	$	1,659,165
2000
Comprehensive income:
	Net income			—		—		266,820			—			266,820
	Other comprehensive income (loss), net of tax effect of $15
		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
		Minimum pension liability adjustment		—		—		—			134			134
		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

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

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

				2001			2000			1999
				(dollars in thousands)
Operating Activities
	Net income			$	326,654		$	266,820		$	233,576
	Items providing or (using) cash currently:
		Depreciation			186,986			180,978			174,988
		Deferred income taxes and investment tax credits — net			43,834			36,238			2,366
		Change in net position of energy risk management activities			(67,979	)		(7,077	)		(27,245	)
		Allowance for equity funds used during construction			(2,672	)		(4,459	)		(2,565	)
		Regulatory assets deferrals			(116,365	)		(35,777	)		(11,868	)
		Regulatory assets amortization			55,867			18,154			26,193
		Changes in current assets and current liabilities:
			Restricted deposits		(3,380	)		(28	)		1,040
			Accounts and notes receivable, net of reserves on receivables sold		174,385			(235,094	)		(66,682	)
			Materials, supplies, and fuel		(39,058	)		(62	)		16,295
			Accounts payable		(184,064	)		248,562			22,462
			Accrued taxes and interest		(37,209	)		16,902			(18,533	)
		Other items — net			(3,900	)		(21,282	)		48,981

			Net cash provided by (used in) operating activities		333,099			463,875			399,008

Financing Activities
	Change in short-term debt, including net affiliate notes				305,155			40,684			173,117
	Issuance of long-term debt				—			—			19,818
	Redemption of long-term debt				(1,200	)		—			(164,264	)
	Retirement of preferred stock				—			(168	)		(26	)
	Dividends on preferred stock				(845	)		(847	)		(856	)
	Dividends on common stock				(286,269	)		(232,334	)		(250,100	)

			Net cash provided by (used in) financing activities		16,841			(192,665	)		(222,311	)

Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)				(361,503	)		(260,127	)		(194,132	)

			Net cash provided by (used in) investing activities		(361,503	)		(260,127	)		(194,132	)

Net increase (decrease) in cash and cash equivalents					(11,563	)		11,083			(17,435	)
Cash and cash equivalents at beginning of period					20,637			9,554			26,989

Cash and cash equivalents at end of period				$	9,074		$	20,637		$	9,554

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)		$	108,079		$	99,009		$	101,264
		Income taxes		$	147,471		$	121,158		$	159,241

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

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31
					2001			2000
					(dollars in thousands)
Long-term Debt(excludes current portion)
	CG&E
		First Mortgage Bonds:
			7¹/4 % Series due September 1, 2002		$	—		$	100,000
			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
			5¹/2 % Series due January 1, 2024 (Pollution Control)			48,000			48,000

				Total First Mortgage Bonds		470,200			570,200
		Pollution Control Notes:
			6.50% due November 15, 2022			12,721			12,721
		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			100,000

				Total Other Long-term Debt		550,000			550,000
		Unamortized Premium and Discount — Net				(2,209	)		(2,449	)

				Total Long-term Debt		1,030,712			1,130,472
ULH&P
		Other Long-term Debt:
			6.11 % Debentures due December 8, 2003			20,000			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		75,000			75,000
		Unamortized Premium and Discount — Net				(379	)		(411	)

				Total Long-term Debt		74,621			74,589
Total CG&E Consolidated Long-term Debt					$	1,105,333		$	1,205,061

THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (cont.)

Cumulative Preferred Stock
Cumulative Preferred Stock								December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001		Mandatory Redemption	December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001	Series	Mandatory Redemption	2001			2000
								(dollars in thousands)
$100				6,000,000	204,859	4% - 4³/4%	No	$	20,486		$	20,486
Common Stock Equity
	Common Stock — $8.50 par value; authorized shares — 120,000,000; outstanding shares — 89,663,086 at December 31, 2001, and December 31, 2000							$	762,136		$	762,136
	Paid-in capital								571,926			565,777
	Retained earnings								408,706			368,911
	Accumulated other comprehensive income (loss)								(5,678	)		(994	)

		Total Common Stock Equity							1,737,090			1,695,830
			Total Capitalization					$	2,862,909		$	2,921,377

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

PSI ENERGY, INC.
AND SUBSIDIARY COMPANY

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

			2001		2000		1999
			(dollars in thousands)
Operating Revenues
	Electric		$	4,075,024	$	2,684,197	$	2,135,706
Operating Expenses
	Fuel and purchased and exchanged power			3,132,494		1,724,656		1,213,653
	Operation and maintenance			413,275		463,649		461,779
	Depreciation			149,467		141,512		135,330
	Taxes other than income taxes			49,955		56,908		52,920

		Total Operating Expenses		3,745,191		2,386,725		1,863,682
Operating Income				329,833		297,472		272,024
Miscellaneous — Net				19,541		4,723		655
Interest				80,955		78,250		86,265
Income Before Taxes				268,419		223,945		186,414
Income Taxes (Note 12)				106,086		88,547		69,215

Net Income			$	162,333	$	135,398	$	117,199
Preferred Dividend Requirement				2,587		3,738		4,601

Net Income Applicable to Common Stock			$	159,746	$	131,660	$	112,598

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

PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

				December 31
				2001		2000
				(dollars in thousands)
ASSETS
Current Assets
	Cash and cash equivalents			$	1,587	$	1,311
	Restricted deposits				519		341
	Notes receivable				—		3
	Notes receivable from affiliated companies				444,801		12,798
	Accounts receivable less accumulated provision for doubtful accounts of $6,773 at December 31, 2001, and $9,317 at December 31, 2000 (Note 7)				336,994		464,930
	Accounts receivable from affiliated companies				10,470		5,385
	Materials, supplies, and fuel — at average cost				87,661		53,838
	Energy risk management current assets (Note 1(k))				28,201		697,488
	Prepayments and other				41,041		49,049

			Total Current Assets		951,274		1,285,143
Property, Plant, and Equipment — at Cost
	Utility plant in service				4,909,007		4,699,090
	Construction work in progress				368,313		190,773

		Total Utility Plant			5,277,320		4,889,863
	Accumulated depreciation				2,216,908		2,110,747

			Net Property, Plant, and Equipment		3,060,412		2,779,116
Other Assets
	Regulatory assets (Note 1(c))				423,372		474,286
	Energy risk management non-current assets (Note 1(k))				30,164		7,000
	Other investments				57,633		51,343
	Other				47,927		32,887

			Total Other Assets		559,096		565,516
Total Assets				$	4,570,782	$	4,629,775

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

PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

			December 31
			2001			2000
			(dollars in thousands)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
	Accounts payable		$	312,707		$	392,206
	Accounts payable to affiliated companies			27,370			32,448
	Accrued taxes			102,317			80,995
	Accrued interest			23,760			23,708
	Notes payable and other short-term obligations (Note 6)			148,600			188,391
	Notes payable to affiliated companies			422,263			146,381
	Long-term debt due within one year (Note 5)			23,000			38,325
	Energy risk management current liabilities (Note 1(k))			23,185			717,902
	Other			41,695			12,748

		Total Current Liabilities		1,124,897			1,633,104
Non-Current Liabilities
	Long-term debt (Note 5)			1,325,089			1,074,255
	Deferred income taxes (Note 12)			486,694			458,593
	Unamortized investment tax credits			36,139			39,341
	Accrued pension and other postretirement benefit costs (Note 10)			154,799			143,990
	Energy risk management non-current liabilities (Note 1(k))			41,773			26,337
	Other			63,557			78,112

		Total Non-Current Liabilities		2,108,051			1,820,628
Total Liabilities				3,232,948			3,453,732
Cumulative Preferred Stock (Note 3)
	Not subject to mandatory redemption			42,347			42,348
Common Stock Equity(Note 2)
	Common Stock — without par value; $.01 stated value; authorized shares — 60,000,000; outstanding shares — 53,913,701 at December 31, 2001, and December 31, 2000			539			539
	Paid-in capital			416,414			413,523
	Retained earnings			880,129			720,153
	Accumulated other comprehensive income (loss)			(1,595	)		(520	)

		Total Common Stock Equity		1,295,487			1,133,695
Commitments and Contingencies (Note 13)
Total Liabilities and Shareholder's Equity			$	4,570,782		$	4,629,775

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

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)
1999
Beginning balance			$	539	$	410,739		$	564,865		$	(495	)	$	975,648
Comprehensive income:
	Net income			—		—			117,199			—			117,199
	Other comprehensive income (loss), net of tax effect of $(418)
		Minimum pension liability adjustment		—		—			—			(163	)		(163	)
		Unrealized gain (loss) on investment trust		—		—			—			2,049			2,049

	Total comprehensive income			—		—			—			—			119,085
Dividends on preferred stock				—		—			(4,601	)		—			(4,601	)
Dividends on common stock				—		—			(35,900	)		—			(35,900	)
Contribution from parent company for reallocation of taxes				—		457			—			—			457
Other				—		2			1,006			—			1,008

Ending balance			$	539	$	411,198		$	642,569		$	1,391		$	1,055,697
2000
Comprehensive income:
	Net income			—		—			135,398			—			135,398
	Other comprehensive income (loss), net of tax effect of $584
		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
		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

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

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

				2001			2000			1999
				(dollars in thousands)
Operating Activities
	Net income			$	162,333		$	135,398		$	117,199
	Items providing or (using) cash currently:
		Depreciation			149,467			141,512			135,330
		Deferred income taxes and investment tax credits — net			41,543			(6,582	)		102,878
		Change in net position of energy risk management activities			(33,158	)		(7,077	)		(27,245	)
		Allowance for equity funds used during construction			(5,956	)		(1,354	)		(1,068	)
		Regulatory assets deferrals			(24,959	)		(63,884	)		(294,472	)
		Regulatory assets amortization			62,641			74,702			76,923
		Changes in current assets and current liabilities:
			Restricted deposits		(178	)		(341	)		2,414
			Accounts and notes receivable, net of reserves on receivables sold		119,311			(178,453	)		(74,847	)
			Materials, supplies, and fuel		(33,823	)		49,652			(23,045	)
			Accounts payable		(84,577	)		176,820			(270	)
			Accrued taxes and interest		21,374			(15,342	)		32,809
	Other items — net				14,153			34,064			77,447

			Net cash provided by (used in) operating activities		388,171			339,115			124,053
Financing Activities
	Change in short-term debt, including net affiliate notes				(195,912	)		143,030			(80,140	)
	Issuance of long-term debt				322,471			53,075			589,225
	Redemption of long-term debt				(89,248	)		(187,097	)		(379,484	)
	Retirement of preferred stock				(1	)		(29,225	)		(8	)
	Dividends on preferred stock				(2,587	)		(3,738	)		(4,601	)
	Dividends on common stock				—			(54,000	)		(35,900	)

			Net cash provided by (used in) financing activities		34,723			(77,955	)		89,092
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)				(414,047	)		(259,394	)		(189,207	)
	Other investments				(8,571	)		(9,297	)		(33,884	)

			Net cash provided by (used in) investing activities		(422,618	)		(268,691	)		(223,091	)
Net increase (decrease) in cash and cash equivalents					276			(7,531	)		(9,946	)
Cash and cash equivalents at beginning of period					1,311			8,842			18,788

Cash and cash equivalents at end of period				$	1,587		$	1,311		$	8,842

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)		$	84,306		$	80,854		$	86,256
		Income taxes		$	41,419		$	112,210		$	(54,099	)

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

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31
					2001			2000
					(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			—

				Total First Mortgage Bonds		620,720			295,720
	Secured Medium-term Notes:
		Series A, 8.37% to 8.81%, due November 8, 2006 to June 1, 2022				34,300			57,300
		Series B, 5.93% to 8.24%, due September 17, 2003 to August 22, 2022				126,000			126,000

			(Series A and B, 7.105% weighted average interest rate and 8 year weighted average remaining life)
				Total Secured Medium-term Notes		160,300			183,300
	Other Long-term Debt:
		Series 2000A, Pollution Control Revenue Refunding Bond, due May 1, 2035				44,025			44,025
		Series 2000B, Pollution Control Revenue Refunding Bond, due April 1, 2022				10,000			10,000
		6.35% Debentures due November 15, 2006				50			50
		6.00% Debentures due December 14, 2016 (Note 5)				—			50,000
		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 (RUS) Obligation payable in annual installments				83,004			83,927
		6.52% Senior Notes due March 15, 2009				97,342			97,342
		7.85% Debentures due October 15, 2007				265,000			265,000

				Total Other Long-term Debt		552,079			603,002
	Unamortized Premium and Discount — Net					(8,010	)		(7,767	)

				Total Long-term Debt		1,325,089			1,074,255

PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (cont.)

Cumulative Preferred Stock
Cumulative Preferred Stock								December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001		Mandatory Redemption	December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001	Series	Mandatory Redemption	2001			2000
								(dollars in thousands)
$100				5,000,000	347,581	3¹/2% - 6⁷/8%	No	$	34,758		$	34,759
$25				5,000,000	303,544	4.16% – 4.32%	No		7,589			7,589

		Total Preferred Stock							42,347			42,348
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, 2001, and December 31, 2000							$	539		$	539
	Paid-in capital								416,414			413,523
	Retained earnings								880,129			720,153
	Accumulated other comprehensive income (loss)								(1,595	)		(520	)

		Total Common Stock Equity							1,295,487			1,133,695
			Total Capitalization					$	2,662,923		$	2,250,298

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

THE UNION LIGHT, HEAT
AND POWER COMPANY

THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME

		2001		2000			1999
		(dollars in thousands)
Operating Revenues
	Electric	$	230,960	$	225,601		$	210,234
	Gas		109,333		91,950			70,728

Total Operating Revenues			340,293		317,551			280,962
Operating Expenses
	Electricity purchased from parent company for resale (Note 1(o))		151,562		159,915			158,556
	Gas purchased		72,593		51,591			34,690
	Operation and maintenance		39,501		40,699			38,611
	Depreciation		17,039		15,685			14,830
	Taxes other than income taxes		3,901		3,938			4,136

Total Operating Expenses			284,596		271,828			250,823
Operating Income			55,697		45,723			30,139
Miscellaneous — Net			239		(982	)		(1,567	)
Interest			6,313		6,308			6,114
Income Before Taxes			49,623		38,433			22,458
Income Taxes (Note 12)			13,699		13,801			10,184

Net Income		$	35,924	$	24,632		$	12,274

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

THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS

					December 31
					2001		2000
					(dollars in thousands)
ASSETS
Current Assets
	Cash and cash equivalents				$	4,099	$	6,460
	Accounts receivable less accumulated provision for doubtful accounts of $1,196 at December 31, 2001, and $1,492 at December 31, 2000 (Note 7)					16,785		28,518
	Accounts receivable from affiliated companies					2,401		2,279
	Materials, supplies, and fuel — at average cost					10,835		6,300
	Prepayments and other					300		274

				Total Current Assets		34,420		43,831
Property, Plant, and Equipment — at Cost
	Utility plant in service
		Electric				248,223		234,482
		Gas				197,301		184,878
		Common				50,289		44,603

			Total Utility Plant In Service			495,813		463,963
	Construction work in progress					11,004		15,069

			Total Utility Plant			506,817		479,032
	Accumulated depreciation					178,567		169,403

				Net Property, Plant, and Equipment		328,250		309,629
Other Assets
	Regulatory assets (Note 1(c))					7,838		10,177
	Other					6,582		5,110

				Total Other Assets		14,420		15,287
Total Assets					$	377,090	$	368,747

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

THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS

			December 31
			2001			2000
			(dollars in thousands)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
	Accounts payable		$	7,960		$	24,249
	Accounts payable to affiliated companies			16,156			20,192
	Accrued taxes			7,051			(5,760	)
	Accrued interest			643			1,215
	Notes payable to affiliated companies			26,432			29,403
	Other			5,322			11,669

		Total Current Liabilities		63,564			80,968
Non-Current Liabilities
	Long-term debt (Note 5)			74,621			74,589
	Deferred income taxes (Note 12)			28,323			35,822
	Unamortized investment tax credits			3,411			3,684
	Accrued pension and other postretirement benefit costs (Note 10)			13,198			13,041
	Amounts due to customers — income taxes			7,148			7,439
	Other			14,622			6,016

		Total Non-Current Liabilities		141,323			140,591
Total Liabilities				204,887			221,559
Common Stock Equity(Note 2)
	Common Stock — $15.00 par value; authorized shares — 1,000,000; outstanding shares — 585,333 at December 31, 2001, and December 31, 2000			8,780			8,780
	Paid-in capital			21,111			20,305
	Retained earnings			142,320			118,103
	Accumulated other comprehensive income (loss)			(8	)		—

		Total Common Stock Equity		172,203			147,188
Commitments and Contingencies (Note 13)
Total Liabilities and Shareholder's Equity			$	377,090		$	368,747

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

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)
1999
Beginning balance		$	8,780	$	19,525	$	100,513		$	—		$	128,818
Net income			—		—		12,274			—			12,274
Dividends on common stock			—		—		(9,659	)		—			(9,659	)
Contribution from parent for reallocation of taxes			—		617		—			—			617

Ending balance		$	8,780	$	20,142	$	103,128		$	—		$	132,050
2000
Net income			—		—		24,632			—			24,632
Dividends on common stock			—		—		(9,657	)		—			(9,657	)
Contribution from parent 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 for reallocation of taxes			—		806		—			—			806

Ending balance		$	8,780	$	21,111	$	142,320		$	(8	)	$	172,203

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

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

					2001			2000			1999
					(dollars in thousands)
Operating Activities
	Net income				$	35,924		$	24,632		$	12,274
	Items providing or (using) cash currently:
		Depreciation				17,039			15,685			14,830
		Deferred income taxes and investment tax credits — net				(7,116	)		8,926			(738	)
		Allowance for equity funds used during construction				(143	)		(61	)		(36	)
		Regulatory assets deferrals				1,098			(12	)		—
		Regulatory assets amortization				901			271			138
		Changes in current assets and current liabilities:
				Accounts and notes receivable, net of reserves on receivables sold		12,112			(14,269	)		(5,099	)
				Materials, supplies, and fuel		(4,535	)		1,354			615
				Accounts payable		(20,325	)		15,832			7,720
				Accrued taxes and interest		12,239			(6,582	)		(3,138	)
		Other items — net				(681	)		3,482			5,971

			Net cash provided by (used in) operating activities			46,513			49,258			32,537
Financing Activities
	Change in short-term debt					(2,971	)		(8,349	)		5,935
	Issuance of long-term debt					—			—			19,818
	Redemption of long-term debt					—			—			(20,000	)
	Dividends on common stock					(11,707	)		(9,657	)		(9,659	)

			Net cash provided by (used in) financing activities			(14,678	)		(18,006	)		(3,906	)
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)					(34,196	)		(28,433	)		(28,234	)

			Net cash provided by (used in) investing activities			(34,196	)		(28,433	)		(28,234	)
Net increase (decrease) in cash and cash equivalents						(2,361	)		2,819			397
Cash and cash equivalents at beginning of period						6,460			3,641			3,244

Cash and cash equivalents at end of period					$	4,099		$	6,460		$	3,641

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)			$	6,775		$	6,534		$	6,691
		Income taxes			$	10,848		$	11,760		$	12,794

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

THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CAPITALIZATION

					December 31
					2001			2000
					(dollars in thousands)
Long-term Debt (excludes current portion)
	Other Long-term Debt:
		6.11% Debentures due December 8, 2003			$	20,000		$	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			75,000			75,000
		Unamortized Premium and Discount — Net				(379	)		(411	)

			Total Long-term Debt			74,621			74,589
Common Stock Equity
	Common Stock — $15.00 par value; authorized shares — 1,000,000; outstanding shares — 585,333 at December 31, 2001, and December 31, 2000				$	8,780		$	8,780
	Paid-in capital					21,111			20,305
	Retained earnings					142,320			118,103
	Accumulated other comprehensive income (loss)					(8	)		—

			Total Common Stock Equity			172,203			147,188
				Total Capitalization	$	246,824		$	221,777

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

NOTES TO FINANCIAL STATEMENTS

In this reportCinergy (which includesCinergy 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 Wholesale Energy, Inc. (Wholesale Energy);
•: Cinergy Services, Inc. (Services);
•: Cinergy Investments, Inc. (Investments);
•: Cinergy Global Resources, Inc. (Global Resources); and
•: Cinergy Technologies, Inc. (Technologies).

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 on Ohio deregulation.

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

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

Wholesale Energy is a holding company forCinergy's energy commodity businesses, including electric production, as the generation assets eventually become unbundled from the utility subsidiaries. See Note 18 for a discussion on Ohio deregulation. Cinergy Power Generation Services, LLC (Generation Services), a wholly-owned subsidiary of Wholesale Energy, provides electric production-

related construction, operation and maintenance services to certain affiliates and non-affiliated third parties.

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. Global Resources holds most of our international businesses and investments and directs our renewable energy investing activities (for example, wind farms). Technologies primarily holds our portfolio of technology-related investments.

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.

Additionally, we have reclassified certain prior-year amounts in the financial statements ofCinergy,CG&E,PSI, andULH&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 ofCinergy,CG&E, andPSI, 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% to 50% ownership). Under the equity method we report:

•: our investment in the entity asInvestments in unconsolidated subsidiaries in our Consolidated Balance Sheets; and
•: our percentage share of the earnings from the entity asEquity 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% ownership). Under the cost method we report our investments in the entity asOther investments in our Consolidated 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 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.

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 toCG&E's transition plan. This plan created a Regulatory Transition Charge (RTC), designed to recoverCG&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 ofCG&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 to the financial statements was immaterial. Except with respect to the generation-related assets and liabilities ofCG&E, as of December 31, 2001,PSI,CG&E, andULH&P continue to meet the criteria of Statement 71. However, as 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, 2001, is probable. The effect of future discontinuance of Statement 71 on results of operations, cash flows, or statements of position cannot be determined until deregulation legislation plans have been approved by each state in which we do business. For a further discussion of Ohio deregulation see Note 18.

Our regulatory assets and amounts authorized for recovery through regulatory orders at December 31, 2001, and 2000, are as follows:

		2001						2000
		CG&E(1)		PSI		Cinergy		CG&E(1)		PSI		Cinergy
		(in millions)
Amounts due from customers — income taxes(2)		$	57	$	5	$	62	$	53	$	20	$	73
Gasification services agreement buyout costs(3)			—		244		244		—		251		251
Post-in-service carrying costs and deferred operating expenses			—		39		39		—		41		41
Coal contract buyout cost(4)			—		26		26		—		53		53
Deferred demand-side management costs			—		9		9		—		—		—
Deferred merger costs			6		56		62		7		60		67
Unamortized costs of reacquiring debt			10		33		43		11		31		42
Coal gasification services expenses			—		8		8		—		12		12
RTC recoverable assets(5)			511		—		511		432		—		432
Other			9		3		12		—		6		6

	Total regulatory assets	$	593	$	423	$	1,016	$	503	$	474	$	977
	Authorized for recovery(6)	$	573	$	379	$	952	$	494	$	404	$	898

(1): Includes $8 million at December 31, 2001, and $10 million at December 31, 2000, related toULH&P. Of these amounts, $.6 million at December 31, 2001, and $3.4 million at December 31, 2000, 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 forCG&E andPSI and a regulatory liability forULH&P.
(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 through December 2002.
(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, 2001, these amounts were being recovered through rates charged to customers over a period ranging from 1 to 22 years forCG&E, 1 to 32 years forPSI, and 1 to 19 years forULH&P.

(d) Statements of Cash Flows

We defineCash equivalents as investments with maturities of three months or less when acquired.

(e) Operating Revenues and Fuel Costs

Our operating companies recordOperating revenues for electric and gas service, including unbilled revenues and the associated expenses, when they provide the service to the customers. The associated expenses 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 our Statements of Income ofCinergy,CG&E, andPSI asFuel and purchased and exchanged power andGas purchased. These expenses are shown inULH&P's Statements of Income asElectricity purchased from parent for resale andGas purchased. Any portion of these costs that are recoverable or refundable to customers in future periods is deferred in eitherAccounts receivable orAccounts payable in our Balance Sheets.

Indiana law limits the amount of fuel costs thatPSI 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 rates has been frozen.

(f) 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 ourProperty, 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 (h) and (i)); and
•: other miscellaneous amounts.

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

(g) 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 (the number of years we expect to be able to use the properties) and the net cost to remove the properties. The average

depreciation rates forProperty, plant, and equipment, excluding software, are presented in the table below.

		2001		2000		1999
Cinergy
	Non-regulated(1)	4.2	%	•	%	—	%
CG&E and subsidiaries
	Electric	2.5		2.6		2.9	(2)
	Gas	2.9		2.9		2.9
	Common	2.9		3.3		2.7
	Non-regulated electric generation	3.2		3.1		—
PSI		3.0		3.0		3.0
ULH&P
	Electric	3.2		3.3		3.3
	Gas	3.2		3.1		3.1
	Common	5.0		5.1		5.2

(1): ExcludingCG&E's electric generation. Amounts in 1999 and 2000 were immaterial.
(2): Prior to Ohio deregulation in 2000, electric generation was included in the electric line item.

(h) 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. AFUDC rates are compounded semi-annually and are as follows:

	2001		2000		1999
Cinergy average	7.4	%	8.0	%	7.3	%
CG&E and subsidiaries average	8.6		8.4		8.0
PSI average	7.1		7.4		6.5
ULH&P average	5.7		6.6		5.3

The borrowed funds component of AFUDC, which is recorded on a pre-tax basis, was as follows:

	2001		2000		1999
	(in millions)
Cinergy	$	8.4	$	8.2	$	5.6
CG&Eand subsidiaries		1.0		5.0		3.4
PSI		7.4		3.2		2.2
ULH&P		0.2		0.4		0.2

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

(i) 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). 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, were $7.1 million and $5.5 million forCinergy andCG&E, respectively, for the year ended December 31, 2001. Capitalized interest costs for the years 1999 and 2000 were immaterial.

(j) 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 asDeferred income tax assets orliabilities 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 12.

(k) Energy Marketing and Trading

We market and trade electricity, natural gas, and other energy-related products. We designate transactions as physical or trading at the time they are originated. Physical refers to our intent and projected ability to fulfill substantially all obligations from company-owned assets. We sell 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 contracts (including most natural gas contracts) are classified as trading. We account for physical transactions on a settlement basis and trading transactions using the mark-to-market method of accounting, consistent with our application of Emerging Issues Task Force (EITF) 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities. To the extent that physical transactions constitute derivatives under Statement of Financial Accounting Standards No. 133,Accounting for Derivatives and Hedging Activities, (Statement 133), we typically utilize the normal purchases and sales exemption when the criteria for the application of the normal exemption are met, the most critical criterion being probability of delivery under the contract. Should we determine that delivery under a previously exempted contract is no longer probable, that contract would be recognized at fair value and subsequently marked to market. To the extent trading transactions constitute derivatives under Statement 133, we typically do not attempt to identify them as a hedging instrument.

Under the mark-to-market method of accounting, trading transactions are shown at fair value in our Balance Sheets asEnergy risk management assets andEnergy risk management liabilities. We reflect changes in fair value resulting in unrealized gains and losses inFuel and purchased and exchanged power andGas purchased on our Statements of Income. We record the revenues and costs for all transactions in our Statements of Income when the contracts are settled. We recognize revenues inOperating revenues; costs are recorded inFuel and purchased and exchanged power andGas purchased.

Although we intend to settle physical electricity contracts with company-owned generation, occasionally we settle these contracts with power purchased 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 the power is delivered. Due to the infrequency of such settlements, both historical and projected, and the fact that physical power 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 value contracts in the trading portfolio using end-of-the-period market prices, 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
•: model pricing (which considers time value and historical volatility factors of electricity and natural gas).

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.

Throughout 2001, our natural gas trading volumes increased substantially. Because of this volume change and the potential volatility of gas prices, our risk exposure to these markets has increased. However, we continue to employ value-at-risk analysis and other methodologies to mitigate our risks in all trading operations, including natural gas trading.

We are in the process of evaluating the feasibility of coal marketing as a commercial activity. While our review of establishing a dedicated commercial activity is ongoing, we executed a small number of sales contracts in the fourth quarter of 2001. These contracts were entered into primarily to balance forecasted supply and demand in 2002 as we had some coal under option, accounted for at fair value, that our forecast indicated would not be internally consumed. Since option contracts cannot utilize the normal exemption (see Note 1(m)(iii) for certain exceptions to this rule), the coal from this option was designated to source these sales contracts. We have concluded that these sales contracts meet the definition of a derivative and are therefore accounted for at fair value. Should coal begin to be marketed in 2002 under a formal commercial activity, it is likely that the volume of coal transactions accounted for under mark-to-market could increase substantially. Since we are still evaluating the viability of this as a commercial activity, the impact to either our financial position or results of operations cannot be determined at this time.

(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 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.

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). Through December 31, 2000, we utilized the accrual method to account for these interest rate swaps. 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 ofInterest over the life of the agreement. Effective with our adoption of Statement 133 in the first quarter of 2001, we began accounting for interest rate swaps using fair value accounting and are assessing the effectiveness of any swaps used in hedging activities. At December 31, 2001, the fair value, and ineffectiveness, of instruments that we have classified as fair value or cash flow hedges of debt instruments was not material. Reclassification of unrealized gains or losses on cash flow hedges of variable-rate debt instruments from other comprehensive income occurs as interest payments are accrued on the debt instrument. See Note 1(m)(iii) below for further discussion of Statement 133.

(m) Accounting Changes

(i) Business Combinations and Intangible Assets

In June 2001, the Financial Accounting Standards Board (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. Goodwill will be initially assessed for impairment shortly after adoption and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under current 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 we will adopt Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill beginning in the first quarter of 2002 will not be material to our results of operations. We have identified the reporting units forCinergy and are in the process of performing the initial impairment test. Preliminary estimates indicate that the effects of this test will not be material to our results of operations.

(ii) Asset Retirement Obligations

In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations (Statement 143). Statement 143 requires fair value recognition of legal obligations to retire long-lived assets at the time such 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 operation expense). Additional depreciation expense will be recorded prospectively for any property, plant, and equipment increases. We currently accrue costs of removal on many regulated, long-lived assets through depreciation expense, with a corresponding charge to accumulated depreciation, as allowed by each regulatory jurisdiction. For assets that we conclude have a retirement obligation under Statement 143, the accounting we currently use will be modified to comply with this standard. We will adopt Statement 143 in the first quarter of 2003. We are beginning to analyze the impact of this statement, but, at this time, we are unable to predict whether the implementation of this accounting standard will be material to our financial position or results of operations.

(iii) Derivatives

During 1998, the FASB issued Statement 133. This standard was effective forCinergy 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 mark-to-market accounting, the effects of implementation were not material.

Our adoption did not reflect the potential impact of applying mark-to-market accounting to selected electricity options and capacity contracts. We had not historically marked these instruments to market because they are 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 much of the criteria this guidance requires is 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. We will continue to apply this guidance to any new electricity contracts that meet the definition of a derivative.

In October 2001, the FASB staff posted revised guidance on the normal purchases and sales exemption for these contracts. This revised guidance proposed changes in certain quantitative criteria that were critical to determining whether or not a contract with option characteristics qualified for the normal exemption. In December 2001, the FASB staff again revised this guidance to make the changes proposed by the October guidance 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. Based on a review of existing contracts, we do not believe this revised guidance, which will be effective in the third quarter of 2002, will have a material impact on our financial position or results of operations upon adoption. However, given our activity in energy trading, it could increase volatility in future results.

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 (an option component). While this guidance was issued

primarily to address optionality in fuel supply contracts, it is applicable 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.Cinergy has certain contracts that contain optionality, primarily coal contracts, for which the accounting may be impacted by this new guidance. We will adopt this guidance in the second quarter of 2002, consistent with the transition provisions. We have begun analyzing contracts to determine the applicability of this guidance and to determine the interaction between this guidance and Statement 71. Due to a lack of liquidity with respect to coal purchased under certain contracts, some of our contracts may fail to meet the net settlement criteria of Statement 133, which would preclude such contracts from being considered derivatives. For other possibly affected contracts, we are evaluating the potential for contract restructuring prior to the adoption of this new guidance. To the extent this restructuring results in separate forwards and options, we would plan to apply the normal exemption to the forwards. The options would either be accounted for as cash flow hedges, to the extent all criteria were met, or marked to market similar to all other energy trading contracts. Given these evaluations are ongoing, we are unable to predict whether the implementation of this accounting standard will be material to our results of operations or financial position.

(iv) Asset Impairment

In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144,Accounting for the Impairment of Long-Lived Assets (Statement 144). Statement 144 addresses accounting and reporting for the impairment or disposal of long-lived assets. It supersedes previous guidance on (a) accounting for the impairment or disposal of long-lived assets and (b) accounting and reporting for the disposal of a segment of a business (commonly known as discontinued operations). While Statement 144 incorporates many of the impairment tests and criteria from previous guidance, it does include additional guidance and resolution of inconsistencies and overlaps with other pronouncements. These include adding clarity around when assets are considered held for disposal (which requires an immediate impairment charge if fair value is less than book value) and requiring the use of one accounting model for long-lived assets to be disposed of. We will begin applying Statement 144 in the first quarter of 2002. The impact of implementation on our results of operations and financial position is expected to be immaterial.

(n) 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 inAccumulated other comprehensive income (loss), which is a component of common stock equity.

(o) Related Party Transactions

Cinergy and its subsidiaries engage in related party transactions. These transactions are generally performed at cost and in accordance with the SEC regulations under the PUHCA. The Balance Sheets of our operating companies reflect amounts payable to and/or receivable from related parties asAccounts payable to affiliated companies andAccounts receivable from affiliated companies. The significant related party transactions are disclosed below.

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:

	2001		2000		1999
	(in millions)
Cinergy(1)	$	483	$	479	$	416
CG&Eand subsidiaries		240		250		208
PSI		196		187		168
ULH&P		24		25		23

(1): The results ofCinergyalso include amounts related to non-registrants.

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 year ended December 31, 2001:

	2001
	(in millions)
Cinergy(1)	$	92
CG&E		67
PSI		21

(1): The results ofCinergyalso include amounts related to non-registrants.

ULH&P purchases energy fromCG&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 withCG&E and replaces the previous cost-of-service based contract, which expired on December 31, 2001.

ULH&P purchased energy fromCG&E for resale in the amounts of $152 million, $160 million, and $159 million for the years ended 2001, 2000, and 1999, respectively.

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 6.

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.

	Newly Issued Shares Used to Grant or Settle Awards
	2001	2000	1999
Cinergy Corp. 1996 Long-term Incentive Compensation Plan (LTIP)	64,851	—	—
Cinergy Corp. Stock Option Plan (SOP)	197,957	77,042	255,828
Cinergy Corp. Employee Stock Purchase and Savings Plan	1,504	208	266
Cinergy Corp. UK Sharesave Scheme	121	—	—
Cinergy Corp. Retirement Plan for Directors	—	—	—
Cinergy Corp. Directors' Equity Compensation Plan	—	—	—
Cinergy Corp. Directors' Deferred Compensation Plan	—	—	—
Cinergy Corp. 401(k) Plans	69,500	—	—
Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan	173,984
Cinergy Corp. Performance Shares Plan	—	—	34,550
Cinergy Corp. Union Employees' Savings Incentive Plan	—	—	—

We retired 72,739 shares of common stock in 2001; 32,988 shares in 2000; and 31,777 shares in 1999, mainly representing shares tendered as payment for the exercise of previously granted stock options.

In April of 2001,Cinergy adopted the Direct Stock Purchase and Dividend Reinvestment Plan, a plan designed to provide investors with a convenient method to purchase shares ofCinergy 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 newCinergy Corp. common shares to satisfy obligations under its various employee stock plans and theCinergy 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 theCinergy Corp. 401(k) Excess Plan.

Cinergy Corp. owns all of the common stock ofCG&E andPSI. All ofULH&P's common stock is held byCG&E.

(b) Dividend Restrictions

Cinergy Corp.'s ability to pay dividends to holders of its common stock is principally dependent on the ability ofCG&E andPSI to payCinergy Corp. common dividends.Cinergy Corp.,CG&E, andPSI cannot pay dividends on their common stock if 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 underCG&E's andPSI'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; and
•: Directors' Deferred Compensation Plan.

The LTIP, the SOP, and the Employee Stock Purchase and Savings Plan are discussed below. The activity in 2001, 2000, and 1999 for the remaining stock-based compensation plans was not significant.

We account for our stock-based compensation plans under Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees. In 2001, 2000, and 1999, we recognized compensation cost related to stock-based compensation plans, before income taxes, of $12.5 million, $12.8 million, and $(7) million, respectively, in the Statements of Income. The $7 million reduction in 1999 was a result of our revised estimates for the performance-based shares accrued under the LTIP plan for Performance Cycle (Cycle) I. These amounts primarily reflect compensation cost related to the LTIP performance-based shares. For further discussion see section (i) below.

Net income, assuming compensation cost for these plans had been determined at fair value, consistent with the provisions of Statement of Financial Accounting Standards No. 123,Accounting for Stock-Based Compensation (Statement 123), would have been decreased by $4.4 million for 2001, $4.0 million for 2000, and $2.6 million for 1999. Earnings per common share (EPS) would have been decreased by $.03 for both basic EPS and earnings per common share assuming dilution (EPS—assuming dilution) for 2001, $.03 for both basic and EPS—assuming dilution for 2000, and $.02 for both basic and EPS—assuming dilution for 1999.

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 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, as applicable, below.

(i) LTIP

The LTIP was originally adopted in 1996. Under this plan, certain key employees may be granted stock options and the opportunity to earn performance-based shares. Stock options are granted to participants with an option price equal to the fair market value on the grant date and a vesting period of either three or five years. The vesting period begins on the grant date and all options expire ten years from that date. The number of shares of common stock issuable under the LTIP is limited to a total of 7,000,000 shares.

Entitlement to performance-based shares is based onCinergy's Total Shareholder Return (TSR) over designated Cycles as measured against a 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)
IV	1/2000	2000-2002	359
V	1/2001	2001-2003	315
VI	1/2002	2002-2004	342

Participants may earn additional performance shares ifCinergy's TSR exceeds that of the peer group. For the 2000-2001 performance period (Cycle III), 372,149 shares were earned, based on a TSR of 140%.

(ii) SOP

The SOP is designed to align executive compensation with shareholder interests. Under the SOP, incentive and non-qualified stock options, stock appreciation rights (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% per year, beginning on the grant date, and expire ten 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% of the fair market value of a share of common stock on the first date of the 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 2001, 2000, and 1999 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, 1998		3,676,514		$	28.28	297,374		$	31.83
	Options granted	2,866,100			25.41	368,889			27.73
	Options exercised	(259,865	)		21.51	(266	)		31.83
	Options forfeited	(95,500	)		31.97	(306,692	)		31.70

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 Exercisable(1):
	At December 31, 1999	1,986,749		$	25.17
	At December 31, 2000	3,195,191		$	26.20
	At December 31, 2001	3,763,558		$	27.32

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

The weighted average fair value of options granted under the combined LTIP and the SOP plans was $5.42 in 2001, $2.75 in 2000, and $2.60 in 1999. The weighted average fair value of options granted under the Employee Stock Purchase and Savings Plan was $5.85 in 2001, and $3.89 in 1999 (no options were granted in 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						Employee Stock Purchase and Savings Plan(1)
	2001		2000		1999		2001		1999
Risk-free interest rate	4.78	%	6.57	%	5.86	%	4.22	%	4.98	%
Expected dividend yield	5.42	%	7.32	%	7.13	%	5.26	%	6.17	%
Expected lives	5.37	yrs.	4.86	yrs.	6.55	yrs.	2.17	yrs.	2.17	yrs.
Expected volatility	25.01	%	20.18	%	19.42	%	30.67	%	22.79	%

(1): Options were not granted under the Employee Stock Purchase and Savings Plan in 2000.

Price ranges, along with certain other information, for options outstanding under the combined LTIP and SOP plan at December 31, 2001, 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
$17.35 — $23.81	2,885,473	$23.55	6.64 yrs.	1,674,393	$23.37
$23.88 — $32.65	2,489,905	$25.67	6.23 yrs.	1,089,165	$25.24
$33.50 — $38.59	2,072,400	$35.67	6.87 yrs.	1,000,000	$36.19

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

In December 1999,Cinergy Corp. adopted the Director, Officer, and Key Employee Stock Purchase Program (the Program). The purpose of the Program is to facilitate the purchase and ownership ofCinergy 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 byCinergy 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% 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 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 ofCinergy Corp. stock on or before February 2005. The number of shares to be issued is contingent upon the market price ofCinergy Corp. stock, but subject to predetermined ceiling and floor prices. See Note 4 for further discussion of these securities.

3. Change in Preferred Stock of Subsidiaries

In 2000,PSI redeemed 289,250 shares of its $100 par value, 6.875% Series preferred stock for $29 million. All other preferred stock redemptions from 1999 to 2001 were immaterial forCG&E andPSI. Refer to the Statements of Capitalization ofCG&E andPSI for detailed information on preferred stock.

4. Preferred Trust Securities

In December 2001,Cinergy Corp. issued approximately $316 million notional amount of combined securities consisting of (a) 6.9% preferred trust securities, due February 2007, and (b) stock purchase contracts obligating the holders to purchase between 9.2 and 10.8 million shares ofCinergy Corp. common stock on 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 downCinergy 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%, to yield $316 million in the remarketing. The holders will use the proceeds from this remarketing to fund their obligation to purchase shares ofCinergy 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 securities were issued through a wholly-owned trust ofCinergy Corp. The preferred trust securities are recorded onCinergy Corp.'s Balance Sheets, net of discount and expense, asCompany obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company. The fair value of the stock purchase contract was charged toPaid-in capital with a corresponding credit toNon-current liabilities—other.

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

5. Long-Term Debt

Refer to the Statements of Capitalization for detailed information forCG&E,PSI, andULH&P. In addition,Cinergy Corp. and Global Resources also have the following total long-term debt (excludingLong-term debt due within one year, which is reflected inCurrent liabilities in the Balance Sheets):

				December 31
				2001			2000
				(in thousands)
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%)			500,341			—

			Total Other Long-term Debt		900,341			400,000
	Unamortized Discount				(255	)		(265	)

			Total—Cinergy Corp.	$	900,086		$	399,735

Global Resources
	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 2015			14,042			14,156
		Variable interest rate of LIBOR plus 2.5%, due July 2015			5,840			6,323
		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			8,314
		Fixed interest rates 6.1% - 7.4% maturing March 2003 to May 2003			10,271			18,783
		Fixed interest rates ranging between 9.423% and 9.911%, maturing September 2010 to September 2019			13,420			—
		Fixed interest rate of 11.5%, maturing December 2023 to March 2025			17,850			—
		Variable interest rate of EURIBOR plus 1.2%, maturing November 2016			52,274			—

			Total Other Long-term Debt		266,449			197,576
	Unamortized Discount				(227	)		(260	)

			Total—Global Resources		266,222			197,316

Operating Companies
	CG&E and subsidiaries			$	1,105,333		$	1,205,061
	PSI				1,325,089			1,074,255

			Total—Operating Companies	$	2,430,422		$	2,279,316

Total—Cinergy				$	3,596,730		$	2,876,367

In January 2001,PSI retired $19.8 million principal amount of non-interest bearing Series 1994A Promissory Note, which had matured. The securities were not replaced by new issues of debt. In June 2001,PSI issued $325 million principal amount of First Mortgage Bonds Series EEE, 6.65% with a maturity date of June 15, 2006. The net proceeds of the offering were used to repay short-term indebtedness. In November 2001, the note holders exercised their option to call the $50 millionPSI 6% Putable/Callable Notes (Notes) on December 14, 2001, with the intent to reset the interest rate and

remarket the Notes. However, in December 2001,PSI exercised its option to purchase, and subsequently retired the Notes.

In September 2001,Cinergy Corp. issued $500 million principal amount of 6.25% debentures with a maturity date of September 1, 2004. The net proceeds of the offering were used to repay short-term indebtedness. In October 2001,Cinergy Corp. executed three receive-fixed, pay-floating interest rate swaps with a combined notional amount of $250 million. These swaps are designated as fair value hedges of 50% ofCinergy Corp.'s $500 million debentures issue.

During 2001, Global Resources borrowed funds at variable and fixed rates to fund various projects. These loans are classified asLong-term debt andLong-term debt due within one year based upon scheduled maturities.

The following table reflects the long-term debt maturities, excluding any redemptions due to the exercise of call or put 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.

	Cinergy(1)		CG&E and subsidiaries			PSI
	(in millions)
2002	$	148	$	100		$	23
2003		92		20	(2)		58
2004		814		110			1
2005		3		—			1
2006		334		—			328
Thereafter(3)		2,365		978			945

	$	3,756	$	1,208		$	1,356

(1): The results ofCinergy also include amounts related to non-registrants.
(2): CG&E and subsidiaries includesULH&P's $20 million maturing in 2003.
(3): Includes long-term debt with put provisions of $100 million in 2003 and $150 million in 2005 forCG&E and $50 million in 2005 forPSI.

Maintenance and replacement fund provisions contained inPSI'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 toPSI's net revenues.

6. Notes Payable and Other Short-term Obligations

Short-term obligations may include:

•: short-term notes;
•: commercial paper;
•: variable rate pollution control notes; and
•: money pooling.

Short-term Notes

Short-term borrowings mature within one year from the date of issuance. We primarily use unsecured revolving lines of credit for short-term borrowings. A portion of each company's revolving lines is used to provide credit support for commercial paper (discussed below). 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 periods 1999, 2000, and 2001.

At December 31, 2001,Cinergy Corp. had $437 million remaining unused and available capacity relating to its $1.2 billion revolving credit facilities. In February 2001,Cinergy Corp. placed a $400 million, 364-day senior revolving credit facility and in March 2001,Cinergy Corp. placed a $500 million, 364-day senior revolving credit facility. These facilities provide short-term financing. Also, in May 2001,Cinergy Corp. placed a $400 million, three-year senior revolving credit facility. This facility replacedCinergy Corp.'s $400 million, five-year revolving credit facility that expired in May 2001, and its $200 million, three-year revolving credit facility that expired in July 2001. In December 2001,Cinergy Corp. permanently reduced the size of its $500 million, 364-day senior revolving credit facility to $225 million.

In early 2002,Cinergy Corp. placed a $600 million, 364-day senior revolving credit facility. This facility replaces the $400 million, 364-day senior revolving credit facility that expired in February 2002 and will replace the $225 million, 364-day senior revolving credit facility expiring in March 2002, and a $150 million, three-year senior revolving credit facility expiring in June 2002.

In addition to revolving credit facilities,Cinergy Corp.,CG&E, andPSI 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. At December 31, 2001,Cinergy Corp.'s $40 million uncommitted line andCG&E's $15 million uncommitted line were unused.PSI's uncommitted line of $60 million was fully drawn at year-end.

Commercial Paper

In early 2001,Cinergy Corp. expanded the commercial paper program to a maximum outstanding principal amount of $800 million and reduced the established lines of credit atCG&E andPSI. The expansion of the commercial paper program at theCinergy Corp. level supports, in part, the short-term borrowing needs ofCG&E andPSI and eliminates their need for separate commercial paper programs. As of December 31, 2001,Cinergy Corp. had $125 million in commercial paper outstanding.

Variable Rate Pollution Control Notes

CG&E andPSI have issued variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development to control pollution). Because the holders of these notes have the right to redeem their notes on any business day, with the remainder being redeemable annually, they are reflected inNotes payable and other short-term obligations in the Balance Sheets ofCinergy,CG&E, andPSI.

In August 2001,CG&E issued $12.1 million of Ohio Air Quality Development Authority Air Quality Development Revenue Bonds 2001, Series A with a final maturity date of August 1, 2033, and an initial interest rate of 3.7%. The interest rate will reset annually on August 1, as negotiated, based on the Municipal Market Data Index as a benchmark. The net proceeds were used to finance the cost of air quality and solid waste disposal facilities at the William H. Zimmer Generating Station (Zimmer Station).

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

		December 31, 2001						December 31, 2000
		Established Lines		Outstanding		Weighted Average Rate		Established Lines		Outstanding		Weighted Average Rate
		(in millions)
Cinergy Corp.
	Revolving lines(1)	$	1,175	$	599	2.55	%	$	750	$	359	6.84	%
	Uncommitted lines		40		—	—			45		12	7.25
	Commercial paper		800		125	3.49			400		216	7.06
Operating companies
	Revolving lines		—		—	—			180		180	7.18
	Uncommitted lines		75		66	3.73			125		5	7.00
	Pollution control notes		N/A		279	2.10			N/A		267	4.52
Non-regulated subsidiaries
	Revolving lines		46		38	3.37			13		11	5.86
	Short-term debt		49		49	4.90			79		79	6.77

Cinergy Total				$	1,156	2.74	%			$	1,129	6.38	%
CG&E and subsidiaries
	Revolving lines	$	—	$	—	—	%	$	80	$	80	7.06	%
	Uncommitted lines		15		—	—			40		—	—
	Pollution control notes		N/A		196	2.00			N/A		184	4.61

CG&E Total				$	196	2.00	%			$	264	5.35	%
PSI
	Revolving lines	$	—	$	—	—	%	$	100	$	100	7.27	%
	Uncommitted lines		60		66	3.73			85		5	7.00
	Pollution control notes		N/A		83	2.33			N/A		83	4.34

PSI Total				$	149	2.95	%			$	188	5.97	%

(1): Excludes a $600 million credit facility placed in the first quarter of 2002.

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 thanCinergy 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 asNotes receivable from affiliated companies orNotes payable to affiliated companies on the Balance Sheets ofCG&E,PSI, andULH&P.

7. Sales of Accounts Receivable

CG&E,PSI, andULH&P have 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 retains servicing responsibilities for its role as a collection agent of the amounts due on the sold receivables. However, the purchaser assumes the risk of collection on the sold

receivables without recourse toCG&E,PSI, andULH&P in the event of a loss. Proceeds from a portion of the sold receivables are held back as a reserve to reduce the purchaser's credit risk.CG&E,PSI, andULH&P do not retain any ownership interest in the sold receivables, but do retain undivided interests in their remaining balances of accounts receivable. The recorded amounts of the retained interests are measured at net realizable value.

TheAccounts receivable on the Balance Sheets ofCinergy,CG&E,PSI, andULH&P are net of the amounts sold at December 31, 2001, and 2000.

The following table shows the receivables sold, the associated reserves held back, and the net amounts received as of December 31, 2001, and 2000:

	Receivables Sold		Reserves		Net Amount
	(in millions)
2001
Cinergy	$	322	$	65	$	257
CG&E and subsidiaries		188		38		150
PSI		134		27		107
ULH&P		27		5		22
2000
Cinergy	$	316	$	59	$	257
CG&E and subsidiaries		192		36		156
PSI		124		23		101
ULH&P		32		6		26

8. 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, 2001:

	Actual Payments						Estimated Minimum Payments
	1999		2000		2001		2002		2003		2004		2005		2006		After 2006		Total
	(in millions)						(in millions)
Cinergy(1)	$	50	$	56	$	61	$	45	$	36	$	26	$	21	$	18	$	61	$	207
CG&E and subsidiaries		27		30		33		20		15		10		7		6		15		73
PSI		21		21		21		17		14		9		7		7		23		77
ULH&P(2)		4		4		5		—		—		—		—		—		—		—

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

(b) Capital Leases

In 2001, 2000, and 1999,CG&E,PSI, andULH&P entered into capital lease agreements to fund the purchase of gas and electric meters. The lease terms are for 120 months commencing December 2001, 2000, and 1999, with early buyout options at 48, 72, and 105 months. Since the objective is to own the meters indefinitely, the companies plan to exercise the buyout option at month

105. The lease rates used to determine the monthly payments were 6.00%, 6.09%, and 6.71% for 2001, 2000, and 1999, respectively. The meters are depreciated at the same rate as if they were owned by the companies.CG&E,PSI, andULH&P each recorded a capital lease obligation, included inNon-current liabilities—other.

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)	$	46		$	26		$	20		$	8
Less: amount representing interest		(11	)		(6	)		(5	)		(2	)

Present value of minimum lease payments	$	35		$	20		$	15		$	6

(1): Annual minimum lease payments are immaterial.

In 2000,CG&E entered into a capital lease agreement to fund the purchase of equipment for Zimmer Station. In August 2001,CG&E purchased the equipment at Zimmer Station, effectively terminating the lease.

In 1996,CG&E entered into a sale-leaseback agreement for certain equipment at Woodsdale Generating Station. The lease was a capital lease with an initial lease term of five years expiring on October 31, 2001. At the end of this term,CG&E purchased the equipment.

9. Financial Instruments

(a)Financial Derivatives

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

(i) Interest Rate Risk Management

Our current policy in managing exposure to fluctuations in interest rates is to maintain the total amount of outstanding debt in floating interest rate debt instruments of approximately 30%. In maintaining this level of exposure, we use interest rate swaps. Under these 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 inAccumulated other comprehensive income (loss), beginning with our adoption of Statement 133 on January 1, 2001. In October 2001,Cinergy Corp. executed three interest rate swaps with a combined notional amount of $250 million. Under the provisions of the swaps,Cinergy Corp. will receive fixed-rate interest payments and pay 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. 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.

(ii) Foreign Exchange Hedging Activity

From time to time, we may utilize foreign exchange forward contracts and currency swaps to hedge foreign currency denominated purchase and sale commitments and certain of our net investments in foreign operations. These contracts and swaps allow us to potentially hedge our position against currency exchange rate fluctuations and would qualify as derivatives.

Cinergy has exposure to fluctuations in exchange rates between the U.S. dollar and the currencies of foreign countries where we have investments. When it is appropriate we will hedge our exposure to cash flow transactions, such as a dividend payment by one of our foreign subsidiaries. As of December 31, 2001, we had no outstanding foreign currency derivatives.

(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, 2001				December 31, 2000
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Cinergy(1)
First mortgage bonds and other long-term debt (includes amounts reflected asLong-term debt due within one year)	$	3,745	$	3,805	$	2,917	$	2,950
CG&Eand subsidiaries
First mortgage bonds and other long-term debt (includes amounts reflected asLong-term debt due within one year)	$	1,205	$	1,214	$	1,206	$	1,203
PSI
First mortgage bonds and other long-term debt (includes amounts reflected asLong-term debt due within one year)	$	1,348	$	1,379	$	1,113	$	1,136
ULH&P
Other long-term debt	$	75	$	76	$	75	$	76

(1): The results ofCinergy also include amounts related to non-registrants.

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.

(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, 2001, we do not believe we had significant exposure to credit risk with our trade accounts receivable or our physical portfolio.

(ii) Energy Trading

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, 2001, approximately 97% of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or higher. 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 courts 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. While most of our contracts with Enron were considered trading and thus recorded at fair value, a few contracts were accounted for utilizing the normal exemption under Statement 133 (see Note 1(k)). These contracts were recognized at fair value when the contracts were terminated in the fourth quarter of 2001. Fair value for these contracts, and all terminated contracts with Enron, is governed by the provisions of each contract, but typically approximates fair value at contract termination. However, the effect of the loss of Enron's participation in the energy markets on long-term liquidity and price volatility, or on the creditworthiness of common counterparties cannot be determined. We continually review and monitor our credit exposure to all counterparties and adjust the fair value of our position, as appropriate.

(iii) Financial Derivatives

Potential exposure to credit risk also exists from our use of financial derivatives such as currency swaps, foreign exchange forward contracts, and interest rate swaps. Because these financial instruments are transacted only with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.

10. Pension and Other Postretirement Benefits

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

Our 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. NeitherCG&E norULH&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.

In 2000,Cinergy offered early retirement plans to certain individuals under a Limited Early Retirement Program (LERP). 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 a one-time expense of $12.8 million in 2000.

Our benefit plans' costs for the past three years, as well as the actuarial assumptions used in determining these costs, included the following components:

		Pension Benefits									Other Postretirement Benefits
		2001			2000			1999			2001			2000			1999
		(in millions)
Service cost		$	27.9		$	27.4		$	24.8		$	3.8		$	3.4		$	3.5
Interest cost			77.5			73.0			70.8			17.9			17.0			16.2
Expected return on plans' assets			(81.9	)		(77.0	)		(72.0	)		—			—			—
Amortization of transition (asset) obligation			(1.3	)		(1.3	)		(1.3	)		5.0			5.0			5.0
Amortization of prior service cost			4.6			4.5			4.5			—			—			—
Recognized actuarial (gain) loss			(3.2	)		(2.4	)		0.6			0.1			—			0.8
LERP Statement 88 cost			—			11.9			—			—			—			—

Net periodic benefit cost		$	23.6		$	36.1		$	27.4		$	26.8		$	25.4		$	25.5
Actuarial assumptions:
	Discount rate		7.50	%		7.50	%		7.50	%		7.50	%		7.50	%		7.50	%
	Rate of future compensation increase		4.00			4.50			4.50			N/A			N/A			N/A
	Rate of return on plans' assets		9.25			9.00			9.00			N/A			N/A			N/A

For measurement purposes, we assumed an eight percent annual rate of increase in the per capita cost of covered health care benefits for 2001. It was assumed that the rate would decrease gradually to five percent in 2008 and remain at that level thereafter.

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, 2001, and a statement of the funded status as of December 31 of both years.

	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of period	$	1,064.5		$	1,002.0		$	247.1		$	234.4
Service cost		27.9			27.4			3.8			3.4
Interest cost		77.5			73.0			17.9			17.0
Amendments(1)		18.0			13.1			—			—
Actuarial (gain) loss		(43.6	)		12.0			17.9			6.7
Benefits paid		(60.8	)		(63.0	)		(16.3	)		(14.4	)

Benefit obligation at end of period		1,083.5			1,064.5			270.4			247.1
Change in plan assets
Fair value of plan assets at beginning of period		1,043.6			946.1			—			—
Actual return on plan assets		(108.1	)		160.5			—			—
Employer contribution		0.7			—			16.3			14.4
Benefits paid		(60.8	)		(63.0	)		(16.3	)		(14.4	)

Fair value of plan assets at end of period		875.4			1,043.6			—			—
Funded status		(208.1	)		(20.9	)		(270.4	)		(247.1	)
Unrecognized prior service cost		50.0			36.6			—			—
Unrecognized net actuarial (gain) loss		(100.1	)		(249.6	)		45.7			26.6
Unrecognized net transition (asset) obligation		(3.2	)		(4.5	)		50.8			55.8

Accrued benefit cost at December 31	$	(261.4	)	$	(238.4	)	$	(173.9	)	$	(164.7	)

(1): For 2000, the amount of $13.1 million includes $11.9 million of LERP expenses in accordance with Statement 88, as previously discussed.

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	$	3.2	$	(2.8	)
Effect on postretirement benefit obligation		34.7		(30.3	)

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.

The pension benefit obligations and pension cost under these plans were as follows:

	2001		2000
	(in millions)
Pension benefit obligation	$	70.9	$	67.0
Pension cost		8.7		8.3

11. Disposition of Unconsolidated Subsidiary

On July 15, 1999, we sold our 50% ownership interest in Midlands Electricity plc (Midlands) to GPU, Inc. In exchange for our interest in Midlands, we received 452.5 million pounds sterling (approximately $700 million). As a result of the transaction, we realized a net contribution to earnings of approximately $.43 EPS and EPS-assuming dilution, after deducting financing, transaction, and currency costs.

The pro forma information presented below reflectsCinergy's net income and EPS without the investment in Midlands for 1999.

		Year Ended December 31 1999
		Net Income			EPS(1)
		(in millions, except for earnings per share)
Reported results		$	404		$	2.54
Pro forma adjustments:
	Equity in earnings of Midlands		(58	)
	Gain on sale of investment in Midlands		(99	)
	Interest		21
	Income taxes		40

Pro forma results		$	308		$	1.94

(1): Represents basic EPS. Actual EPS — assuming dilution were $2.53, and pro forma EPS — assuming dilution were $1.93.

12. Income Taxes

The following table shows the significant components ofCinergy's,CG&E's, andPSI's net deferred income tax liabilities as of December 31, 2001, and 2000:

		Cinergy(1)				CG&E and subsidiaries				PSI
		2001		2000		2001		2000		2001		2000
		(in millions)				(in millions)				(in millions)
Deferred Income Tax Liability
	Property, plant, and equipment	$	1,172.0	$	1,135.9	$	708.0	$	703.0	$	453.2	$	432.8
	Unamortized costs of reacquiring debt		13.4		18.2		3.2		8.1		10.2		10.1
	Deferred operating expenses and carrying costs		10.3		60.2		—		40.7		10.3		19.5
	Purchased power tracker		9.7		—		—		—		9.7		—
	RTC		206.0		—		206.0		—		—		—
	Net energy risk management assets		12.2		—		8.4		—		—		—
	Amounts due from customers—income taxes		22.9		96.2		16.0		91.2		6.9		5.0
	Gasification services agreement buyout costs		92.3		94.8		—		—		92.3		94.8
	Other		47.6		60.9		8.7		37.0		2.3		9.0

Total Deferred Income Tax Liability			1,586.4		1,466.2		950.3		880.0		584.9		571.2
Deferred Income Tax Asset
	Unamortized investment tax credits		45.9		56.1		36.0		42.8		10.0		13.2
	Accrued pension and other benefit costs		162.4		137.7		96.6		67.5		47.2		39.8
	Net energy risk management liabilities		—		24.6		—		6.1		5.5		18.5
	Rural Utilities Service (RUS) obligation		28.2		28.2		—		—		28.2		28.2
	Other		48.5		33.6		38.4		27.8		7.3		12.9

Total Deferred Income Tax Asset			285.0		280.2		171.0		144.2		98.2		112.6
Net Deferred Income Tax Liability		$	1,301.4	$	1,186.0	$	779.3	$	735.8	$	486.7	$	458.6

(1): The results ofCinergy also include amounts related to non-registrants.

We will file a consolidated federal income tax return for the year ended December 31, 2001. The current tax liability is allocated among the members of theCinergy consolidated group, pursuant to a tax sharing agreement filed with the SEC under the PUHCA.

The following table summarizes federal and state income taxes charged (credited) to income forCinergy,CG&E, andPSI:

			Cinergy(1)									CG&E and subsidiaries									PSI
			2001			2000			1999			2001			2000			1999			2001			2000			1999
			(in millions)									(in millions)									(in millions)
Current Income Taxes
	Federal		$	122.4		$	187.3		$	114.0		$	135.1		$	121.5		$	137.3		$	59.9		$	84.4		$	(30.6	)
	State			9.3			16.9			(1.5	)		7.6			1.6			4.0			4.6			10.8			(3.1	)

Total Current Income Taxes				131.7			204.2			112.5			142.7			123.1			141.3			64.5			95.2			(33.7	)
Deferred Income Taxes
	Federal
		Depreciation and other property, plant, and equipment-related items		42.7			26.1			24.0			23.3			19.0			13.8			10.7			7.1			10.2
		Pension and other benefit costs		(11.8	)		(21.3	)		(10.5	)		(4.2	)		(7.5	)		(5.3	)		(7.6	)		(11.5	)		(5.0	)
		Deferred excise taxes		14.5			—			—			14.5			—			—			—			—			—
		Unrealized energy risk management transactions		44.0			10.9			(5.1	)		23.9			5.6			(11.6	)		11.6			2.0			6.5
		Fuel costs		5.7			28.7			4.3			(8.0	)		26.7			2.7			13.7			2.0			1.6
		Purchased power tracker		8.5			—			—			—			—			—			8.5			—			—
		Gasification services agreement buyout costs		(2.2	)		(0.1	)		83.6			—			—			—			(2.2	)		(0.1	)		83.6
		Other—net		16.1			11.0			(5.1	)		(4.8	)		(3.0	)		8.3			5.3			(1.2	)		(4.5	)

Total Deferred Federal Income Taxes				117.5			55.3			91.2			44.7			40.8			7.9			40.0			(1.7	)		92.4
	State			15.4			1.7			14.2			5.0			1.5			0.6			4.8			(1.4	)		13.6

Total Deferred Income Taxes				132.9			57.0			105.4			49.7			42.3			8.5			44.8			(3.1	)		106.0
Investment Tax Credits—Net				(9.1	)		(9.6	)		(9.2	)		(5.9	)		(6.0	)		(6.1	)		(3.2	)		(3.6	)		(3.1	)

Total Income Taxes			$	255.5		$	251.6		$	208.7		$	186.5		$	159.4		$	143.7		$	106.1		$	88.5		$	69.2

(1): The results ofCinergy also include amounts related to non-registrants.

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 forCinergy,CG&E, andPSI.

		Cinergy(1)									CG&Eand subsidiaries									PSI
		2001			2000			1999			2001			2000			1999			2001			2000			1999
		(in millions)									(in millions)									(in millions)
Statutory federal income tax provision		$	235.6		$	221.3		$	209.9		$	175.2		$	148.1		$	130.4		$	90.7		$	75.1		$	61.6
Increases (Reductions) in taxes resulting from:
	Amortization of investment tax credits		(9.1	)		(9.6	)		(9.2	)		(5.9	)		(6.0	)		(6.1	)		(3.2	)		(3.6	)		(3.1	)
	Depreciation and other property, plant, and equipment-related differences		3.2			17.7			14.4			2.6			14.0			11.6			0.6			3.6			2.8
	Preferred dividend requirements of subsidiaries		1.2			1.6			1.9			—			—			—			—			—			—
	Foreign tax adjustments		(1.3	)		—			(15.5	)		—			—			—			—			—			—
	Other—net		1.2			2.0			(5.5	)		2.0			0.2			3.2			8.6			4.0			(2.6	)

Federal Income Tax Expense		$	230.8		$	233.0		$	196.0		$	173.9		$	156.3		$	139.1		$	96.7		$	79.1		$	58.7

(1): The results ofCinergyalso include amounts related to non-registrants.

The following table shows the significant components ofULH&P's net deferred income tax liability as of December 31, 2001 and 2000:

		ULH&P
		2001		2000
		(in thousands)
Deferred Income Tax Liability
	Property, plant, and equipment	$	34,218	$	32,674
	Unamortized costs of reacquiring debt		699		747
	Deferred fuel costs		—		6,934
	Other		4,158		3,620

Total Deferred Income Tax Liability			39,075		43,975
Deferred Income Tax Asset
	Unamortized investment tax credits		1,035		1,309
	Amounts due to customers-income taxes		2,524		2,627
	Deferred fuel costs		520		—
	Accrued pension and other benefit costs		3,947		2,660
	Other		2,726		1,557

Total Deferred Income Tax Asset			10,752		8,153
Net Deferred Income Tax Liability		$	28,323	$	35,822

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

			ULH&P
			2001			2000			1999
			(in thousands)
Current Income Taxes
	Federal		$	23,109		$	5,003		$	8,668
	State			(2,293	)		(129	)		2,253

Total Current Income Taxes				20,816			4,874			10,921
Deferred Income Taxes
	Federal
		Depreciation and other property, plant, and equipment-related items		1,042			1,059			831
		Pension and other benefit costs		(140	)		(605	)		40
		Fuel costs		(7,338	)		8,564			(1,385	)
		Unamortized costs of reacquiring debt		(30	)		(30	)		(39	)
		Service company allocations		192			251			324
		Other—net		212			(338	)		(155	)

Total Deferred Federal Income Taxes				(6,062	)		8,901			(384	)
Deferred State Income Taxes				(781	)		303			(76	)

Total Deferred Income Taxes				(6,843	)		9,204			(460	)
Investment Tax Credits—Net				(274	)		(277	)		(277	)
Total Income Taxes			$	13,699		$	13,801		$	10,184

		ULH&P
		2001			2000			1999
		(in thousands)
Statutory federal income tax provision		$	18,444		$	13,391		$	7,098
Increases (Reductions) in taxes resulting from:
	Amortization of investment tax credits		(274	)		(277	)		(277	)
	Depreciation and other property, plant, and equipment-related differences		23			830			94
	Other—net		(1,420	)		(317	)		1,092

Federal Income Tax Expense		$	16,773		$	13,627		$	8,007

13. Commitments and Contingencies

(a)Construction and Other Commitments

Forecasted construction and other committed expenditures, including AFUDC, for the year 2002 and for the five-year period 2002-2006 (in nominal dollars) are presented in the table below:

	2002		2002-2006
	(in millions)
Cinergy(1)	$	889	$	3,070
CG&E and subsidiaries		275		1,135
PSI		478		1,522
ULH&P		43		212

(1): The results ofCinergyalso include amounts related to non-registrants.

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

Cinergy Corp.has made separate guarantees to certain counterparties regarding performance of commitments by our consolidated subsidiaries, unconsolidated subsidiaries and joint ventures. We are subject to an SEC order under PUHCA, which limits the amount we can have outstanding under guarantees at any one time to $2 billion. As of December 31, 2001, we had $558 million outstanding under the guarantees issued, of which approximately 70% represents guarantees of obligations reflected onCinergy's Consolidated Balance Sheet. These outstanding guarantees relate to subsidiary and joint venture indebtedness and performance commitments.

(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. In late 1997, the EPA published a proposed call for revisions to State Implementation Plans (SIPs) for achieving emissions reductions to address air quality concerns. The EPA must approve all SIPs.

(i) NO_X 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 states reduce NO_X emissions primarily from industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999, to incorporate NO_X reductions and, at the discretion of the state, a NO_X trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NO_X reductions by May 1, 2003, if states failed to revise their SIPs.

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).

Following a number of rulings and appeals, in August 2000, the Court of Appeals extended the deadline for NO_X reductions to May 31, 2004. The states and other groups sought review of the Court of Appeals ruling by the U.S. Supreme Court (Supreme Court). In March 2001, the Supreme Court decided not to grant that review.

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. It is unclear whether this decision will result in an increase or decrease in the size of the NO_X reduction requirement. On August 3, 2001, the EPA published, in the Federal Register, a notice of data availability for justification of the state NO_X budgets. Comments on the justification were filed prior to the September 19, 2001 deadline by various industry groups (some of which we are members) and states.

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. The EPA is expected to approve Kentucky's rules in the near future. The state of Ohio is still in the process of developing its NO_X SIP rules in response to the NO_XSIP Call.Cinergy's current plans for compliance with the EPA's NO_X SIP Call would also satisfy compliance with Indiana's SIP rules and Kentucky's proposed rules.

On September 25, 2000,Cinergy announced a plan for its subsidiaries,CG&E andPSI, to invest in pollution control equipment and other methods to reduce NO_X emissions. The current estimate of additional expenditures for this investment is approximately $550 million (in nominal dollars) and includes the following:

•: install selective catalytic reduction units (SCRs) at several different generating stations;
•: install other pollution control technologies, including new computer software, at all generating stations;
•: make combustion improvements; and
•: utilize market opportunities to buy and sell NO_X allowances.

SCRs are the most proven technology currently available for reducing NO_X emissions produced in coal-fired generating stations.

(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.

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 January 19, 2002, the EPA issued a memorandum to all Regional Air Division Directors confirming that the Agency would extend the Section 126 rule compliance deadline to May 31, 2004, thus harmonizing the deadline with that for NO_XSIP Call.

(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. Indiana and Kentucky committed to adopt utility NO_Xcontrol rules by December 2000, that would require controls be installed by May 2003. However, Indiana halted the rulemaking for NO_X controls at this level, but completed NO_X SIP Call level reduction regulations. Kentucky has completed its rulemaking, and issued a final rule that changed the compliance deadline to mirror the NO_X SIP Call of May 31, 2004. However, on November 1, 2001, the intent to withdraw the regulation was noted in the Kentucky Administrative Register.

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. In July 1998, the EPA requested comments on proposed revisions to the NSR rules that could have the affect of changing NSR applicability by limiting exemptions contained in the current regulation. On June 22, 2001, the EPA issued an NSR 90-Day Review Paper and scheduled four public forums across the U.S. to gather more information on the impacts of NSR.Cinergy provided oral testimony at an EPA public forum held in Cincinnati, Ohio, on July 10, 2001, and submitted written comments as well.

Since July 1999,CG&E andPSI have received requests from the EPA (Region 5), under Section 114 of the CAA, seeking documents and information regarding capital and maintenance expenditures at several of their respective generating stations. These requests were part of an industry-wide investigation assessing compliance with the NSR and the New Source Performance Standards (NSPS) of the CAA at electric generating stations.

On September 15, 1999, November 3, 1999, and February 2, 2001, the Attorneys General of New York, Connecticut, and New Jersey, respectively, issued letters notifyingCinergy andCG&E of their intent to sue under the citizens' suit provisions of the CAA. These states allege violations of the CAA by constructing and continuing to operate a major modification ofCG&E's W.C. Beckjord Generating Station (Beckjord Station) without obtaining the required NSR pre-construction permits.

On November 3, 1999, the EPA sued a number of holding companies and electric utilities, includingCinergy,CG&E, andPSI, in various U.S. District Courts (District Court). TheCinergy,CG&E, andPSI suit alleged violations of the CAA at two of our generating stations relating to NSR and NSPS requirements. The suit sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station and atPSI's Cayuga Generating Station (Cayuga Station), and (2) civil penalties in amounts of up to $27,500 per day for each violation.

On March 1, 2000, the EPA filed an amended complaint againstCinergy,CG&E, andPSI. The amended complaint added alleged violations of the NSR requirements of the CAA at two of our generating stations contained in a notice of violation (NOV) filed by the EPA on November 3, 1999. It also added claims for relief of alleged violations of nonattainment NSR, Indiana and Ohio SIPs, and particulate matter emission limits (as discussed below in the "Beckjord Station NOV" section).

The amended complaint sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station andPSI's Cayuga Station, Wabash River Generating Station, and Gallagher Generating Station, and such other measures as necessary, and (2) civil penalties in amounts of up to $27,500 per day for each violation.

On March 1, 2000, the EPA also filed an amended complaint in a separate lawsuit alleging violations of the CAA relating to NSR, Prevention of Significant Deterioration (PSD), and Ohio SIP requirements regarding various generating stations, including a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, the Dayton Power and Light Company (DP&L), andCG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. On April 4, 2001, the District Court in that case ruled that neither the Government nor the intervening plaintiff environmental groups could obtain civil penalties for any alleged violations that occurred more than five years prior to the filing of the complaint, but that both parties could seek injunctive relief for alleged violations that occurred more than five years before the filing of the complaint. Thus, if the plaintiffs prevail in their claims, any calculation for penalties will not start on the date of the alleged violations, unless those alleged violations occurred after November 3, 1994, but CSP would be forced to install the controls required under the CAA. Neither party appealed that decision.

On June 28, 2000, the EPA issued an NOV toCinergy,CG&E, andPSI for alleged violations of NSR, PSD, and SIP requirements atCG&E's Miami Fort Generating Station (Miami Fort Station) andPSI's Gibson Generating Station (Gibson Station). In addition,Cinergy andCG&E have been informed by DP&L, the operator of J.M. Stuart Generating Station (Stuart Station), that on June 30, 2000, the EPA issued an NOV to DP&L for alleged violations of NSR, PSD, and SIP requirements at this station.CG&E owns 39% of Stuart Station. The NOVs indicated that the EPA may (1) issue an order requiring compliance with the requirements of the SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation.

On August 2, 2001, the states of New York, New Jersey, and Connecticut filed an Assented to Motion to Intervene in this litigation. Their motion was granted by the District Court on August 3, 2001. The states' proposed complaint is an exhibit to the motion to intervene.Cinergy,CG&E, andPSI are in the process of evaluating the states' complaint but, at this time, are unable to determine the effect, if any, this filing will have on the issues affecting us regarding NSR, as framed in the EPA's Amended Complaint.

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

(e)Beckjord Station NOV

On November 30, 1999, the EPA filed an NOV againstCinergy andCG&E, alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit. The NOV indicated that the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. 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 and offered us an opportunity to meet and discuss the allegations and corrective measures. 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, andPSI reached an agreement in principle with the EPA, the U.S. Department of Justice (Justice Department), three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated byCinergy'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 NSR violations as well as the Beckjord Station NOVs/FOV discussed previously under (d) and (e).

Under the terms of the tentative agreement, the EPA and the other plaintiffs have agreed to drop all challenges of past maintenance and repair activities at our coal-fired generation plants. 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 permitting requirements.

In return for resolution of claims regarding past maintenance activities as well as future operational certainty, and demand growth, 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;
•: retire 50,000 tons of SO₂ allowances between 2001 and 2005 and reduce our SO₂ cap by 35% in 2013;
•: pay a civil penalty of $8.5 million to the U.S. government; and
•: implement $21.5 million in environmental mitigation projects.

The estimated cost for these capital expenditures is expected to be approximately $700 million. These capital expenditures are in addition to our previously announced commitment to install NO_X controls over the next four years as previously discussed in "Ozone Transport Rulemaking".

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.

In January 2002, the Justice Department completed its review of NSR, after considering dismissal of the lawsuits, and decided to pursue the pending lawsuits, including the suit againstCinergy,CG&E, andPSI. We will continue to pursue a negotiated settlement of these lawsuits if that continues to be in the best interests of the company. 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 on their claims or whether resolution of these matters would have a material effect on our financial condition or results of operations.

(g)Manufactured Gas Plant (MGP) Sites

(i) General

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.

(ii)PSI

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 whichPSI or its predecessors previously owned.PSI acquired four of the sites from Northern Indiana Public Service Company (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 (in 1994) and NIPSCO (in 1995) both made claims againstPSI. The basis of these claims was thatPSI 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 thatPSI was legally responsible for the costs of investigating and remediating the sites. In August 1997, NIPSCO filed suit againstPSI 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 MGP site.

In November 1998, NIPSCO, IGC, andPSI 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 againstPSI was dismissed. The parties have assigned lead responsibility for managing further investigation and remediation activities at each of the sites to one of the parties. Similar agreements were reached between IGC andPSI 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. Subsequently,PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims againstPSI, or (2) payPSI's costs of defense and compensatePSI 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 Superior Court (Superior Court) in July 1998. Discovery closed in the case at the end of August 2001.PSI and its insurance carriers filed briefs on various issues for decision by the Superior Court in hearings held in November 2001. In December 2001, the Superior Court rescheduled the trial to June 2002. On February 1, 2002, the Superior Court issued rulings on motions for summary judgment. The Superior Court granted the motions of several insurance carriers who claimed that there was insufficient evidence concerning the terms of their policies. The insurance policies in question were between 1950-1958 and 1961-1964. With respect to the remaining policies (between 1958-1961 and 1964-1984), the Superior Court denied all of the insurance carriers' motions. This included motions on the issues of Trigger of Coverage, Expected or Intended Damage, Late Notice and Voluntary Payments. The Superior Court found triable issues of fact for the jury to decide as to the former two issues, and ruled inPSI's favor, as a matter of law, on the latter two issues. The trial against the remaining insurance

carriers will go forward in June 2002. At the present time,PSI cannot predict the outcome of this litigation.

PSI has 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 does not believe it can provide an estimate of the reasonably possible total remediation costs for any site before a remedial investigation/feasibility study has been completed. To the extent remediation is necessary, the timing of the remediation activities impacts the cost of remediation. Therefore,PSI currently cannot determine the total costs that may be incurred in connection with the remediation of all sites, to the extent that remediation is required. According to current information, these future costs at the 21 Indiana MGP sites are not material to our financial condition or results of operations. Until investigation and remediation activities have been completed on these sites, we are unable to reasonably estimate the total costs and impact on our financial position or results of operations.

(iii)CG&E

CG&E and its utility subsidiaries are aware of potential sites where MGP activities have occurred at some time in the past. None of these sites is known to present a risk to the environment.CG&E and its utility subsidiaries have begun preliminary site assessments to obtain information about some of these MGP sites.

(h)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 three class action lawsuits 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. We intend to vigorously defend these lawsuits. At the present time,Cinergy cannot predict the outcome of these suits.

(i)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 aPSI 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 will reconsider its decision.PSI believes it has strong legal and factual arguments in its favor and that it will ultimately be permitted to recover these costs. However,PSI cannot definitively predict the ultimate outcome of this matter.

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 is scheduled for April 2002.

(j)Other

In compliance with an electric wholesale rate case settlement adopted by the FERC, effective February 2000,CG&E reduced the cost of fuel reflected in its wholesale base rates and revised its

wholesale fuel adjustment factor. Beginning March 1, 2000,ULH&P began passing through to retail customers the fuel costs incurred pursuant to the revised wholesale fuel adjustment factor, but did not synchronize the cost of fuel reflected in retail base rates with the reduced cost of fuel reflected in wholesale base rates.

In May 2001, the KPSC approved an offer of settlement byULH&P, which allows it to maintain existing retail electric base rates and fuel adjustment clause at current levels through December 2003 and limits electric rate increases for three years thereafter, resolving all related matters previously pending before the KPSC. The settlement also approved the proposed wholesale power supply contract betweenULH&P andCG&E, beginning January 1, 2002, and made the necessary determinations under the PUHCA, forCG&E to transfer its generating assets and liabilities to an exempt wholesale generator. In connection with this settlement,ULH&P recognized revenues of approximately $7.3 million in 2001, which had been previously reserved in 2000 subject to refund.

14. 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 byPSI. The Statements of Income reflectCG&E's andPSI's portions of all operating costs associated with the jointly-owned facilities.

CG&E's andPSI's investments in jointly-owned plant or facilities are as follows:

			Ownership Share		Property, Plant, and Equipment		Accumulated Depreciation		Construction Work in Progress
			(in millions)
CG&E
	Production:
		Miami Fort Station (Units 7 and 8)	64.00	%	$	222	$	127	$	68
		Beckjord Station (Unit 6)	37.50			43		28		3
		Stuart Station(1)	39.00			292		148		42
		Conesville Station (Unit 4)(1)	40.00			77		45		—
		Zimmer Station	46.50			1,235		367		7
		East Bend Station	69.00			336		194		36
		Killen Station(1)	33.00			187		105		7
	Transmission		Various			84		36		—
PSI
	Production:
		Gibson Station (Unit 5)	50.05			213		113		2
	Transmission and local facilities		94.68			2		1		—

(1): Station is not operated byCG&E.

15. Quarterly Financial Data (unaudited)

						CG&Eand subsidiaries
		Cinergy(1)								PSI
Quarter Ended		Cinergy(1)								PSI
Quarter Ended		2001		2000		2001		2000		2001		2000
		(in millions, except per share amounts)
March 31
	Operating Revenues	$	3,707	$	1,583	$	1,258	$	716	$	916	$	534
	Operating Income		249		274		154		181		85		102
	Net Income		120		138		82		96		41		50
	Basic EPS		.76		.87		N/A		N/A		N/A		N/A
	EPS — assuming dilution		.75		.87		N/A		N/A		N/A		N/A
June 30
	Operating Revenues	$	3,642	$	1,770	$	1,277	$	707	$	1,184	$	620
	Operating Income		178		167		98		113		66		49
	Net Income		83		75		49		56		34		19
	Basic EPS		.51		.47		N/A		N/A		N/A		N/A
	EPS — assuming dilution		.51		.47		N/A		N/A		N/A		N/A
September 30
	Operating Revenues	$	3,324	$	2,300	$	1,321	$	840	$	1,258	$	804
	Operating Income		275		196		166		81		110		63
	Net Income		128		94		89		39		57		31
	Basic EPS		.81		.59		N/A		N/A		N/A		N/A
	EPS — assuming dilution		.80		.58		N/A		N/A		N/A		N/A
December 31
	Operating Revenues	$	2,250	$	2,769	$	838	$	967	$	717	$	726
	Operating Income		240		225		194		153		69		83
	Net Income		111		92		107		76		30		35
	Basic EPS		.70		.58		N/A		N/A		N/A		N/A
	EPS — assuming dilution		.69		.58		N/A		N/A		N/A		N/A
Total
	Operating Revenues	$	12,923	$	8,422	$	4,694	$	3,230	$	4,075	$	2,684
	Operating Income		942		862		612		528		330		297
	Net Income		442		399		327		267		162		135
	Basic EPS		2.78		2.51		N/A		N/A		N/A		N/A
	EPS — assuming dilution		2.75		2.50		N/A		N/A		N/A		N/A

(1): The results ofCinergyalso include amounts related to non-registrants.

16. Financial Information by Business Segment

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).

The following section describes the activities of our business units as of December 31, 2001.

Energy Merchant manages wholesale generation and the domestic and foreign 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, both domestically and abroad. Energy Merchant also conducts the following activities:

•: energy risk management;
•: financial restructuring services;
•: proprietary arbitrage activities;
•: customized energy solutions; and
•: directs our renewable energy investing activities.

Regulated Businesses consists of a regulated, integrated utility, and regulated electric and gas transmission and distribution systems. Regulated Businesses plans, constructs, operates, and maintainsCinergy's transmission and distribution systems and delivers gas and electric energy to consumers, both domestically and abroad. Regulated Businesses also earns revenues from wholesale customers primarily by transmitting electric power throughCinergy'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 and includes the following products and services:

•: providing energy management and consulting services to customers that operate retail facilities;
•: providing various utility operations and infrastructure services to utilities (for example, providing underground locating and construction services for utilities); and
•: building and maintaining fiber optic telecommunication networks for businesses, municipalities, telecommunications carriers, and schools.

Power Technology also manages Cinergy Ventures, LLC (Ventures),Cinergy's venture capital subsidiary. Ventures invests in emerging energy technologies that can benefit futureCinergy business development activities.

Financial information by (1) business units, (2) products and services, and (3) geographic areas and long-lived assets for the years ending December 31, 2001, 2000, and 1999, are as follows:

Business Units

		2001
		Cinergy Business Units
		Energy Merchant		Regulated Businesses		Power Technology			Total		All Other(1)		Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues —
	External customers(3)	$	10,024	$	2,850	$	49		$	12,923	$	—	$	—		$	12,923
	Intersegment revenues(4)		144		—		—			144		—		(144	)		—
Depreciation(5)			137		238		3			378		—		—			378
Equity in earnings (losses) of unconsolidated subsidiaries			3		7		(8	)		2		—		—			2
Interest(6)			110		144		14			268		—		—			268
Income taxes			103		162		(9	)		256		—		—			256
Segment profit (loss)(7)			196		265		(19	)		442		—		—			442
Total segment assets			4,803		7,238		213			12,254		46		—			12,300
Investments in unconsolidated subsidiaries			131		132		76			339		—		—			339
Total expenditures for long-lived assets			769		630		—			1,399		—		—			1,399

(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 of Energy Merchant.
(3): The increase in 2001, as compared to 2000, is primarily due to the increase in volumes and average price realized on wholesale commodity transactions.
(4): 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.
(5): The components of Depreciation include depreciation of fixed assets and amortization of intangible assets.
(6): Interest income is deemed immaterial.
(7): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.

Business Units (cont.)

		2000
		Cinergy Business Units
		Energy Merchant(7)			Regulated Businesses(7)		Power Technology			Total		All Other(1)		Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues —
	External customers(3)	$	4,831		$	3,515	$	76		$	8,422	$	—	$	—		$	8,422
	Intersegment revenues		1,021			—		—			1,021		—		(1,021	)		—
Depreciation(4)			121			220		3			344		—		—			344
Equity in earnings (losses) of unconsolidated subsidiaries			(1	)		7		(1	)		5		—		—			5
Interest(5)			82			133		9			224		—		—			224
Income taxes			94			165		(7	)		252		—		—			252
Segment profit (loss)(6)			152			260		(13	)		399		—		—			399
Total segment assets			5,949			6,162		177			12,288		42		—			12,330
Investments in unconsolidated subsidiaries			453			33		52			538		—		—			538
Total expenditures for long-lived assets			130			387		—			517		3		—			520

(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 of Energy Merchant.
(3): The increase in 2000, as compared to 1999, is primarily due to the increase in volumes and average price realized on wholesale commodity transactions.
(4): The components of Depreciation include depreciation of fixed assets and amortization of intangible assets.
(5): Interest income is deemed immaterial.
(6): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.
(7): Effective January 2001, electric customer choice legislation was implemented in Ohio. For comparative purposes, the estimated pro forma adjustment to reflect this effect on the twelve months ended December 31, 2000 results would be as follows:

		Energy Merchant			Regulated Businesses
Operating revenues		$	(119	)	$	119
Segment profit (loss)		$	(41	)	$	41

Business Units (cont.)

		Cinergy Business Units
		Energy Merchant		Regulated Businesses		Power Technology			Total		All Other(1)		Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues —
	External customers	$	2,561	$	3,318	$	59		$	5,938	$	—	$	—		$	5,938
	Intersegment revenues		988		—		—			988		—		(988	)		—
Depreciation(3)			113		210		—			323		—		—			323
Gain on sale of investment in unconsolidated subsidiary			99		—		—			99		—		—			99
Equity in earnings (losses) of unconsolidated subsidiaries			59		1		(2	)		58		—		—			58
Interest(4)			89		142		3			234		1		—			235
Income taxes			50		165		(6	)		209		—		—			209
Segment profit (loss)(5)			169		245		(10	)		404		—		—			404
Total segment assets			3,584		5,889		97			9,570		47		—			9,617
Investments in unconsolidated subsidiaries			334		17		8			359		—		—			359
Total expenditures for long-lived assets			171		304		2			477		—		—			477

(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 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): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.

Products and Services
(in millions)

	Revenues
	Utility						Energy Marketing and Trading
Year	Electric		Gas		Total		Electric		Gas		Total		Other		Consolidated
2001	$	2,248	$	595	$	2,843	$	5,933	$	4,068	$	10,001	$	79	$	12,923
2000		3,019		497		3,516		2,365		2,445		4,810		96		8,422
1999		2,944		420		3,364		1,369		1,176		2,545		29		5,938

Geographic Areas and Long-Lived Assets
(in millions)

	Revenues
			International
Year	Domestic		United Kingdom(1)		All Other(2)		Total		Consolidated
2001	$	12,748	$	—	$	175	$	175	$	12,923
2000		8,339		—		83		83		8,422
1999		5,877		—		61		61		5,938

	Long-Lived Assets
			International
Year	Domestic		United Kingdom(1)		All Other(2)		Total		Consolidated
2001	$	9,682	$	—	$	482	$	482	$	10,164
2000		8,267		—		328		328		8,595
1999		7,841		2		277		279		8,120

(1): As discussed in Note 11, on July 15, 1999, we sold our 50% ownership interest in Midlands. Prior to the sale, Midlands had provided the majority of our international earnings.
(2): International revenues are primarily from assets which we own in the Czech Republic, the majority of which are four district heating plants. The Czech Republic assets and results of operations are consolidated into our financial statements.

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, 2001
EPS:
	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:
	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
Year ended December 31, 1999
EPS:
	Net income	$	403,641	158,863	$	2.54
Effect of dilutive securities:
	Common stock options			344
	Employee stock purchase and savings plan			22
	Contingently issuable common stock			26

EPS — assuming dilution:
	Net income plus assumed conversions	$	403,641	159,255	$	2.53

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 2001, 2000, and 1999, approximately two million shares per year were excluded from the EPS—assuming dilution calculation.

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 approvedCG&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 four million dollars from 2001 to 2005 in support of energy efficiency and weatherization services for low income customers;
•: The creation of a RTC designed to recoverCG&E's regulatory assets and other transition costs over a ten-year period;
•: Authority forCG&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 forCG&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 byCG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;
•: 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); and
•: CG&E has agreed to provide shopping credits to switching customers.

With regard to the PUCO's order, two parties filed applications for rehearing with the PUCO. On October 18, 2000, the PUCO denied these applications. One of the parties appealed to the Ohio Supreme Court in the fourth quarter of 2000 andCG&E subsequently intervened in that case. On April 6, 2001,CG&E filed for dismissal of this appeal. On July 25, 2001, the Ohio Supreme Court deniedCG&E's motion to dismiss.CG&E is unable to predict the outcome of this proceeding.

As indicated above, the August 31, 2000 order authorizesCG&E to transfer its generation assets to a non-regulated affiliate. In addition to the regulatory approvals received from the PUCO, the IURC, and the KPSC, this transfer requires the approval of the FERC and the SEC under PUHCA. On October 29, 2001,CG&E filed an application with the FERC seeking authorization to transfer these assets. As the transfer is contingent uponCG&E receiving FERC approval, SEC approval under PUHCA, and various third party consents, the timing and receipt of which are unknown, the completion date of the transfer of generation assets to a non-regulated affiliate cannot be predicted.

19. Comprehensive Income

The elements ofComprehensive income and their related tax effects for the years ended 2001, 2000 and 1999 are as follows:

		Comprehensive Income
		2001									2000									1999
		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	$	697,785		$	(255,506	)	$	442,279		$	651,023		$	(251,557	)	$	399,466		$	612,312		$	(208,671	)	$	403,641
Other comprehensive income (loss):
	Foreign currency translation adjustment		4,996			(3,355	)		1,641			721			1,353			2,074			(14,771	)		4,990			(9,781	)
	Minimum pension liability adjustment		(2,636	)		1,081			(1,555	)		(1,852	)		753			(1,099	)		(2,081	)		842			(1,239	)
	Unrealized gain (loss) on investment trusts		(1,345	)		504			(841	)		(2,778	)		649			(2,129	)		2,629			(543	)		2,086
	Cumulative effect of change in accounting principle		(4,026	)		1,526			(2,500	)		—			—			—			—			—			—
	Cash flow hedges		(4,477	)		1,698			(2,779	)		—			—			—			—			—			—

Total other comprehensive income (loss)			(7,488	)		1,454			(6,034	)		(3,909	)		2,755			(1,154	)		(14,223	)		5,289			(8,934	)

Total comprehensive income		$	690,297		$	(254,052	)	$	436,245		$	647,114		$	(248,802	)	$	398,312		$	598,089		$	(203,382	)	$	394,707

(1): The results ofCinergyalso include amounts related to non-registrants. Individual amounts forCG&E,PSI, andULH&Pare deemed immaterial.

The after-tax components ofAccumulated other comprehensive income (loss) as of December 31, 2001, 2000, and 1999 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, 1998		$	1,635		$	(2,442	)	$	—		$	—		$	(807	)
	Current-period change		(9,781	)		(1,239	)		2,086			—			(8,934	)

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	)

(1): The results ofCinergyalso include amounts related to non-registrants. Individual amounts forCG&E,PSI, andULH&Pare deemed immaterial.

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