8-K

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): February 19, 2002

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-11377	CINERGY CORP. (A Delaware Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-1385023
1-1232	THE CINCINNATI GAS & ELECTRIC COMPANY (An Ohio Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-0240030
1-3543	PSI ENERGY, INC. (An Indiana Corporation) 1000 East Main Street Plainfield, Indiana 46168 (513) 421-9500	35-0594457
2-7793	THE UNION LIGHT, HEAT AND POWER COMPANY (A Kentucky Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-0473080

Item 7. Financial Statements and Exhibits.

        The registrants file this Form 8-K Current Report for the purpose of filing the exhibits listed below. Exhibits 99.1 and 99.2 are expected to be filed in identical form with the registrants' Form 10-K Annual Report for the year ended December 31, 2001.

        (c) Exhibits

Exhibit Number	Description
23.1	Consent of Arthur Andersen LLP
99.1	Financial Statements:
	Report of Independent Public Accountants
	Cinergy Corp. and Subsidiaries
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	The Cincinnati Gas & Electric Company and Subsidiaries
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	—	Consolidated Statements of Capitalization at December 31, 2001, and 2000
	PSI Energy, Inc. and Subsidiary
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	—	Consolidated Statements of Capitalization at December 31, 2001, and 2000
	The Union Light, Heat and Power Company
	—	Statements of Income for the three years ended December 31, 2001
	—	Balance Sheets at December 31, 2001 and 2000
	—	Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Statements of Cash Flows for the three years ended December 31, 2001
	—	Statements of Capitalization at December 31, 2001, and 2000
	Notes to Financial Statements
99.2	Management's Discussion and Analysis of Financial Condition and Results of Operations

1

SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CINERGY CORP.
Dated: February 19, 2002	By	/s/  WENDY L. AUMILLER Name: Wendy L. Aumiller Title: Acting Treasurer

2

EXHIBIT INDEX

Exhibit Number	Description
23.1	Consent of Arthur Andersen LLP
99.1	Financial Statements:
	Report of Independent Public Accountants
	Cinergy Corp. and Subsidiaries
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	The Cincinnati Gas & Electric Company and Subsidiaries
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	—	Consolidated Statements of Capitalization at December 31, 2001, and 2000
	PSI Energy, Inc. and Subsidiary
	—	Consolidated Statements of Income for the three years ended December 31, 2001
	—	Consolidated Balance Sheets at December 31, 2001 and 2000
	—	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Consolidated Statements of Cash Flows for the three years ended December 31, 2001
	—	Consolidated Statements of Capitalization at December 31, 2001, and 2000
	The Union Light, Heat and Power Company
	—	Statements of Income for the three years ended December 31, 2001
	—	Balance Sheets at December 31, 2001 and 2000
	—	Statements of Changes in Common Stock Equity for the three years ended December 31, 2001
	—	Statements of Cash Flows for the three years ended December 31, 2001
	—	Statements of Capitalization at December 31, 2001, and 2000
	Notes to Financial Statements
99.2	Management's Discussion and Analysis of Financial Condition and Results of Operations

E-1

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SIGNATURES
EXHIBIT INDEX

EX-23.1

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Exhibit 23.1

Consent of Independent Public Accountants

        As independent public accountants, we hereby consent to the incorporation of our report, dated January 24, 2002, included in this Form 8-K, into (i) Cinergy Corp.'s previously filed Registration Statement Nos. 33-55267, 33-55713, 33-56089, 33-56091, 33-56093, 33-56095, 333-17531, 333-51484, 333-83461, 333-83467, 333-94281, 333-72898, 333-72900, 333-72902, 333-74086 and 333-81770 (ii) PSI Energy, Inc.'s previously filed Registration Statement Nos. 33-48612 and 33-57064; (iii) The Cincinnati Gas & Electric Company's previously filed Registration Statement Nos. 33-45116, 33-52335 and 33-58967; and (iv) The Union Light, Heat and Power Company's previously filed Registration Statement No. 33-40245.

/s/ ARTHUR ANDERSEN LLP
Arthur Andersen LLP

Cincinnati, Ohio,
February 19, 2002

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Consent of Independent Public Accountants

EX-99.1

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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

1

CINERGY CORP.
AND SUBSIDIARY COMPANIES

2

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.

3

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.

4

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.

5

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.

6

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.

7

THE CINCINNATI GAS & ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES

8

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.

9

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.

10

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.

11

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.

12

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.

13

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

14

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

Cumulative Preferred Stock
								December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001		Mandatory Redemption
						Series		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.

15

PSI ENERGY, INC.
AND SUBSIDIARY COMPANY

16

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.

17

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.

18

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.

19

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.

20

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.

21

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

22

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

Cumulative Preferred Stock
								December 31
Par/Stated Value				Authorized Shares	Shares Outstanding at December 31, 2001		Mandatory Redemption
						Series		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.

23

THE UNION LIGHT, HEAT
AND POWER COMPANY

24

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.

25

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.

26

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.

27

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.

28

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.

29

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.

30

NOTES TO FINANCIAL STATEMENTS

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

1.    Summary of Significant Accounting Policies

(a)  Nature of Operations

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

•

Cinergy 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 for Cinergy'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-

31

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 of Cinergy, CG&E, PSI, and ULH&P to conform to current presentation.

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

(i)  Consolidation Method

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

(ii)  Equity Method

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

•

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



•

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

32

(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 as Other 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 to CG&E's transition plan. This plan created a Regulatory Transition Charge (RTC), designed to recover CG&E's generation-related regulatory assets and transition costs over a ten-year period which began January 1, 2001. Accordingly, Statement 71 was discontinued for the generation portion of CG&E's business and Statement of Financial Accounting Standards No. 101, Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71 was applied. The effect of this change to the financial statements was immaterial. Except with respect to the generation-related assets and liabilities of CG&E, as of December 31, 2001, PSI, CG&E, and ULH&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.

33

        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 to ULH&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 for CG&E and PSI and a regulatory liability for ULH&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 for CG&E, 1 to 32 years for PSI, and 1 to 19 years for ULH&P.

(d)  Statements of Cash Flows

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

34

(e)  Operating Revenues and Fuel Costs

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

        Indiana law limits the amount of fuel costs that PSI can recover to an amount that will not result in earning a return in excess of that allowed by the IURC. Due to deregulation in the state of Ohio, the recovery of fuel costs in retail 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 our Property, plant, and equipment at its original cost, which includes:

•

materials;



•

salaries;



•

payroll taxes;



•

fringe benefits;



•

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



•

other miscellaneous amounts.

        In August 2000, the generation assets of CG&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 of PSI 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

35

depreciation rates for Property, 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)

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

36

(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 for Cinergy and CG&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 as Deferred income tax assets or liabilities in our Balance Sheets and are based on currently enacted income tax rates.

        Investment tax credits, which have been used to reduce our federal income taxes payable, have been deferred for financial reporting purposes. These deferred investment tax credits are being amortized over the useful lives of the property to which they are related. For a further discussion of income taxes see Note 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 as Energy risk management assets and Energy risk management liabilities. We reflect changes in fair value resulting in unrealized gains and losses in Fuel and purchased and exchanged power and Gas 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 in Operating revenues; costs are recorded in Fuel and purchased and exchanged power and Gas 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

37

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

38

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 of Interest over the life of the agreement. Effective with our adoption of Statement 133 in the first quarter of 2001, we began accounting for 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 for Cinergy 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.

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

40

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 in Accumulated 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 as Accounts payable to affiliated companies and Accounts receivable from affiliated companies. The significant related party transactions are disclosed below.

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        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&E and subsidiaries		240		250		208
PSI		196		187		168
ULH&P		24		25		23

(1)

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

ULH&P purchases energy from CG&E pursuant to a new contract effective January 1, 2002, which was approved by the FERC and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed-rate contract with CG&E and replaces the previous cost-of-service based contract, which expired on December 31, 2001.

ULH&P purchased energy from CG&E for resale in the amounts of $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.

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2.    Common Stock

(a)    Changes In Common Stock Outstanding

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

	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 of Cinergy Corp. common stock and to reinvest cash dividends in the purchase of additional shares. This plan replaced the Dividend Reinvestment and Stock Purchase Plan.

        In November 2001, Cinergy chose to reinstitute the practice of issuing new Cinergy Corp. common shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. This replaces our previous practice of purchasing shares in the open market to fulfill certain plan obligations.

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

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

(b)    Dividend Restrictions

Cinergy Corp.'s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. common dividends. Cinergy Corp., CG&E, and PSI 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 under CG&E's and PSI's credit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock.

(c)    Stock-based Compensation Plans

        We currently have the following stock-based compensation plans:

•

LTIP;

43

•

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 on Cinergy'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

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        Participants may earn additional performance shares if Cinergy'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.

45

        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.

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        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 of Cinergy Corp.'s common stock by its directors, officers, and key employees, thereby further aligning their interests with those of its shareholders.

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

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

        Services, and in part, Cinergy Corp., have guaranteed repayment to the bank of 100% 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 of Cinergy Corp. stock on or before February 2005. The number of shares to be issued is contingent upon the market price of Cinergy Corp. stock, but subject to predetermined ceiling and floor prices. See Note 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 for CG&E and PSI. Refer to the Statements of Capitalization of CG&E and PSI 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 of Cinergy 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

47

approximately $10 million of issuance costs, were used to pay down Cinergy Corp.'s short-term indebtedness. In February 2005, the preferred trust securities will be remarketed and the dividend rate reset, no lower than 6.9%, to yield $316 million in the remarketing. The holders will use the proceeds from this remarketing to fund their obligation to purchase shares of Cinergy Corp. common stock under the stock purchase contract. The holders will pay the market price for the stock at that time, subject to a ceiling of $34.40 per share and a floor of $29.15 per share. The number of shares to be issued will vary according to the stock price, subject to the total proceeds equaling $316 million. These securities were issued through a wholly-owned trust of Cinergy Corp. The preferred trust securities are recorded on Cinergy Corp.'s Balance Sheets, net of discount and expense, as Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company. The fair value of the stock purchase contract was charged to Paid-in capital with a corresponding credit to Non-current liabilities—other.

        Each Unit will receive quarterly cash payments of 9.5% 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.

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5.    Long-Term Debt

        Refer to the Statements of Capitalization for detailed information for CG&E, PSI, and ULH&P. In addition, Cinergy Corp. and Global Resources also have the following total long-term debt (excluding Long-term debt due within one year, which is reflected in Current 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 million PSI 6% Putable/Callable Notes (Notes) on December 14, 2001, with the intent to reset the interest rate and

49

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% of Cinergy 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 as Long-term debt and Long-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 of Cinergy also include amounts related to non-registrants.

(2)

CG&E and subsidiaries includes ULH&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 for CG&E and $50 million in 2005 for PSI.

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

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.

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        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 replaced Cinergy 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, and PSI also maintain uncommitted lines of credit. These facilities are not guaranteed sources of capital and represent an informal agreement to lend money, subject to availability, with pricing to be determined at the time of advance. At December 31, 2001, Cinergy Corp.'s $40 million uncommitted line and CG&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 at CG&E and PSI. The expansion of the commercial paper program at the Cinergy Corp. level supports, in part, the short-term borrowing needs of CG&E and PSI and eliminates their need for separate commercial paper programs. As of December 31, 2001, Cinergy Corp. had $125 million in commercial paper outstanding.

Variable Rate Pollution Control Notes

CG&E and PSI 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 in Notes payable and other short-term obligations in the Balance Sheets of Cinergy, CG&E, and PSI.

        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).

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        The following table summarizes our Notes payable and other short-term obligations, excluding Notes 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 than Cinergy Corp.) participating under this arrangement. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as Notes receivable from affiliated companies or Notes payable to affiliated companies on the Balance Sheets of CG&E, PSI, and ULH&P.

7.    Sales of Accounts Receivable

CG&E, PSI, and ULH&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

52

receivables without recourse to CG&E, PSI, and ULH&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, and ULH&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.

        The Accounts receivable on the Balance Sheets of Cinergy, CG&E, PSI, and ULH&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 of Cinergy 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, and ULH&P entered into capital lease agreements to fund the purchase of gas and electric meters. The lease terms are for 120 months commencing 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

53

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, and ULH&P each recorded a capital lease obligation, included in Non-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 in Accumulated 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.

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(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 as Long-term debt due within one year)	$	3,745	$	3,805	$	2,917	$	2,950
CG&E and subsidiaries
First mortgage bonds and other long-term debt (includes amounts reflected as Long-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 as Long-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 of Cinergy 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.

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(c) Concentrations of Credit Risk

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

(i) Trade Receivables and Physical Power Portfolio

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

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        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. Neither CG&E nor ULH&P pre-fund their obligations for these postretirement benefits. In 1999, PSI began pre-funding its obligations through a grantor trust as authorized by the IURC.

        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.

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        The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ended December 31, 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.

58

        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 reflects Cinergy'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.

59

12. Income Taxes

        The following table shows the significant components of Cinergy's, CG&E's, and PSI's net deferred income tax liabilities as of December 31, 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 of Cinergy 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 the Cinergy consolidated group, pursuant to a tax sharing agreement filed with the SEC under the PUHCA.

60

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

			Cinergy(1)									CG&E and subsidiaries									PSI
			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 of Cinergy also include amounts related to non-registrants.

61

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

		Cinergy(1)									CG&E and subsidiaries									PSI
		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 of Cinergy also include amounts related to non-registrants.

        The following table shows the significant components of ULH&P's net deferred income tax liability as of December 31, 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

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

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

		ULH&P
		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

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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 of Cinergy also 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 on Cinergy'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).

64

        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 and PSI, 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.

65

(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 and PSI 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 notifying Cinergy and CG&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 of CG&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, including Cinergy, CG&E, and PSI, in various U.S. District Courts (District Court). The Cinergy, CG&E, and PSI suit alleged violations of the CAA at two of our generating stations relating to NSR and 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 at PSI'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 against Cinergy, CG&E, and PSI. 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).

66

        The amended complaint sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station and PSI'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), and CG&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 to Cinergy, CG&E, and PSI for alleged violations of NSR, PSD, and SIP requirements at CG&E's Miami Fort Generating Station (Miami Fort Station) and PSI's Gibson Generating Station (Gibson Station). In addition, Cinergy and CG&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, and PSI 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 against Cinergy and CG&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.

67

(f) EPA Agreement

        On December 21, 2000, Cinergy, CG&E, and PSI 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 by Cinergy's operating subsidiaries. The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties. If a final agreement is reached with these parties, it would resolve past claims of 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 against Cinergy, CG&E, and PSI. 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.

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

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

PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and IDEM. In April 1998, PSI filed suit in Hendricks County Circuit Court in the State of Indiana against its general liability insurance carriers. Subsequently, PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI, or (2) pay PSI's costs of defense and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. The lawsuit was moved to the Hendricks 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 in PSI's favor, as a matter of law, on the latter two issues. The trial against the remaining insurance

69

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 a PSI fuel recovery proceeding, disallowing approximately $14 million of deferred costs. On June 26, 2001, PSI formally requested that the IURC reconsider its disallowance decision. In August 2001, the IURC indicated that it 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

70

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 by ULH&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 between ULH&P and CG&E, beginning January 1, 2002, and made the necessary determinations under the PUHCA, for CG&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 by PSI. The Statements of Income reflect CG&E's and PSI's portions of all operating costs associated with the jointly-owned facilities.

CG&E's and PSI'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 by CG&E.

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15. Quarterly Financial Data (unaudited)

						CG&E and subsidiaries
		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 of Cinergy also 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.

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        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 maintains Cinergy'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 through Cinergy's transmission system.

        Power Technology primarily manages the development, marketing, and sales of our non-regulated retail energy and energy-related businesses. This is accomplished through various subsidiaries and joint ventures 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 future Cinergy 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.

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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

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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

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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.

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17. Earnings Per Common Share

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

		Income		Shares	EPS
		(in thousands, except per share amounts)
Year ended December 31, 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.

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

•

Residential customer rates are frozen through December 31, 2005;



•

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



•

CG&E will provide 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 recover CG&E's regulatory assets and other transition costs over a ten-year period;



•

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



•

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



•

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 and CG&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 denied CG&E's motion to dismiss. CG&E is unable to predict the outcome of this proceeding.

        As indicated above, the August 31, 2000 order authorizes CG&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 upon CG&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.

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19. Comprehensive Income

        The elements of Comprehensive 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 of Cinergy also include amounts related to non-registrants. Individual amounts for CG&E, PSI, and ULH&P are deemed immaterial.

        The after-tax components of Accumulated 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 of Cinergy also include amounts related to non-registrants. Individual amounts for CG&E, PSI, and ULH&P are deemed immaterial.

79

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
CINERGY CORP. AND SUBSIDIARY COMPANIES
CINERGY CORP. CONSOLIDATED STATEMENTS OF INCOME
CINERGY CORP. CONSOLIDATED BALANCE SHEETS
CINERGY CORP. CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
CINERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS
THE CINCINNATI GAS & ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
THE CINCINNATI GAS & ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
PSI ENERGY, INC. AND SUBSIDIARY COMPANY
PSI ENERGY, INC. CONSOLIDATED STATEMENTS OF INCOME
PSI ENERGY, INC. CONSOLIDATED BALANCE SHEETS
PSI ENERGY, INC. CONSOLIDATED BALANCE SHEETS
PSI ENERGY, INC. CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
PSI ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
PSI ENERGY, INC. CONSOLIDATED STATEMENTS OF CAPITALIZATION
THE UNION LIGHT, HEAT AND POWER COMPANY
THE UNION LIGHT, HEAT AND POWER COMPANY STATEMENTS OF INCOME
THE UNION LIGHT, HEAT AND POWER COMPANY BALANCE SHEETS
THE UNION LIGHT, HEAT AND POWER COMPANY BALANCE SHEETS
THE UNION LIGHT, HEAT AND POWER COMPANY STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
THE UNION LIGHT, HEAT AND POWER COMPANY STATEMENTS OF CASH FLOWS
THE UNION LIGHT, HEAT AND POWER COMPANY STATEMENTS OF CAPITALIZATION
NOTES TO FINANCIAL STATEMENTS
Products and Services (in millions)
Geographic Areas and Long-Lived Assets (in millions)

EX-99.2

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

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

        The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this report. The results discussed below are not necessarily indicative of the results to be expected in any future periods.

INTRODUCTION

        In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), we explain our general operating environment, as well as our liquidity, capital resources, and results of operations. Specifically, we discuss the following:

•

factors affecting current and future operations;



•

what our expenditures for construction and other commitments were during 2001, and what we expect them to be in 2002-2006;



•

potential sources of cash for future capital expenditures;



•

why revenues and expenses changed from period to period; and



•

how the above items affect our overall financial condition.

LIQUIDITY AND CAPITAL RESOURCES

Comparative Cash Flow Analysis

Cinergy

        At December 31, 2001, Cinergy's consolidated cash and cash equivalents totaled $111.1 million compared to $93.1 million at December 31, 2000. The increase reflects increases in cash from operating activities and new financings, offset in part by additional expenditures for our operating companies' construction programs and additional investments, including peaking generation assets.

The Cincinnati Gas & Electric Company (CG&E)

        At December 31, 2001, CG&E's consolidated cash and cash equivalents totaled $9.1 million compared to $20.6 million at December 31, 2000. Additional construction expenditures were largely offset by cash from operating activities.

PSI Energy, Inc. (PSI)

        At December 31, 2001, PSI's consolidated cash and cash equivalents totaled $1.6 million as compared to $1.3 million at December 31, 2000. Increases in cash from operating activities and financing activities were offset by additional construction expenditures.

1

Operating Activities

        For each of the years ended December 31, 2001, 2000, and 1999, our cash flows from operating activities were as follows:

Net Cash Provided by (Used in) Operating Activities

	2001		2000		1999
	(in thousands)
Cinergy(1)	$	694,412	$	618,001	$	478,267
CG&E and subsidiaries		333,099		463,875		399,008
PSI		388,171		339,115		124,053
The Union Light, Heat and Power Company (ULH&P)		46,513		49,258		32,537

(1)

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

Cinergy's net cash provided by operating activities increased during 2001, as compared to 2000, primarily due to increased income and a net cash inflow from working capital fluctuations. CG&E's net cash provided by operating activities decreased primarily due to working capital fluctuations, offset in part by increased income. PSI's cash from operating activities increased primarily due to increased income.

Cinergy's and PSI's net cash provided by operating activities increased during 2000, as compared to 1999, primarily due to the one-time cash payment in 1999 for the purchase of the remainder of Dynegy Inc.'s 25 year contract for coal gasification services. CG&E's cash provided by operating activities increased primarily due to increased income and fluctuations in working capital.

        The tariff-based gross margins of our operating companies continue to be the principal source of cash from operating activities. The diversified retail customer mix of residential, commercial, and industrial classes and a commodity mix of gas and electric service provides a reasonably predictable gross cash flow.

Financing Activities

        For each of the years ended December 31, 2001, 2000, and 1999, our cash flows from financing activities were as follows:

Net Cash Provided by (Used in) Financing Activities

	2001			2000			1999
	(in thousands)
Cinergy(1)	$	866,438		$	157,771		$	(355,986	)
CG&E and subsidiaries		16,841			(192,665	)		(222,311	)
PSI		34,723			(77,955	)		89,092
ULH&P		(14,678	)		(18,006	)		(3,906	)

(1)

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

Cinergy's net cash provided by financing activities increased during 2001, as compared to 2000, primarily due to the net proceeds from the issuance of Preferred trust securities and proceeds from debt issuances to fund the purchase of new generating facilities and environmental compliance expenditures as discussed in the "Investing Activities" section. CG&E's net cash provided by financing activities increased primarily as the result of increased short-term borrowings offset by an increase in dividends

2

paid on common stock. PSI's net cash provided by financing activities increased primarily as the result of no dividends paid on common stock in 2001 and the retirement of preferred stock in 2000.

Cinergy's net cash provided by financing activities increased in 2000, as compared to 1999, primarily due to a net increase in long-term and short-term borrowings. CG&E's net cash used in financing activities decreased primarily as a result of the redemption of $164 million in long-term debt that occurred during 1999 partially offset by a decrease in short-term borrowings. PSI's net cash provided by financing activities increased primarily due to a net reduction in short-term and long-term debt offset in part by fewer debt redemptions in 2000.

Investing Activities

        For each of the years ended December 31, 2001, 2000, and 1999, our cash flows used in investing activities were as follows:

Net Cash Used in Investing Activities

	2001			2000			1999
	(in thousands)
Cinergy(1)	$	(1,542,837	)	$	(764,637	)	$	(140,516	)
CG&E and subsidiaries		(361,503	)		(260,127	)		(194,132	)
PSI		(422,618	)		(268,691	)		(223,091	)
ULH&P		(34,196	)		(28,433	)		(28,234	)

(1)

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

Cinergy's, CG&E's, and PSI's net cash used in investing activities increased in 2001, as compared to 2000, as a result of an increase in capital expenditures related to environmental compliance projects. See the "Environmental Commitment and Contingency Issues" section for further information. Cinergy's increase also reflects the acquisition of additional peaking capacity including the 480 megawatt (MW) Brownsville and the 550 MW Caledonia peaking stations.

        The increase in Cinergy's cash used in investing activities in 2000, as compared to 1999, primarily reflects the impact from proceeds of $690 million received in 1999 from the sale of our 50% ownership interest in Midlands Electricity plc (Midlands). CG&E's and PSI's net cash used in investing activities increased primarily as a result of an increase in construction expenditures.

3

Capital Requirements

        Actual construction and other committed expenditures for 2001 and forecasted construction and other committed expenditures for the year 2002 and for the five-year period 2002-2006 (in nominal dollars), including allowance for funds used during construction, are presented in the table below:

Actual Capital and Investment Expenditures and Future Projections

			Forecasted Expenditures
	Actual Expenditures 2001
			2002		2002-2006
	(in millions)
By Registrant
Cinergy(1)	$	1,545	$	889	$	3,070
CG&E and subsidiaries		364		275		1,135
PSI		429		478		1,522
ULH&P		34		43		212

(1)

The results of Cinergy also 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 United States (U.S.) Environmental Protection Agency (EPA) agreement), as discussed in EPA Agreement below.

        All forecasted amounts and the underlying assumptions are subject to risks and uncertainties as disclosed in the "Cautionary Statements Regarding Forward-Looking Information."

Environmental Commitment and Contingency Issues

EPA Agreement

        On December 21, 2000, Cinergy, CG&E, and PSI reached an agreement in principle with the EPA, the U.S. Department of Justice, three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of Clean Air Act Amendments claims and other related matters brought against coal-fired power plants owned and operated by Cinergy's operating companies. 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 at an estimated cost of approximately $800 million (in nominal dollars) between 2001 and 2005. In 2001, we spent $260 million for NO_X and other environmental compliance projects. Forecasted expenditures for NO_X and other environmental compliance projects (in nominal dollars) are approximately $250 million for 2002 and $600 million for the 2002-2006 period. See Note 13 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the EPA Agreement and related environmental issues.

Manufactured Gas Plant (MGP) Sites

        In November 1998, PSI entered into a Site Participation and Cost Sharing Agreement with Northern Indiana Public Service Company and Indiana Gas Company, Inc. related to contamination at MGP sites, which PSI or its predecessors previously owned. Until investigation and remediation activities have been completed on the sites, we are unable to reasonably estimate the total costs and impact on our financial position or results of operations. In relation to the MGP claims, PSI also filed suit against its general liability insurance carriers. Subsequently, PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI, or (2) pay PSI's costs of defense

4

and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. At the present time, PSI cannot predict the outcome of this litigation. See Note 13(g) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further information.

Ambient Air Standards

        In 1997, the EPA revised the National Ambient Air Quality Standards for ozone and fine particulate matter. Fine particulate matter refers to very small solid or liquid particles in the air. The EPA has estimated that it will take up to five years to collect sufficient ambient air monitoring data to determine fine particulate matter non-attainment areas. A fine particulate monitoring network was put in place during 1999 and 2000. Following identification of non-attainment areas, the states will identify the sources of particulate emissions and develop emission reduction plans. These plans may be state-specific or regional. We currently cannot predict the exact amount and timing of required reductions.

        On May 14, 1999, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) ruled that the EPA's final rule establishing the new eight-hour ozone standard and the fine particulate matter standard constituted an invalid delegation of legislative authority. In June 1999, the EPA appealed the decision. On February 27, 2001, the U.S. Supreme Court (Supreme Court) reversed the Court of Appeals' ruling. However, the Supreme Court invalidated the EPA's implementation procedure for the portion of the case dealing with the eight-hour ozone standard. The EPA currently is evaluating approaches for implementing the eight-hour ozone standard in accordance with the Supreme Court's opinion. Meanwhile, the Court of Appeals continues to consider the validity of the eight-hour ozone standard and the fine particulate matter standard, as a number of issues that were raised by the parties were not addressed in its original opinion invalidating those standards. The parties have filed supplemental briefs on these issues, and further oral argument was held in December 2001. A decision by the Court of Appeals is expected in the spring of 2002. We currently cannot determine the outcome of this litigation or of future EPA actions in response to the litigation and the effects on future emissions reduction requirements.

Regional Haze

        The EPA published the final regional haze rule on July 1, 1999. This rule established planning and emission reduction timelines for states to use to improve visibility in national parks throughout the U.S. The ultimate effect of the new regional haze rule could be requirements for (1) newer and cleaner technologies and additional controls on conventional particulates and (2) reductions in sulfur dioxide (SO₂) and NO_X emissions from utility sources. If more utility emissions reductions are required, the compliance cost could be significant. In August 1999, several industry groups (some of which we are a member) filed a challenge to the regional haze rules with the Court of Appeals. Parties have filed their briefs in this case and oral argument will be held in the first quarter of 2002. In addition, several industry groups (some of which we are a member) have petitioned the Bush Administration to reconsider its approach to regional haze, including possible modifications to the rule and/or settlement of the lawsuit. We currently cannot determine the outcome or effects of the EPA's, courts', or states' determinations.

        In July 2001, the EPA proposed guidance to implement portions of the regional haze rule. This guidance recommends that states require widespread installation of scrubbers to reduce SO₂ emissions. Several industry groups (some of which we are a member) commented that the EPA's recommendations exceed the scope of the law and the regional haze recommendations. We currently cannot determine whether or how the EPA will modify the scope of this guidance, or whether the states in which we operate will adopt the EPA's proposed guidance.

5

Global Climate

        In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming. The Kyoto Protocol establishes legally binding greenhouse gas emission (man-made pollutants thought to be artificially warming the earth's atmosphere) targets for developed nations. On November 12, 1998, the U.S. signed the Kyoto Protocol; however, it will not be effective in the U.S. until it is approved by a two-thirds vote of the U.S. Senate, which is currently deemed unlikely.

        In March 2001, the Bush Administration announced that the U.S. was not interested in ratifying the Kyoto Protocol. Talks resumed without active U.S. participation at the Conference of the Parties in Bonn, Germany in July 2001, where the parties reached broad political agreement on the major outstanding issues. The Marrakech Accord, concluded at the seventh Conference of the Parties in November 2001, turned broad principles into a detailed set of rules that more clearly define the operating framework for the instruments and institutions created under the Kyoto Protocol. The Marrakech Accord set the stage for ratification of the Kyoto Protocol, although the U.S. continues to maintain its position against ratification. Because of a lack of U.S. support for the Kyoto Protocol or similar legislation, significant uncertainty exists about how and when greenhouse gas emissions reductions will be required. Our plan for managing the potential risk and uncertainty of regulations relating to climate change includes the following:

•

implementing cost-effective greenhouse gas emission reduction and offsetting activities;



•

funding research of more efficient and alternative electric generating technologies;



•

funding research to better understand the causes and consequences of climate change;



•

encouraging a global discussion of the issues and how best to manage them; and



•

advocating comprehensive legislation for fossil-fired power plants.

Mercury

        The EPA's 1997 Mercury Study Report and Utility Report to Congress both conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in current domestic sources would reduce human mercury exposure. On December 14, 2000, the EPA made a determination that additional regulation of mercury emissions from coal-fired power plants was appropriate. It is currently developing a Maximum Achievable Control Technology standard for mercury. The EPA is expected to issue draft regulations in 2003 and final rules by 2004, with reductions required before 2010. We currently cannot predict the outcome or costs relating to the EPA's determination and subsequent regulation.

Other Investing Activities

        Our ability to invest in growth initiatives is limited by certain legal and regulatory requirements, including the Public Utility Holding Company Act of 1935, as amended (PUHCA). The PUHCA limits the types of non-utility businesses in which Cinergy and other registered holding companies under PUHCA can invest as well as the amount of capital that can be invested in permissible non-utility businesses. Also, the timing and amount of investments in the non-utility businesses is dependent on the development and favorable evaluations of opportunities. Under the PUHCA restrictions, we are allowed to invest or commit to invest in certain non-utility businesses, including:

1.

Exempt Wholesale Generators (EWG) and Foreign Utility Companies (FUCO)

An EWG is an entity, certified by the Federal Energy Regulatory Commission (FERC), devoted exclusively to owning and/or operating, and selling power from one or more electric

6

generating facilities. An EWG whose generating facilities are located in the U.S. is limited to making only wholesale sales of electricity.

A FUCO is a company all of whose utility assets and operations are located outside the U.S. and which are used for the generation, transmission, or distribution of electric energy for sale at retail or wholesale, or the distribution of gas at retail. An entity claiming status as a FUCO must provide notification thereof to the Securities and Exchange Commission (SEC) under PUHCA.

In May 2001, the SEC issued an order under PUHCA authorizing Cinergy to invest (including by way of guarantees) an aggregate amount in EWGs and FUCOs equal to the sum of (1) our average consolidated retained earnings from time to time plus (2) $2 billion. As of December 31, 2001, we had invested or committed to invest $1.3 billion in EWGs and FUCOs, leaving available investment capacity under the May 2001 order of $2 billion.

2.

Qualifying Facilities and Energy-Related Non-utility Entities

SEC regulations under the PUHCA permit Cinergy and other registered holding companies to invest and/or guarantee an amount equal to 15% of consolidated capitalization (consolidated capitalization is the sum of Notes payable and other short-term obligations, Long-term debt (including amounts due within one year), Preferred Trust Securities, Cumulative preferred stock of subsidiaries, and total Common stock equity) in domestic qualifying cogeneration and small power production plants (qualifying facilities) and certain other domestic energy-related non-utility entities. At December 31, 2001, we had invested and/or guaranteed approximately $.5 billion of the $1.2 billion available.

7

Financing Obligations

        The following table presents Cinergy's, PSI's, CG&E's, and ULH&P's financing obligations:

			Payments Due by Period
Financing Obligations
			2002		2003			2004		2005			2006		Thereafter			Total
			(in millions)
Cinergy(1)
	Notes payable and other short-term obligations		$	877	$	—		$	—	$	—		$	—	$	279	(2)	$	1,156
	Capital lease obligations			3		3			3		3			4		19			35
	Operating leases			45		36			26		21			18		61			207
	Long-term debt (including due within one year)			148		192	(3)		814		203	(4)(5)		334		2,065			3,756
	Preferred trust securities			—		—			—		—			—		316			316
		Total Cinergy	$	1,073	$	231		$	843	$	227		$	356	$	2,740		$	5,470
CG&E and subsidiaries
	Notes payable and other short-term obligations(6)		$	445	$	—		$	—	$	—		$	—	$	196	(2)	$	641
	Capital lease obligations			1		2			2		2			2		11			20
	Operating leases			20		15			10		7			6		15			73
	Long-term debt (including due within one year)			100		120	(3)		110		150	(5)		—		728			1,208
		Total CG&E and subsidiaries	$	566	$	137		$	122	$	159		$	8	$	950		$	1,942
PSI
	Notes payable and other short-term obligations(6)		$	43	$	—		$	—	$	—		$	—	$	83	(2)	$	126
	Capital lease obligations			2		1			1		1			2		8			15
	Operating leases			17		14			9		7			7		23			77
	Long-term debt (including due within one year)			23		58			1		51	(4)		328		895			1,356
		Total PSI	$	85	$	73		$	11	$	59		$	337	$	1,009		$	1,574
ULH&P
	Notes payable and other short-term obligations(6)		$	26	$	—		$	—	$	—		$	—	$	—		$	26
	Capital lease obligations			—		—			1		1			1		3			6
	Operating leases			1		1			—		—			—		—			2
	Long-term debt			—		20			—		—			—		55			75
		Total ULH&P	$	27	$	21		$	1	$	1		$	1	$	58		$	109

(1)

Includes amounts for non-registrants.

(2)

Includes Variable Rate Pollution Control Notes depicted according to scheduled maturities, which the holders have the right to redeem on any business day, with the remainder being redeemable annually. See Variable Rate Pollution Control Notes below.

(3)

Includes 6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.

(4)

Includes 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate resets on August 1, 2005.

8

(5)

Includes 6.90% Debentures due June 1, 2025, reflected as maturing in 2005, as the debentures are putable to CG&E at the option of the holders on June 1, 2005.

(6)

Includes net Notes receivable from/Notes payable to affiliated companies.

Capital Resources

Notes Payable and Other Short-term Obligations

Short-term Borrowings

        At December 31, 2001, Cinergy Corp. had $437 million remaining unused and available capacity relating to its $1.2 billion revolving credit facilities. The revolving credit facilities were comprised of $400 million under a three-year senior revolving credit facility expiring in May 2004 and $775 million in revolving facilities expiring during the first half of 2002. In early 2002, Cinergy Corp. placed a $600 million, 364-day senior revolving credit facility to replace the facilities expiring in 2002. At December 31, 2001, certain of our non-regulated subsidiaries had $8 million of unused and available revolving credit lines.

        In May 2001, CG&E filed an application with the Public Utilities Commission of Ohio (PUCO) to increase its short-term debt authority to $600 million and in June 2001, the PUCO granted this request. In April 2001, Cinergy Corp. filed an application with the SEC to increase PSI's and ULH&P's short-term debt authority to $600 million and $65 million, respectively. In August 2001, the SEC granted our request. As of December 31, 2001, our operating companies had regulatory authority to borrow up to a total of $1.27 billion in short-term debt ($671 million for CG&E and its subsidiaries, including $65 million for ULH&P, and $600 million for PSI.) As of December 31, 2001, CG&E and its subsidiaries had $226 million (including $39 million for ULH&P) unused and available and PSI had $557 million unused and available under their respective regulatory authority.

        Our short-term financial arrangements include customary default provisions that could impact the continued availability of credit or result in the acceleration of repayment. These events include bankruptcy, defaults in payment of other indebtedness, judgments against Cinergy that are not paid or insured, or failure to meet or maintain covenants.

Uncommitted Lines

        In addition to revolving credit facilities, Cinergy, CG&E, and PSI also maintain uncommitted lines of credit. These facilities are not firm 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 and CG&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 at CG&E and PSI. The expansion of the commercial paper program at the Cinergy Corp. level will, in part, support the short-term borrowing needs of CG&E and PSI and will eliminate the need for separate commercial paper programs. As of December 31, 2001, Cinergy Corp.'s commercial paper program was supported by $1.2 billion in revolving credit facilities, of which it had $125 million in commercial paper outstanding.

Variable Rate Pollution Control Notes

CG&E and PSI have issued variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes). Because the holders of a

9

majority of these notes have the right to redeem their notes on any business day, with the remainder being redeemable annually, they are reflected in Notes payable and other short-term obligations in the Balance Sheets for Cinergy, CG&E, and PSI. At December 31, 2001, CG&E had $196 million and PSI had $83 million outstanding in pollution control notes, classified as short-term debt.

Money Pool

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

Capital Leases

        Our operating companies are able to enter into capital leases subject to the authorization limitations of the applicable state utility commissions. Increases in these limits are subject to the approval of the respective commissions. As of December 31, 2001, unused capital lease authority was $74 million for CG&E and $19 million for ULH&P. PSI did not have any remaining authority at December 31, 2001. During the first quarter of 2002, PSI intends to file an application with the Indiana Utility Regulatory Commission (IURC) requesting additional capital lease authority of up to $100 million. See Note 8(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for additional information regarding capital leases.

Operating Leases

        We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space. See Note 8(a) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for additional information regarding operating leases.

Long-term Debt

        We are required to secure authority to issue long-term debt from the SEC under the PUHCA and the state utility commissions of Ohio, Kentucky, and Indiana. The SEC under the PUHCA regulates the issuance of long-term debt by Cinergy Corp. The respective state utility commissions regulate the issuance of long-term debt by our operating companies. In June 2000, the SEC issued an order under the PUHCA authorizing Cinergy Corp., over a five-year period expiring in June 2005, to increase its total capitalization based on a balance at December 31, 1999 (excluding retained earnings and accumulated other comprehensive income (loss)) by an additional $5 billion, through the issuance of any combination of equity and debt securities. This increased authorization is subject to certain conditions, including, among others, that common equity comprises at least 30% of Cinergy Corp.'s consolidated capital structure and that Cinergy Corp., under certain circumstances, maintains an investment grade rating on its senior debt obligations.

        In May 2001, CG&E filed an application with the PUCO to increase its long-term debt authority to $400 million and in June 2001, the PUCO granted this request. As of December 31, 2001, $400 million remained unused and available under the PUCO authorization. PSI intends to file an application with the IURC requesting additional long-term debt issuance authority of up to $500 million. In November 2001, Cinergy Corp. filed a shelf registration statement with the SEC with respect to the issuance of common stock, preferred stock, and other securities with an aggregate

10

amount of $800 million, and at December 31, 2001, $168 million remained unused and available under this registration statement. We may, at any time, seek to issue additional long-term debt, subject to regulatory approval.

        As of December 31, 2001, through shelf registration statements filed with the SEC under the Securities Act of 1933, as amended, we could issue the following amounts of debt securities:

	CG&E		PSI		ULH&P
	(in millions)
First Mortgage Bonds and Other Secured Notes	$	300	$	205	$	20
Senior or Junior Unsecured Debt		50		400		30

Off-Balance Sheet Financing

Cinergy uses special-purpose entities (SPEs) from time to time to facilitate financing of various projects. Due to our lack of control of these entities, a substantive investment by unrelated parties, and various other criteria, Cinergy does not consolidate these SPEs. The following describes the major off-balance sheet financings.

(i) Power Sales

        Cinergy Capital & Trading, Inc. (Capital & Trading) is a 10% owner of two SPEs that were created to facilitate power sales to Central Maine Power (CMP). The SPEs raised capital to purchase CMP's existing power supply contracts from two independent power producers. The SPEs restructured the terms of the agreements, resulting in power sales contracts for approximately 45 MW, ending in 2009, and 35 MW, ending in 2016. Since the SPEs have no generation sources, power purchase agreements were entered into with Capital & Trading with near equivalent terms. The total debt outstanding at December 31, 2001, within these two SPEs is approximately $250 million. This debt is non-recourse to Cinergy and Capital & Trading in the event of non-performance by CMP. A portion of the cash flows received by the SPEs from CMP is reserved to pay the interest and principal on the debt.

        Capital & Trading provides various services, including certain credit support facilities. All but one of these credit support facilities is capped at immaterial amounts. The non-capped facility can only be called upon in the event the SPE breaches representations, violates covenants, or other unlikely events.

        Capital & Trading accounts for its 10% interest in both SPEs under the equity method of accounting.

(ii) Leasing

Cinergy has an arrangement with an SPE that has contracted to buy five combustion turbines from an unrelated party. Cinergy will act as agent for the SPE in all turbine-related matters. Progress payments are being made by the SPE as the turbines are constructed, with estimated completion in 2003 for two of the turbines and 2004 for the remaining three. Total cost of the turbines being constructed, including interest during construction, is estimated at $185 million. The arrangement with the SPE allows Cinergy to elect any of the following at construction completion: (a) purchase the turbines for the total costs incurred by the SPE, (b) enter into a five-year operating lease, or (c) remarket the turbines with the proceeds distributed first to the debt holders and then to the equity holders of the SPE. Should Cinergy elect to remarket the turbines on behalf of the owners of the SPE, we are required to pay up to 89.9% of the turbine costs (including interest) to the SPE for use in payment of outstanding senior debt. The proceeds from the sales of turbines would then be used to recover the remaining turbine cost, with any residuals returned to Cinergy. During the construction period, Cinergy has agreed to indemnify the SPE for 89.9% of the construction cost of the turbines in

11

an event of default under Cinergy's agency agreement. At December 31, 2001, approximately $30 million of progress payments had been made by the SPE. Neither the turbines nor any related debt is reflected in the financial statements because we have no ownership in, nor control of, the SPE. Cinergy is uncertain whether it will exercise the purchase option or enter into the five-year operating lease at the completion of construction.

(iii) Sales of Accounts Receivable

CG&E, PSI, and ULH&P have an agreement to sell, on a revolving basis, undivided interests in certain accounts receivable. At December 31, 2001, approximately $322 million of receivables were sold. Cash proceeds from these sales, net of a purchaser holdback of approximately 20%, were $257 million. For a more detailed discussion of our sales of accounts receivable, see Note 7 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

        In addition to the items above, Cinergy holds investments in various unconsolidated subsidiaries which are accounted for under the equity method (see Note 1(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data"). Cinergy has guaranteed approximately $12 million of the debt of these entities.

Securities Ratings

        As of January 31, 2002, the major credit ratings agencies rated our securities as follows:

		Fitch	Moody's(1)	S&P(2)
Cinergy Corp.
	Corporate Credit	BBB+	Baa2	BBB+/A-2
	Senior Unsecured Debt	BBB+	Baa2	BBB+
	Commercial Paper	F-2	P-2	A-2
	Preferred Trust Securities	BBB+	Baa2	BBB
CG&E
	Senior Secured Debt	A-	A3	A-
	Senior Unsecured Debt	BBB+	Baa1	BBB+
	Junior Unsecured Debt	BBB	Baa2	BBB
	Preferred Stock	BBB	Baa3	BBB
	Commercial Paper	F-2	P-2	Not Rated
PSI
	Senior Secured Debt	A-	A3	A-
	Senior Unsecured Debt	BBB+	Baa1	BBB+
	Junior Unsecured Debt	BBB	Baa2	BBB
	Preferred Stock	BBB	Baa3	BBB
	Commercial Paper	F-2	P-2	Not Rated
ULH&P
	Senior Unsecured Debt	Not Rated	Baa1	BBB+

(1)

Moody's Investors Service (Moody's)

(2)

Standard & Poor's Ratings Services (S&P)

        On December 12, 2000, S&P placed its ratings of Cinergy Corp. and its operating affiliates, CG&E and PSI, on CreditWatch with negative implications. On January 22, 2001, Moody's announced it had assigned negative outlooks to the debt and preferred stock securities of Cinergy Corp. and all of its

12

subsidiaries. These actions were primarily in response to Cinergy's acquisition of the Brownsville and Caledonia power plants. See "Supply-side Actions" under "Electric Industry" for further discussion. Other items of concern included (1) the announcement that Cinergy Corp., CG&E, and PSI have reached an agreement in principle with the EPA; (2) the continuing uncertainty surrounding CG&E's post-deregulation corporate and financial structure; (3) the absence of restructuring legislation and stranded investment resolution in Indiana; and (4) Cinergy's emphasis on higher-risk non-regulated activities.

        On September 4, 2001, Moody's placed the debt ratings of Cinergy Corp. on review for possible downgrade. These actions are primarily in response to Cinergy Corp.'s increased debt associated with its growing portfolio of peaking generation.

        On November 14, 2001, Fitch changed the outlook of Cinergy's 'BBB+' Senior unsecured debt to negative from stable due to increased leverage and planned environmental expenditures.

        These securities ratings may be revised or withdrawn at any time, and each rating should be evaluated independently of any other rating.

Equity Securities

        In addition to the authority to issue common stock pursuant to the SEC's June 2000 Order permitting Cinergy Corp. to increase its total capitalization by $5 billion (as previously discussed), Cinergy Corp. may issue an additional 50 million shares of common stock for various stock-based plans, of which approximately 6 million shares had been issued as of December 31, 2001. We also have the option of purchasing shares of common stock on the open market to satisfy the obligations of our various stock-based plans. The proceeds from any new issuances will be used for general corporate purposes.

        In November 2001, Cinergy Corp. chose to reinstitute the practice of issuing new Cinergy Corp. common shares to meet its obligations under the various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. This replaces the previous practice of purchasing open market shares to fulfill plan obligations.

        The following table reflects the number of newly issued shares and purchased shares used to satisfy obligations under our various stock-based plans:

	2001	2000	1999
	(in thousands)
Purchased Shares	820	2,299	748
Issued Shares	508	77	291

        See Note 2(a) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for additional information on issued shares.

        In November 2001, Cinergy filed a shelf registration statement with the SEC with respect to the issuance of common stock, preferred stock, and other securities with an aggregate amount of $800 million. In December 2001, Cinergy issued approximately $316 million notional amount of combined securities, a component of which was stock purchase contracts. These contracts obligate the holder to purchase common shares of Cinergy Corp. on or before February 2005. See Note 4 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the stock purchase contracts.

Dividend Restrictions

Cinergy Corp.'s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. common dividends. Cinergy Corp., CG&E, and PSI

13

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 under CG&E's and PSI's credit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock.

Guarantees

        We are subject to an SEC order under the PUHCA, which limits the amounts Cinergy Corp. 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 on Cinergy's Consolidated Balance Sheet. The amount outstanding represents Cinergy Corp.'s guarantees of liabilities and commitments of its consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. See Note 13(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a further discussion of guarantees.

Collateral Requirements

Cinergy has certain contracts in place, primarily with trading counterparties, that require the issuance of collateral in the event our debt ratings are downgraded below investment grade. Based upon our December 31, 2001 trading portfolio, if such an event were to occur, Cinergy would be required to issue up to approximately $30 million in collateral related to its gas trading operations.

Other

        Where subject to rate regulations, our operating companies have the ability to timely recover certain cash outlays through regulatory mechanisms such as fuel adjustment clause, purchased power tracker, gas cost recovery, and construction work in progress (CWIP) ratemaking. For further discussion see "Electric Industry" and "Gas Industry".

        We are exploring opportunities to monetize certain non-core investments, which would include our international and renewable assets operated by Cinergy Global Resources, Inc. (Global Resources) and other technology investments. In that regard, management believes that the effects of potential asset dispositions will not result in material gains or losses or be material to our results of operations. The Results of Operations discussions for Cinergy, CG&E, and PSI are combined within this section.

2001 RESULTS OF OPERATIONS—HISTORICAL

SUMMARY OF RESULTS

        Electric and gas gross margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 2001 and 2000 were as follows:

	Cinergy(1)				CG&E and subsidiaries				PSI
	2001		2000		2001		2000		2001		2000
	(in thousands)
Electric gross margin	$	2,270,274	$	2,229,869	$	1,215,385	$	1,183,816	$	942,530	$	959,541
Gas gross margin		231,017		267,304		199,665		224,633		—		—
Net income		442,279		399,466		326,654		266,820		162,333		135,398

(1)

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

        Diluted earnings per share (diluted EPS) for the year ended December 31, 2001, was $2.75 as compared to $2.50 for the year ended December 31, 2000. Included in 2000 results were previously reported one-time charges totaling $.11 per share related to a tentative agreement reached with the EPA and a limited early retirement program (LERP) offered to employees during 2000.

14

        The increase in 2001 earnings was primarily attributable to increased electric gross margins within Energy Merchant Business Unit's (Energy Merchant) origination, marketing and trading segment, and reduced operating expenditures. Partially offsetting this increase were lower electric gross margins within our regulated operations, mainly driven by mild weather and a slowed economy, and increased depreciation and interest expenses associated with new investments. Gas gross margins decreased for the year ended December 31, 2001, as compared to the same period last year, primarily as a result of mild weather.

        The explanations below follow the line items on the Statements of Income for Cinergy, CG&E, and PSI. However, only the line items that varied significantly from prior periods are discussed.

ELECTRIC OPERATING REVENUES

		Cinergy(1)					CG&E and subsidiaries						PSI
		2001		2000		% Change	2001		2000		% Change		2001		2000		% Change
		(in millions)
Retail		$	2,691	$	2,692	—	$	1,444	$	1,482	(3	)	$	1,247	$	1,210	3
Wholesale			5,432		2,640	106		2,612		1,226	113			2,802		1,443	94
Transportation			3		—	—		3		—	—			—		—	—
Other			55		52	6		38		31	23			26		31	(16	)
	Total	$	8,181	$	5,384	52	$	4,097	$	2,739	50		$	4,075	$	2,684	52

(1)

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

Electric operating revenues for Cinergy, CG&E, and PSI increased for the year ended December 31, 2001, as compared to the same period last year, mainly due to an increase in volumes and average price per megawatt-hour (MWh) realized on non-firm wholesale transactions related to energy marketing and trading activities. Non-firm power is power without a guaranteed commitment for physical delivery.

GAS OPERATING REVENUES

		Cinergy(1)						CG&E and subsidiaries
		2001		2000		% Change		2001		2000		% Change
		(in millions)
Retail		$	547	$	429	28		$	547	$	429	28
Wholesale			4,071		2,454	66			3		1	—
Transportation			40		56	(29	)		40		56	(29	)
Other			5		3	67			6		5	20
	Total	$	4,663	$	2,942	58		$	596	$	491	21

(1)

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

Gas operating revenues for Cinergy and CG&E increased for the year ended December 31, 2001, as compared to the same period last year. Cinergy's increase was primarily the result of increased volumes sold by Cinergy Marketing & Trading, LP (Marketing & Trading).

CG&E's retail gas revenues increased primarily due to a higher price received per thousand cubic feet (mcf) sold. This increase was partially offset by a decrease in retail gas sales resulting from warmer weather during the fourth quarter of 2001. The higher price reflects a substantial increase in the wholesale gas commodity cost during the first six months, which is passed directly to the retail customer

15

dollar-for-dollar under the gas cost recovery mechanism that is mandated by state law. Retail sales also increased and transportation sales decreased due to transportation customers (customers who purchase gas directly from other suppliers) returning to full gas service (customers who purchase gas and utilize the transportation services of CG&E).

OPERATING EXPENSES

		Cinergy(1)						CG&E and subsidiaries						PSI
		2001		2000		% Change		2001		2000		% Change		2001		2000		% Change
		(in millions)
Fuel		$	771	$	773	—		$	307	$	344	(11	)	$	453	$	407	11
Purchased and exchanged power			5,140		2,382	116			2,575		1,211	113			2,679		1,318	103
Gas purchased			4,432		2,674	66			397		266	49			—		—	—
Operation and maintenance			1,032		1,119	(8	)		442		492	(10	)		413		464	(11	)
Depreciation			378		344	10			187		181	3			150		141	6
Taxes other than income taxes			228		268	(15	)		174		208	(16	)		50		57	(12	)
	Total	$	11,981	$	7,560	58		$	4,082	$	2,702	51		$	3,745	$	2,387	57

(1)

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

Fuel

Fuel represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from the year ended December 31, 2000, to the year ended December 31, 2001:

	Cinergy(1)			CG&E			PSI
	(in millions)
2000 fuel expense	$	773		$	344		$	407
Increase (Decrease) due to changes in:
Price of fuel		47			22			25
Deferred fuel cost		45			2			43
MWh generation		(58	)		(36	)		(22	)
Other(2)		(36	)		(25	)		—
2001 fuel expense	$	771		$	307		$	453

(1)

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

(2)

Includes fair value adjustments of contracted coal options. See Note 1(k) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further discussion.

Purchased and Exchanged Power

Purchased and exchanged power expense for Cinergy, CG&E, and PSI increased for the year ended December 31, 2001, as compared to the same period last year, primarily due to an increase in purchases of non-firm wholesale power, reflecting higher sales volumes and higher prices paid per MWh.

16

Gas Purchased

Gas purchased expense for Cinergy increased for the year ended December 31, 2001, as compared to the same period last year, primarily due to an increase in gas commodity trading volumes. CG&E's expense increased for the year ended December 31, 2001, as compared to the same period last year, primarily due to higher prices paid per mcf during the first six months of 2001. CG&E's wholesale gas commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism that is mandated by state law.

Operation and Maintenance

Operation and maintenance expense for Cinergy, CG&E, and PSI decreased for the year ended December 31, 2001, as compared to the same period last year, due in part to one-time charges related to a tentative agreement reached with the EPA in late 2000 and the LERP offered during 2000, as part of a corporate restructuring initiative. Cinergy's and CG&E's decrease is also attributable to a sale of emission allowances, due to decreased electric generation, and Cinergy's and PSI's decrease reflects the reduction in amortization of demand-side management costs, resulting from the expiration of the agreement in May 2000.

Depreciation

Depreciation expense for Cinergy increased for the year ended December 31, 2001, as compared to the same period last year. This increase was primarily attributable to the acquisition of additional depreciable plant, including investments in peaking generation.

Taxes Other Than Income Taxes

Taxes other than income taxes expense for Cinergy, CG&E, and PSI decreased for the year ended December 31, 2001, as compared to the same period last year, primarily due to reduced property tax expense and other tax changes associated with deregulation in Ohio.

MISCELLANEOUS—NET

Miscellaneous—net for PSI increased $15 million for the year ended December 31, 2001, as compared to the same period last year, primarily due to income associated with capitalized financing costs of its pollution control projects and gains associated with the demutualization of one of our medical insurance carriers.

INTEREST

Interest expense for Cinergy increased $44 million for the year ended December 31, 2001, as compared to the same period last year, mainly due to debt issuances principally associated with the acquisition of additional peaking generation. Partially offsetting this increase was a decrease in short-term interest rates.

INCOME TAXES

Income tax expense for Cinergy, CG&E, and PSI increased $4 million, $27 million and $18 million, respectively for the year ended December 31, 2001, as compared to the same period last year, primarily due to an increase in taxable income.

ULH&P

        The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2001, in accordance with General Instruction I(2)(a).

17

        Electric and gas margins and net income for ULH&P for the year ended December 31, 2001 and 2000, were as follows:

	ULH&P
	2001		2000
	(in thousands)
Electric gross margin	$	79,398	$	65,686
Gas gross margin		36,740		40,359
Net income		35,924		24,632

Electric gross margins increased for the year ended December 31, 2001, as compared to the same period last year, primarily due to the recognition of revenues previously reserved as they were subject to refund. These revenues were recorded in connection with a 2000 retail rate filing with the Kentucky Public Service Company (KPSC). A settlement agreement was reached with the KPSC in May 2001, which granted ULH&P retention of these revenues. For further information regarding the settlement agreement, see Note 13(j) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

Gas gross margins decreased for the year ended December 31, 2001, as compared to the same period last year, as a result of milder weather and reduced industrial consumption.

        The Results of Operations discussions for Cinergy, CG&E, and PSI are combined within this section.

2000 RESULTS OF OPERATIONS—HISTORICAL

SUMMARY OF RESULTS

        Electric and gas margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 2000 and 1999, were as follows:

	Cinergy(1)				CG&E and subsidiaries				PSI
	2000		1999		2000		1999		2000		1999
	(in thousands)
Electric gross margin	$	2,229,869	$	2,052,602	$	1,183,816	$	1,108,371	$	959,541	$	922,053
Gas gross margin		267,304		212,153		224,633		204,016		—		—
Net income		399,466		403,641		266,820		233,576		135,398		117,199

(1)

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

        Our diluted EPS for the year ended December 31, 2000, was $2.50, as compared to $2.53 for the year ended December 31, 1999, mainly due to a decrease in contributions from our international operations, offset by increased earnings in our regulated business.

        The contribution to earnings of our international operations decreased $.70 per share for the year ended December 31, 2000, as compared to 1999, primarily due to the loss of equity earnings and resulting gain from the sale of our share of Midlands, which took place in July 1999. For further details regarding this transaction, refer to Note 11 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data". Earnings from our regulated operations had a net increase of $.66 per share for the year 2000, as compared to 1999. This increase was primarily attributable to growth in electric margins and continued improvement in our commodity supply business. Growth in residential, commercial, and industrial customer bases, along with improvements in cost of sales, were somewhat offset by the effects of mild weather experienced during 2000.

18

        Partially offsetting the overall increase in regulated operations were one-time charges totaling $.11 per share related to a tentative agreement with the EPA and the LERP offered in 2000 as part of a corporate restructuring initiative.

        The explanations below follow the line items on the Statements of Income for Cinergy, CG&E, and PSI. However, only the line items that varied significantly from prior periods are discussed.

ELECTRIC OPERATING REVENUES

		Cinergy(1)						CG&E and subsidiaries					PSI
		2000		1999		% Change		2000		1999		% Change	2000		1999		% Change
		(in millions)
Retail		$	2,692	$	2,725	(1	)	$	1,482	$	1,468	1	$	1,210	$	1,258	(4	)
Wholesale			2,640		1,539	72			1,226		687	78		1,443		840	72
Other			52		49	6			31		20	55		31		38	(18	)
	Total	$	5,384	$	4,313	25		$	2,739	$	2,175	26	$	2,684	$	2,136	26

(1)

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

Electric operating revenues for Cinergy, CG&E, and PSI increased for the year ended December 31, 2000, as compared to 1999, mainly due to an increase in volumes and the average price per MWh realized on non-firm wholesale transactions related to energy marketing and trading activities.

        The increase in other electric operating revenues for Cinergy primarily reflected marketing activities of Capital & Trading, a Cinergy non-regulated affiliate.

GAS OPERATING REVENUES

		Cinergy(1)					CG&E and subsidiaries
		2000		1999		% Change	2000		1999		% Change
		(in millions)
Retail		$	429	$	320	34	$	429	$	320	34
Wholesale			2,454		1,222	101		1		1	—
Transportation			56		51	10		56		51	10
Other			3		3	—		5		4	25
	Total	$	2,942	$	1,596	84	$	491	$	376	31

(1)

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

Gas operating revenues for Cinergy increased in 2000, as compared to 1999, primarily as a result of a higher price realized per mcf sold by Marketing & Trading.

CG&E's retail gas revenues increased primarily due to a higher price realized per mcf sold. Transportation revenues increased due to the continued trend of full-service customers (customers who purchase gas and utilize the transportation services of CG&E) purchasing gas directly from other suppliers.

        The market price of natural gas increased significantly in 2000, which caused CG&E to pay more for the gas it delivered to customers. The wholesale gas commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism that is mandated by state law.

19

OTHER REVENUES

Other operating revenues for Cinergy increased $67 million for 2000, as compared to 1999, primarily due to revenues resulting from the acquisition of an energy-related services affiliate in late 1999.

OPERATING EXPENSES

		Cinergy(1)					CG&E and subsidiaries						PSI
		2000		1999		% Change	2000		1999		% Change		2000		% Change		1999
		(in millions)
Fuel		$	773	$	761	2	$	344	$	341	1		$	407	$	397	3
Purchased and exchanged power			2,382		1,499	59		1,211		726	67			1,318		817	61
Gas purchased			2,674		1,384	93		266		172	55			—		—	—
Operation and maintenance			1,119		1,012	11		492		445	11			464		462	—
Depreciation			344		323	7		181		175	3			141		135	4
Taxes other than income taxes			268		266	1		208		212	(2	)		57		53	8
	Total	$	7,560	$	5,245	44	$	2,702	$	2,071	30		$	2,387	$	1,864	28

(1)

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

Fuel

Fuel represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from 1999 to 2000:

	Cinergy(1)			CG&E			PSI
	(in millions)
1999 fuel expense	$	761		$	341		$	397
Increase (Decrease) due to changes in:
Price of fuel		(14	)		(12	)		(2	)
Deferred fuel cost		(17	)		9			(26	)
MWh generation		44			6			38
Other		(1	)		—			—
2000 fuel expense	$	773		$	344		$	407

(1)

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

Purchased and Exchanged Power

Purchased and exchanged power expense increased for Cinergy, CG&E, and PSI for 2000, as compared to 1999. This increase was primarily due to an increase in purchases of non-firm wholesale power as a result of an increase in sales volumes from Marketing & Trading.

Gas Purchased

Gas purchased expense increased for Cinergy in 2000, as compared to 1999, primarily due to increased gas commodity trading activity and, for both Cinergy and CG&E, an increase in the average cost per mcf of gas purchased.

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Operation and Maintenance

Cinergy's Operation and maintenance expense increased in 2000, as compared to 1999, primarily due to a full year's realization of operating expenses resulting from the acquisition of an energy-related services affiliate in late 1999. Additionally for 2000, operation expenses increased for Cinergy, CG&E, and PSI as a result of one-time charges related to a tentative agreement reached with the EPA and the LERP offered as part of a corporate restructuring initiative.

Depreciation

Cinergy's, CG&E's, and PSI's Depreciation expense increased in 2000, as compared to 1999, due to additions to depreciable plant.

EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED SUBSIDIARIES

Cinergy's Equity in earnings (losses) of unconsolidated subsidiaries decreased $53 million in 2000, as compared to 1999. This decrease was primarily due to the loss in earnings resulting from the July 1999 sale of our 50% ownership interest in Midlands. For further information see Note 11 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

INTEREST

PSI's Interest expense decreased $8 million in 2000, as compared to 1999. This decrease was primarily due to PSI's net redemption of approximately $130 million of long-term debt during the year, which was slightly offset by an increase in average short-term interest rates.

FUTURE EXPECTATIONS/TRENDS

        In the "Future Expectations/Trends" section, we discuss electric and gas industry developments, market risk sensitive instruments and positions, inflation, accounting changes, and insurance. Each of these discussions will address the current status and potential future impact on our results of operations and financial condition.

ELECTRIC INDUSTRY

        The utility industry has traditionally operated as a regulated monopoly but is transitioning to an environment of increased wholesale and retail competition. Regulatory and legislative decisions being made at the federal and state levels are aimed at promoting customer choice and are shaping this transition. Customer choice provides the customer the ability to select an energy supplier (the company that generates or supplies the commodity) in an open and competitive marketplace. This emerging environment presents significant challenges, which are discussed below.

Wholesale Market Developments

        In 1996, the FERC issued orders to open the wholesale electric markets to competition. Competitors within the wholesale market include both utilities and non-utilities such as EWG's, independent power producers, and power marketers. We are involved in wholesale power marketing and trading and exempt wholesale generation through Energy Merchant.

        In both 1998 and 1999, the Midwest wholesale electric power markets experienced record price spikes. These spikes were caused by a number of factors including unseasonably hot weather, unplanned generating unit outages, transmission constraints, and increased electric commodity market volatility. These simultaneous events created temporary but extreme prices in the Midwest electricity markets. In response to these events, we have aggressively adopted a model that is focused on a balance of supply and demand.

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Supply-side Actions

        In September 1999, Capital & Trading formed a partnership (each party having a 50% ownership) with Duke Energy North America, LLC (Duke), to increase the available generating capacity for use during peak demand periods. The partnership was formed for the purpose of jointly constructing and owning three wholesale generating facilities.

        In March 2000, the IURC issued an order, requiring the partnership to immediately suspend all construction activities at the site located in Henry County, Indiana (a peaking plant with a total capacity of 129 MW of which we owned 65 MW). In making this decision, the IURC found that it needed additional information related to the project before issuing a final decision. The issues raised were air quality, water supply, noise control, landscaping, plant abandonment, and emergency services training. The IURC held a hearing on this matter in November 2000, and a favorable ruling was received in April 2001. The plant, which began generating power commercially in the summer of 2001, consists of three gas turbine engines.

        In June 2001, Capital & Trading and Duke announced they would dissolve their partnership. In September 2001, the partnership was dissolved and Capital & Trading obtained 100% ownership of the 680 MW wholesale generating facility located in Butler County, Ohio and the 129 MW wholesale generating facility located in Henry County, Indiana. In exchange for the Butler County, Ohio and Henry County, Indiana generating facilities, Duke received 100% ownership of the Vermillion County, Indiana generating facility (680 MW), which will be operated by Cinergy for five years.

        In March 2001, Capital & Trading completed the acquisition of the 480 MW Brownsville generation facility located in Haywood County, Tennessee and the 550 MW Caledonia generation facility located in Lowndes County, Mississippi. Brownsville has four natural gas-fired combustion turbines and Caledonia has six natural gas-fired combustion turbines.

        In December 2001, the IURC approved PSI's plan for environmental improvements that will increase the electric generating capacity at its Noblesville generating station from 100 MW to 300 MW. In addition to increasing capacity, upon completion of the project, overall emissions to the environment will be reduced.

Demand-side Actions

        Pursuant to Ohio's customer choice legislation enacted in 2001, 20% of CG&E's retail electric load is expected to switch suppliers by December 2003. CG&E currently has no plans to replace these customers by acquiring new retail customers, although CG&E reserves the flexibility to replace load in the wholesale market to the extent it chooses. For a further discussion on Ohio deregulation, see "Retail Market Developments" of this section.

FERC Notice of Proposed Rulemaking

        On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking, proposing to promulgate new standards of conduct regulations that would apply uniformly to natural gas pipelines and transmitting public utilities that are currently subject to FERC's standards of conduct. The FERC is proposing to adopt one set of standards of conduct to govern the relationships between regulated transmission providers and all their energy affiliates, broadening the definition of an affiliate covered by the standards of conduct, from the more narrow definition in the existing regulations. At this time, we are unable to predict either the outcome of this proceeding or its effect on Cinergy.

Retail Market Developments

        Currently, regulatory and legislative initiatives shaping the transition to a competitive retail market are the responsibilities of the individual states. Many states, including Ohio, have enacted electric utility

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deregulation legislation. In general, these initiatives have sought to separate the electric utility service into its basic components (generation, transmission, and distribution) and offer each component separately for sale. This separation is referred to as unbundling of the integrated services. Under the customer choice initiatives in Ohio, we continue to transmit and distribute electricity; however, the customer can purchase electricity from any available supplier and we are compensated by a "wires" charge. The following sections further discuss the current status of federal energy policies and deregulation legislation in the states of Ohio, Indiana, and Kentucky, each of which includes a portion of our service territory.

Federal Update

        President Bush has indicated that legislation addressing the energy security needs of America deserves prompt consideration. He appointed Vice President Cheney to head an inter-agency task force which recommended a number of actions, many of which are embodied in HR 4, which passed the House of Representatives last summer. This legislation includes a number of tax provisions, research and development provisions for clean coal technology, and provisions to increase supplies of natural gas.

        Legislation considering many of the President's recommendations has also been developed by Senator Bingaman and other Senate leaders and is scheduled to be considered by the full Senate in February 2002.

        The President also recognized the need to balance the energy and environmental needs of the country and supported combining the multitude of environmental regulations facing electric utilities into one legislative package. The intent is to give the industry one clear set of environmental goals, along with an appropriate amount of time to meet necessary emission reductions, while providing environmental benefits to consumers. Cinergy has supported this approach within the industry, Congress, and the Bush Administration in the interest of achieving an energy and environmental balance in any final legislative package.

Ohio

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

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

•

Residential customer rates are frozen through December 31, 2005;



•

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



•

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



•

The creation of a Regulatory Transition Charge designed to recover CG&E's regulatory assets and other transition costs over a ten-year period;

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•

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



•

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



•

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 and CG&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 denied CG&E's motion to dismiss. CG&Eis unable to predict the outcome of this proceeding.

        As indicated above, the August 31, 2000 order authorizes CG&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, Cinergy Power Investments, Inc., (Power Investments) filed an application with the FERC seeking EWG status. CG&E also filed an application seeking approval to transfer its generating assets to Power Investments. On December 21, 2001, the FERC issued an order certifying Power Investments' EWG status. As the transfer is contingent upon CG&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 Power Investments cannot be predicted.

        In anticipation of transferring the generation assets, Cinergy Wholesale Energy, Inc. (Wholesale Energy) was formed in the fourth quarter of 2000. Wholesale Energy is a direct subsidiary of Cinergy Corp. and will be the holding company for Cinergy's non-regulated energy commodities businesses, including Power Investments and Cinergy Power Generation Services, LLC.

        Upon FERC authorization, Power Investments will enter into a power sale arrangement with CG&E for the duration of the market development period, which is scheduled to terminate no later than December 31, 2005. Power Investments will supply CG&E with sufficient power to meet the standard service obligations of CG&E's customers that do not choose an alternate electric commodity supplier. In addition, Power Investments will enter into a second power sale agreement with CG&E to provide sufficient power to fulfill the electric commodity obligations of CG&E's wholesale customers. Power Investments will also replace CG&E as the electric commodity supplier in a power sale arrangement with ULH&P. This new contract will replace the power sales agreement that is in place between CG&E and ULH&P.

        The transfer of CG&E's generating assets to Power Investments will also affect the operating agreement between CG&E, PSI, and Services that has been in place since 1994. In 1994, when the operating agreement was entered into, both CG&E and PSI were vertically integrated regulated electric utilities. PSI is still a vertically integrated electric utility and the operations of its generating assets are still dedicated to Indiana ratepayers. Due to this situation, the IURC, CG&E, PSI, and Power Investments reached an agreement on a new Joint Generation Dispatch Agreement (JGDA). The JGDA allows for the joint dispatch of regulated PSI generation with Power Investments deregulated generation. If energy is transferred between PSI and Power Investments it will be priced at market

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rates. The majority of PSI's electric commodity requirements will be provided by PSI's generation. For more information refer to the "Termination of Operating Agreement" of this section.

Indiana

        Indiana lawmakers are involved in creating an Energy Policy Commission to assist in completing a comprehensive energy plan. Indiana Governor Frank O'Bannon will appoint members representing various stakeholder groups, including state government, industry, labor, and environmental representatives. This commission is expected to present a final report in December 2002.

Kentucky

        Throughout 1999, a special Kentucky Electricity Restructuring Task Force (Task Force), convened by the Kentucky legislature, studied the issues of electric deregulation. In January 2000, the Task Force issued a final report to Kentucky Governor Paul Patton recommending that lawmakers wait until the 2002 General Assembly before considering any deregulation that would open the state's electric industry to competition.

Other States

        At the end of 2000, approximately one half of the states and the District of Columbia had adopted deregulation plans. However, recent events are significantly influencing political and legislative activity. At the end of 2001, eight of the states decided to delay or suspend their deregulation activities. While we believe the situation in Ohio, as described above, and generally within the Midwest are different, we cannot predict the consequences, if any, on efforts to deregulate or discontinue deregulation within our service territory or markets.

Other

        Under generally accepted accounting principles, CG&E, PSI, and ULH&P apply the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71) to the applicable rate-regulated portions of their businesses. The provisions of Statement 71 allow CG&E, PSI, and ULH&P to capitalize (record as a deferred asset) costs that would normally be charged to expense. These costs are classified as regulatory assets in the accompanying financial statements and the majority have been approved by regulators for future recovery from customers through our rates. As of December 31, 2001, CG&E, PSI, and ULH&P have approximately $1 billion of net regulatory assets, of which $952 million have been approved for recovery.

        Except with respect to the generation assets of CG&E, as of December 31, 2001, CG&E, PSI, and ULH&P continue to meet each of the criteria required for the application of Statement 71. However, to the extent other states implement deregulation legislation, the application of Statement 71 will need to be reviewed. Based on our operating companies' current regulatory orders and the regulatory environment in which they currently operate, the future 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 the 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. See Note 1(c) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a further discussion of our regulatory assets.

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Midwest Independent Transmission System Operator, Inc. (Midwest ISO)

Historical

        As part of the effort to create a competitive wholesale power marketplace, the FERC approved the formation of the Midwest ISO during 1998. In that same year, Cinergy agreed to join the Midwest ISO in preparation for meeting anticipated changes in the FERC regulations and future deregulation requirements. The Midwest ISO was established as a non-profit organization to maintain functional control over the combined transmission systems of its members.

FERC Orders

        On December 19, 2001, the FERC issued several key orders having considerable impact upon the Midwest ISO and its transmission owning members. Among other determinations, the FERC approved the proposal of the Midwest ISO to become the first FERC-approved Regional Transmission Organization (RTO). It also denied a similar proposal from the companies seeking to form the Alliance Regional Transmission Organization (Alliance RTO) on the basis that the proposal lacked sufficient scope. The Alliance RTO is a planned for-profit transmission company involving various utilities, which have transmission systems that cover parts of Michigan, Ohio, Indiana, West Virginia, and Virginia. The FERC encouraged the Alliance RTO companies to explore joining the Midwest ISO and set a 60-day deadline for those companies to provide the FERC a statement of their plans to join an RTO. In addition, the FERC also directed the Midwest ISO to file a plan with the FERC within 60 days to address interim operations for the period of time in which the Midwest ISO is operational and the Alliance RTO companies have not yet joined an RTO.

        In related activity, the FERC issued an order on December 14, 2001, in response to protests of the Midwest ISO's proposed methodology related to the calculation of its administrative adder fees for the services it provides. Cinergy and a number of other parties filed protests to the proposed methodology, suggesting, among other things, that the methodology was inconsistent with the transmission owners' prior agreement with the Midwest ISO, and selectively allowed only independent transmission companies to choose which unbundled administrative adder services they wished to purchase from the Midwest ISO. In its December 14, 2001 Order, the FERC found that the Midwest ISO's proposed methodology for determination of the administrative adder fees had not been shown to be just and reasonable, and provided the Midwest ISO and the protesting parties a period of 60 days to reach settlement on the issues before an evidentiary hearing would be conducted.

Operations Updates

        On November 30, 2001, the Midwest ISO and Mid-Continent Area Power Pool (MAPP) closed a financial transaction in which the Midwest ISO agreed to acquire certain assets and liabilities of MAPP, including its St. Paul, Minnesota control center. In addition, since the third quarter of 2001, the Midwest ISO and Southwest Power Pool (SPP) have been in a process of agreeing upon a definitive document to establish a business combination which would include the Midwest ISO's purchase of substantially all of the assets of SPP and the assumption of appropriate liabilities. A firm date for the closure of this transaction has not been established.

        On December 15, 2001, the Midwest ISO initiated startup of its operations with the provision of a variety of support or stand alone services to its transmission owning members. The Midwest ISO achieved full startup, including implementation of tariff administration, on February 1, 2002.

State Regulatory Agencies Filings

        In June 2001, Cinergy and various other Indiana Midwest ISO transmission owners made a joint state filing with the IURC seeking permission to transfer functional control of their transmission

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facilities to the Midwest ISO. On December 17, 2001, Cinergy and four other transmission owning Indiana companies received conditional approval from the IURC to transfer functional control of their transmission facilities to the Midwest ISO. The conditional terms of the approval were satisfied prior to the Midwest ISO full startup date of February 1, 2002.

Repeal of PUHCA

        Early in 2001, S. 206, a bill to repeal the PUHCA, was introduced in the Senate. It was referred to the Senate Committee on Banking, Housing and Urban Affairs for action. Subsequently, a hearing was held in the Subcommittee on Securities and Investment to identify support for and opposition to this legislation. S. 206 was favorably reported out by a 19-1 vote by the full Senate Committee on Banking, Housing and Urban Affairs in April 2001. This legislation has been included as part of the Senate Energy Bill which will proceed directly to the Senate floor for debate. Issues surrounding the Enron Corp. (Enron) collapse may have an adverse impact on full repeal of PUHCA, and some Senators have indicated an interest in strengthening consumer protection aspects of the law. However, it currently remains as part of the Senate Energy Bill, scheduled for consideration in the first quarter of 2002.

        In the House of Representatives, Subcommittee on Energy and Air Quality Chairman Joe Barton has drafted an electricity deregulation bill which includes PUHCA repeal. That legislation is also scheduled for consideration in the first quarter of 2002, but again several Committee members have expressed concern about PUHCA repeal in light of the Enron collapse. Cinergy supports PUHCA repeal and will continue to monitor developments as well as possibilities for limited repeal.

Significant Rate Developments

Purchased Power Tracker

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

        A hearing was held before the IURC in February 2001, to determine whether it was appropriate for PSI to continue the Tracker for future periods. In April 2001, a favorable order was received extending the Tracker for two years, through the summer of 2002. PSI is authorized to recover 90% of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portions), with the remaining 10% deferred for subsequent recovery in PSI's next general rate case (subject to a showing of prudence).

        In March 2001, the IURC held a hearing to review PSI's 2000 purchases and rule on its associated request for recovery of costs. In May 2001, the IURC issued an order approving the recovery of PSI's summer 2000 purchased power costs ($18.5 million) via the Tracker.

        In June 2001, PSI filed a petition with the IURC seeking approval of the recovery through the Tracker of its summer 2001 purchased power costs. In October 2001, PSI filed an amended petition with the IURC, seeking approval of the costs associated with additional power purchases made during July and August 2001. Hearings before the IURC were held in January 2002, with a decision expected in the second quarter of 2002.

Purchased Power Agreement

ULH&P purchases energy from CG&E pursuant to a new contract effective January 1, 2002, which was approved by the FERC and the KPSC. This five-year agreement is a negotiated fixed-rate contract with CG&E and replaces the previous cost of service based contract, which expired on December 31, 2001.

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Termination of Operating Agreement

        Upon consummation of the merger between CG&E and PSI Resources, Inc. in 1994, an operating agreement entered into between CG&E, PSI, and Services was filed with and approved by the FERC. This agreement was established to provide for the coordinated planning and operation of the two regulated entities' generation and transmission systems.

        In October 2000, CG&E, PSI, and Services filed a notice of termination of the operating agreement with the FERC. The reason for the termination filing was that, with the introduction of deregulation in the State of Ohio, the companies no longer share the common characteristics that formed the basis for the operating agreement. In December 2000, the FERC ruled that the companies have the contractual right to terminate the operating agreement. Additionally, the FERC established a termination effective date of May 22, 2001, and set a May 1, 2001, hearing date on the issue of the reasonableness of termination.

        Certain parties appealed the FERC's December 2000 decision. In March 2001, the IURC initiated an investigation proceeding into the termination of the operating agreement. In May 2001, the parties to the FERC proceeding reached a settlement resolving termination issues and certain compensation and damage issues. This settlement, which was approved by the FERC in June 2001, delayed the termination of the existing operating agreement until a new successor agreement has been approved by the FERC. The settlement also provided that the parties would engage in negotiations concerning the terms and conditions of a successor agreement(s).

        In August 2001, the parties to both the IURC investigation proceeding and the previous FERC proceeding entered into two complementary settlement agreements. Both agreements addressed, among other things, the terms and conditions of a proposed new joint generation operating agreement and a proposed new joint transmission operating agreement. The IURC settlement agreement was approved by the IURC in September 2001. Both the IURC and the FERC settlement agreements are conditioned upon FERC acceptance of the proposed successor agreements. Cinergy filed the successor agreements with the FERC in October 2001. At this time, we cannot predict the outcome or the timing of the FERC proceedings regarding the proposed successor agreements.

PSI Fuel Adjustment Charge

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

CWIP Ratemaking Treatment for NO_X Equipment

        During the third quarter of 2001, PSI filed an application with the IURC requesting CWIP ratemaking treatment for costs related to NO_Xequipment currently being installed at certain PSI generation facilities. CWIP ratemaking treatment allows for the recovery of carrying costs on the equipment during the construction period. PSI filed its case-in-chief testimony in January 2002. PSI anticipates that hearings before the IURC will be scheduled during the second quarter of 2002. At this time, we cannot predict the outcome of this matter.

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Transfer of Generating Assets to PSI

        In December 2001, PSI filed a petition with the IURC requesting approval, under Indiana's Power Plant Construction Act, to acquire the Butler County, Ohio and Henry County, Indiana peaking plants from Capital & Trading in order to maintain adequate reserve margins. The IURC has scheduled a pre-hearing conference for February 2002 at which time the procedural schedule will be determined. This transfer is also contingent upon receipt of approval from the FERC and the SEC. PSI is unable to predict the outcome of this request.

GAS INDUSTRY

ULH&P Gas Rate Case

        On June 6, 2001, ULH&P filed a retail gas rate case with the KPSC seeking to increase base rates for natural gas distribution services by $7.3 million annually, or 8.4% overall. In addition to an increase in base rates, ULH&P requested recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with a capital cost of approximately $112 million over the next ten years. A hearing on this matter was held in November 2001 and an order was issued on January 31, 2002. In the order the KPSC authorized a base rate increase of $2.7 million or 2.8% overall, to be effective on January 31, 2002. In addition, the KPSC authorized ULH&P to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program for an initial period of three years, with the possibility of renewal for the full ten years. Per the terms of the order, the tracker will be set annually and the first filing will be made by March 31, 2002. ULH&P will request rehearing before the KPSC on selected items within the order. We expect a decision on these matters by the end of the first quarter 2002.

CG&E Gas Rate Case

        On July 31, 2001, CG&E filed a retail gas rate case with the PUCO seeking to increase base rates for natural gas distribution services by approximately $26 million or 5% overall. We expect that any rate change as a result of this filing will be effective in the second quarter of 2002. Simultaneously, CG&E requested recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with a capital cost of approximately $716 million over the next ten years. A hearing in this case will be held in the first quarter of 2002.

Gas Prices

        As the result of the market price of natural gas increasing significantly in 2000, CG&E's and ULH&P's gas supply costs increased. These costs are passed directly through to customers dollar-for-dollar under the gas cost recovery mechanisms that are mandated by state law in Ohio and Kentucky. During 2001, the market price of natural gas decreased and CG&E and ULH&P lowered their rates in accordance with the downward trending gas prices.

        On May 14, 2001, ULH&P filed an application with the KPSC requesting approval of a gas procurement-hedging program designed to mitigate the effects of gas price volatility on customers. On July 16, 2001, the KPSC approved the pilot program for the 2001-2002 heating season, subject to certain restrictions. The approved hedging program allows the pre-arranging of between 50-75% of winter heating season base load gas requirements. ULH&P made advance arrangements for approximately 50% of its winter 2001/2002 base load requirements under the program.

        In July 2001, CG&E filed an application with the PUCO requesting approval of its gas procurement-hedging program. This request was subsequently denied. However, in denying CG&E's request for pre-approval of a hedging program, the PUCO order provided clarification that prudently incurred hedging costs are a valid component of CG&E's gas purchasing strategy. As a result, CG&E

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has hedged approximately 50% of its winter 2001/2002 base load requirements and CG&E will seek PUCO approval for its hedging program on an after the fact basis. At this time, we cannot predict the outcome of this event.

MARKET RISK SENSITIVE INSTRUMENT AND POSITIONS

Energy Commodities Sensitivity

        The transactions associated with Energy Merchant's energy marketing and trading activities give rise to various risks, including market risk. Market risk represents the potential risk of loss from adverse changes in market price of electricity or other energy commodities. As Energy Merchant continues to develop its energy marketing and trading business (and due to its substantial investment in generation assets), its exposure to movements in the price of electricity and other energy commodities may become greater. As a result, we may be subject to increased future earnings volatility.

        The energy marketing and trading activities of Energy Merchant principally consist of CG&E's and PSI's power marketing and trading operations and Marketing & Trading's natural gas marketing and trading operations. These operations market and trade over-the-counter (an informal market where the buying/selling of commodities occurs) contracts for the purchase and sale of electricity (primarily in the Midwest region of the U.S.), natural gas, and other energy-related products. In addition, Energy Merchant also trades natural gas and other energy-related products on the New York Mercantile Exchange. The power marketing and trading operation consists of both physical activities (accounted for when the transaction settles) and trading activities (accounted for on a fair value basis). Transactions are designated as a physical activity when there is intent and ability to physically deliver the power from company-owned generation. Substantially all of the electricity in the physical portfolio requires settlement by physical delivery. All other transactions (including most natural gas contracts) are considered trading activities due to (a) the intent to financially settle the contracts, (b) the lack of hard assets, or (c) the inability to serve with company-owned assets. Some contracts within the trading portfolio may require settlement by physical delivery, but often times can be netted in accordance with industry standards at time of settlement.

        Many of the contracts in both the physical and trading portfolios commit us to purchase or sell electricity, natural gas, and other energy-related products at fixed prices in the future. The majority of the contracts in the natural gas and other energy-related product portfolios are financially settled contracts (i.e., there is no physical delivery related with these items). In addition, Energy Merchant also markets and trades over-the-counter option contracts. The use of these types of commodity instruments is designed to allow Energy Merchant to:

•

manage and economically hedge contractual commitments;



•

reduce exposure relative to the volatility of cash market prices;



•

take advantage of selected arbitrage opportunities; and



•

originate customized transactions with municipalities and end-use customers.

        Energy Merchant structures and modifies its net position to capture the following:

•

expected changes in future demand;



•

seasonal market pricing characteristics;



•

overall market sentiment; and



•

price relationships between different time periods and trading regions.

        At times, a net open position is created or is allowed to continue when Energy Merchant believes future changes in prices and market conditions may possibly result in profitable positions. Position

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imbalances can also occur due to the basic lack of liquidity in the wholesale power market. The existence of net open positions can potentially result in an adverse impact on our financial condition or results of operations. This potential adverse impact could be realized if the market price of electric power does not react in the manner or direction expected.

        Energy Merchant measures the market risk inherent in the trading portfolio employing value-at-risk (VaR) analysis and other methodologies, which utilize forward price curves in electric power markets to quantify estimates of the magnitude and probability of potential future losses related to open contract positions. VaR is a statistical measure used to quantify the potential loss in fair value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to an adverse market movement. Because most of the contracts in the physical portfolio require physical delivery of electricity and generally do not allow for net cash settlement, these contracts are not included in the VaR analysis.

        Our VaR is reported as a percentage of operating income, based on a 95% confidence interval, utilizing one-day holding periods. This means that on a given day (one-day holding period) there is a 95% chance (confidence interval) that our trading portfolio will lose less than the stated percentage of operating income. We disclose our VaR for power activities as a percent of consolidated operating income on a one-day basis at December 31, the average one-day basis at the end of each quarter, and the daily basis at December 31 of each year. On a one-day basis as of December 31, 2001, the VaR for the power trading activity was less than 1% of 2001 consolidated operating income and as of December 31, 2000, was less than 1% of 2000 consolidated operating income. On a one-day basis at the end of each quarter, the VaR for the power trading activity was less than 2% of consolidated operating income in 2001, and less than 1% in 2000. The daily VaR for the power trading portfolio as of December 31, 2000, was less than 1% of 2001 consolidated operating income and as of December 31, 1999, was also less than 1% of 2000 consolidated operating income. The VaR model uses the variance-covariance statistical modeling technique and historical volatilities and correlations over the past 200-day period. The estimated market prices used to value these transactions for VaR purposes reflect the use of established pricing models and various factors including quotations from exchanges and over-the-counter markets, price volatility factors, the time value of money, and location differentials.

        Energy Merchant, through some of our non-regulated subsidiaries, actively markets physical natural gas and actively trades derivative commodity instruments which are usually settled in cash including: forwards, futures, swaps, and options. The aggregated VaR amounts associated with these other trading and hedging activities were slightly more than one million dollars as of December 31, 2001, and less than one million dollars at December 31, 2000. On a one-day basis as of December 31, 2001, the VaR for the gas trading activity was less than 1% of 2001 consolidated operating income and as of December 31, 2000, was less than 1% of 2000 consolidated operating income. On a one-day basis at the end of each quarter, the VaR for the gas trading activity was less than 1% of consolidated operating income in 2001, and less than 1% in 2000. The daily VaR for gas trading portfolio as of December 31, 2000, was less than 1% of 2001 consolidated operating income and as of December 31, 1999, was also less than 1% of 2000 consolidated operating income. The VaR is calculated using a variance-covariance methodology and historical volatilities and correlations over the past 21-day period with a 95% confidence interval and a one-day holding period.

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        The changes in fair value of the energy risk management assets and liabilities for the year ended December 31, 2001, are presented in the table below:

Change in Fair Value for the Year Ended
December 31, 2001
(in millions)

Fair value of contracts outstanding at the beginning of the period		$	(78	)
Fair value of new contracts when entered into during the period:
	Options(1)		15
	Other trading instruments		29
Changes in fair value attributable to changes in valuation techniques and assumptions			10
Other changes in fair value			53
Less: Contracts realized or otherwise settled during the period			11
Fair value of contracts outstanding at the end of the period		$	18

(1)

Represents net option premiums paid.

        The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2001:

	Fair Value of Contracts at December 31, 2001
	Maturing
Source of Fair Value(1)										Total Fair Value
	2002		2003-2004			2005-2006		Thereafter
	(in millions)
Prices actively quoted	$	14	$	(27	)	$	—	$	—	$	(13	)
Prices based on models and other valuation methods		6		6			10		9		31
Total	$	20	$	(21	)	$	10	$	9	$	18

(1)

Active quotes are considered to be available for two years for standard electricity transactions and three years for standard gas transactions. Non-standard transactions are classified based on the extent, if any, of modeling used in determining fair value.

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.

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.

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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 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 court's 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 of Financial Accounting Standards No. 133, Accounting for Derivatives Instruments and Hedging Activities (Statement 133) (see Note 1(k) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data"). 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.

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.

Risk Management

        We manage, on a portfolio basis, the market risks in our energy marketing and trading transactions subject to parameters established by our Risk Policy Committee. Our market and credit risks are monitored by the Corporate Risk Management function to ensure compliance with stated risk management policies and procedures. The Corporate Risk Management function operates independently from the business units and other corporate functions, which originate and actively manage the market and credit risk exposures. Policies and procedures are periodically reviewed and monitored to ensure their responsiveness to changing market and business conditions. In addition, efforts are ongoing to develop systems to improve the timeliness and quality of market and credit risk information. Credit risk mitigation practices include requiring parent company guarantees, various forms of collateral, and the use of mutual netting/closeout agreements.

Exchange Rate Sensitivity

        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

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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.

Interest Rate Sensitivity

        Our net exposure to changes in interest rates consists of short-term debt instruments (including net Notes receivable from/Notes payable to affiliated companies), pollution control debt, and sales of accounts receivable. The following table reflects the different instruments used and the method of benchmarking interest rates, as of December 31, 2001, and 2000:

	Interest Benchmark		2001		2000
			(in millions)
Short-term Bank Loans/Commercial Paper	• Short-term Money Market • LIBOR(1)	Cinergy CG&E PSI ULH&P	$	877 445 43 26	$	862 152 239 29
Pollution Control Debt	• Daily Market • Auction Rate	Cinergy CG&E PSI		279 196 83		267 184 83
Sales of Accounts Receivable	• Short-term Money Market	Cinergy CG&E PSI ULH&P		257 150 107 22		257 156 101 26
Variable Rate Capital Leases	• LIBOR(1)	Cinergy CG&E		— —		31 31

(1)

London Inter-Bank Offered Rate (LIBOR)

        The weighted-average interest rates on the above instruments at December 31, 2001, and 2000, were as follows:

	2001	2000
Short-term Bank Loans/Commercial Paper	2.9%	7.0%
Pollution Control Debt	2.1%	4.5%
Sales of Accounts Receivable	2.4%	7.0%
Variable Rate Capital Leases	—	7.5%

        At December 31, 2001, forward yield curves project an increase in applicable short-term interest rates over the next five years.

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        The following table presents principal cash repayments, by maturity date and other selected information, for each registrant's long-term fixed-rate debt, other debt, and capital lease obligations as of December 31, 2001:

		Expected Maturity Date
Liabilities		2002			2003			2004			2005			2006			Thereafter			Total			Fair Value
		(in millions)
Cinergy
Long-term Debt(1)		$	123		$	178	(4)	$	811		$	201	(5)(6)	$	328		$	1,823		$	3,464		$	3,520
	Weighted-average interest rate(2)		7.3	%		6.2	%		6.2	%		6.8	%		6.7	%		6.9	%		6.7	%
Other(3)		$	25		$	14		$	3		$	2		$	6		$	242		$	292		$	285
	Weighted-average interest rate(2)		6.8	%		6.7	%		6.6	%		5.5	%		5.0	%		6.4	%		6.4	%
Capital Leases
	Fixed-rate leases	$	2.8		$	3.0		$	3.1		$	3.3		$	3.6		$	19.1		$	34.9		$	34.9
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%
CG&E and subsidiaries
Long-term Debt(1)		$	100		$	120	(4)	$	110		$	150	(6)	$	—		$	728		$	1,208		$	1,214
	Weighted-average interest rate(2)		7.3	%		6.3	%		6.5	%		6.9	%		—			7.0	%		6.9	%
Capital Leases
	Fixed-rate leases	$	1.5		$	1.6		$	1.7		$	1.9		$	2.0		$	10.8		$	19.5		$	19.5
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%
PSI
Long-term Debt(1)		$	23		$	58		$	1		$	51	(5)	$	328		$	895		$	1,356		$	1,379
	Weighted-average interest rate(2)		7.6	%		5.9	%		6.0	%		6.5	%		6.7	%		7.1	%		6.9	%
Capital Leases
	Fixed-rate leases	$	1.3		$	1.3		$	1.4		$	1.5		$	1.6		$	8.4		$	15.5		$	15.5
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%
ULH&P
Long-term Debt(1)		$	—		$	20		$	—		$	—		$	—		$	55		$	75		$	76
	Weighted-average interest rate(2)		—			6.1	%		—			—			—			7.3	%		7.0	%
Capital Leases
	Fixed-rate leases	$	0.5		$	0.5		$	0.5		$	0.5		$	0.6		$	3.2		$	5.8		$	5.8
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%

(1)

All long-term debt is fixed-rate and includes amounts reflected as long-term debt due within one year.

(2)

The weighted-average interest rate is calculated as follows: (1) for long-term debt obligations, the weighted-average interest rate is based on the coupon rates of the debt that is maturing in the year reported; (2) for the fixed-rate capital leases, the interest rate is fixed at approximately 6.2% with an amortizing principal structure; and (3) for the Global Resources investments, the interest rate is based on a spread over 6- and 12-month LIBOR.

(3)

Variable rate debt related to investments under Global Resources.

(4)

Includes 6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.

(5)

Includes 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate resets on August 1, 2005.

(6)

Includes 6.90% Debentures due June 1, 2025, reflected as maturing in 2005, as the debentures are putable to CG&E at the option of the holders on June 1, 2005.

        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

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that this swap will continue to be effective as a hedge. Changes in fair value of this swap are recorded in Accumulated other comprehensive income (loss), beginning with our adoption of Statement 133 on January 1, 2001. 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) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" 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.

INFLATION

        We believe that the recent inflation rates do not materially impact our financial condition. However, under existing regulatory practice for all of PSI, ULH&P, and the non-generating portion of CG&E, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.

ACCOUNTING MATTERS

Accounting Estimates

Fair Value Accounting for Energy Marketing and Trading

        We use fair value accounting for energy trading contracts, which is required, with certain exceptions, by Statement 133 and Emerging Issues Task Force (EITF) 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Most of the contracts used in our trading activities are short-term in nature and are priced using exchange based or over-the-counter price quotes. Long-term contracts typically must be valued using model pricing due to the lack of actively quoted prices. The period for which actively quoted prices are available varies by commodity and pricing point, but is generally shorter for electricity than gas. Use of model pricing requires estimation surrounding factors such as volatility and future price expectations beyond the actively quoted portion of the price curve. In addition, some contracts do not have fixed notional amounts and therefore must be valued using estimates of volumes to be consumed by the counterparty.

        We attempt to mitigate these risks by using complex valuation tools, both external and proprietary, which allow us to model prices for periods for which active quotes are unavailable. These models are dynamic and are constantly updated with the most recent data to improve estimates of future expectations. We attempt to mitigate risks for contracts that do not contain fixed notional amounts by obtaining historical data and projecting expected consumption. These models incorporate expectations surrounding the impacts that weather may play in future consumption. We also have a Corporate Risk Management function within Cinergy that is independent of the marketing and trading function and is under the oversight of a risk policy committee comprised primarily of senior company executives. This group's function is to provide an independent evaluation of both forward price curves and the valuation of energy contracts.

        There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Fair value accounting has risk, including its application to short-term contracts, as gains and losses recorded through its use are not yet realized. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

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Retail Customer Revenue Recognition

        Our retail revenues include amounts that are not yet billed to customers. Customers are billed throughout the month as both gas and electric meters are read. We recognize revenues for retail energy sales that have not yet been billed, but where gas or electricity has been consumed. This is termed "unbilled revenue" and is a widely recognized and accepted practice for utilities. In making our estimates of unbilled revenue, we must estimate the effect of weather on consumption. We use complex systems that consider various factors, including weather, in estimation of retail customer consumption at the end of each month. Given the use of these systems and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when revenue is billed.

Accounting Changes

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 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data". 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 for Cinergy 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.

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.

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Derivatives

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

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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.

INSURANCE

        On September 11, 2001, the U.S. experienced terrorists' attacks which resulted in significant loss of life and property. As a result of this tragedy, insurers generally re-evaluated coverage limitations and premium levels. While Cinergy is anticipating increases in its current premiums, we do not expect a material change in the availability of coverage. Management does not believe potential premium increases will be material to our results of operations.

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