~~QuickLinks-- Click here to rapidly navigate through this document~~

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR ~~15(d)~~15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2002~~March 31, 2003
or
oor

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

For the transition period fromto

	Commission File Number			Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.

1-11377		CINERGY CORP.	31-1385023
		(A Delaware Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	~~31-1385023~~
~~1-1232~~
1-1232		THE CINCINNATI GAS & ELECTRIC COMPANY	31-0240030
		(An Ohio Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	~~31-0240030~~
~~1-3543~~
1-3543		PSI ENERGY, INC.	35-0594457
		(An Indiana Corporation) 1000 East Main Street Plainfield, Indiana 46168 (513) 421-9500	~~35-0594457~~
~~2-7793~~
2-7793		THE UNION LIGHT, HEAT AND POWER COMPANY	31-0473080
		(A Kentucky Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	~~31-0473080~~

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes ý No o
This combined Form 10-Q is separately filed byCinergy Corp.,The Cincinnati Gas & Electric Company,PSI Energy, Inc., andThe Union Light, Heat and Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

The Union Light, Heat and Power Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing its company specific information with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

As of ~~October 31, 2002,~~April 30, 2003, shares of common stock outstanding for each registrant were as listed:
Registrant
Description
Shares
Cinergy Corp.
Par value $.01 per share
~~168,326,377~~
176,091,329
The Cincinnati Gas & Electric Company
Par value $8.50 per share
89,663,086
PSI Energy, Inc.
Without par value, stated value $.01 per share
53,913,701
The Union Light, Heat and Power Company
Par value $15.00 per share
585,333
2

TABLE OF CONTENTS
Item Number

Page Number
PART I FINANCIAL INFORMATION

1

Financial Statements

Cinergy Corp. 1
Consolidated Statements of Income 2
Consolidated Balance Sheets 3
Consolidated Statements of Changes in Common Stock Equity 5
Consolidated Statements of Cash Flows 7

The Cincinnati Gas & Electric Company

Consolidated Statements of Income and Comprehensive Income 9
Consolidated Balance Sheets 10
Consolidated Statements of Cash Flows 12

PSI Energy, Inc.

Consolidated Statements of Income and Comprehensive Income 14
Consolidated Balance Sheets 15
Consolidated Statements of Cash Flows 17

The Union Light, Heat and Power Company

Statements of Income 19
Balance Sheets 20
Statements of Cash Flows 22

Notes to Financial Statements

23

Cautionary Statements Regarding Forward-Looking Information

48

2

Management's Discussion and Analysis of Financial Condition and Results of Operations

Introduction 50
Organization 50
Liquidity and Capital Resources 51
2002 Quarterly Results of Operations—Historical 57
2002 Year to Date Results of Operations—Historical 61
Results of Operations—Future 66

3

Quantitative and Qualitative Disclosures About Market Risk

80

4

Controls and Procedures

80

PART II OTHER INFORMATION

1

Legal Proceedings

80

6

Exhibits and Reports on Form 8-K

81

Signatures

82

Certifications

83
i
Item
Number
PART I FINANCIAL INFORMATION
1
Financial Statements
Cinergy Corp.
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Changes in Common Stock Equity
Consolidated Statements of Cash Flows
The Cincinnati Gas & Electric Company
Consolidated Statements of Income and Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
PSI Energy, Inc.
Consolidated Statements of Income and Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
The Union Light, Heat and Power Company
Statements of Income
Balance Sheets
Statements of Cash Flows
Notes to Financial Statements
Cautionary Statements Regarding Forward-Looking Information
2
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
Organization
Liquidity and Capital Resources
2003 Quarterly Results of Operations - Historical
Results of Operations - Future
3
Quantitative and Qualitative Disclosures About Market Risk
4
Controls and Procedures
PART II OTHER INFORMATION
1
Legal Proceedings
4
Submission of Matters to a Vote of Security Holders
6
Exhibits and Reports on Form 8-K
Signatures
Certifications
3

CINERGY CORP.
AND SUBSIDIARY COMPANIES
1

4

CINERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

Quarter Ended
September 30
Year to Date
September 30

2002
2001
2002
2001

(in thousands, except per share amounts)
(unaudited)

Operating Revenues (Note 1(d))
Electric $ 2,554,687 $ 2,539,365 $ 5,178,481 $ 6,838,286
Gas 1,281,411 786,345 3,301,625 3,836,946
Other 49,890 21,604 89,668 61,722

Total Operating Revenues 3,885,988 3,347,314 8,569,774 10,736,954

Operating Expenses

Fuel and purchased and exchanged power (Note 1(d)) 1,871,365 1,888,694 3,357,585 5,131,209
Gas purchased (Note 1(d)) 1,243,507 761,325 3,142,899 3,667,603
Operation and maintenance 365,373 265,518 973,165 782,073
Depreciation 103,565 97,109 303,996 277,876
Taxes other than income taxes 64,890 59,325 201,559 175,826

Total Operating Expenses 3,648,700 3,071,971 7,979,204 10,034,587

Operating Income

237,288

275,343

590,570

702,367

Equity in Earnings (Losses) of Unconsolidated Subsidiaries

3,248

(4,333
)

7,956

(3,500
)
Miscellaneous—Net 5,035 5,366 888 13,845
Interest 63,543 68,762 186,414 200,379
Preferred Dividend Requirement of Subsidiary Trust 5,966 — 17,847 —

Income Before Taxes

176,062

207,614

395,153

512,333

Income Taxes

44,635

78,284

121,299

178,073

Preferred Dividend Requirements of Subsidiaries 859 859 2,575 2,575

Net Income $ 130,568 $ 128,471 $ 271,279 $ 331,685

Average Common Shares Outstanding

167,967

159,097

166,544

159,049

Earnings Per Common Share(Note 10)

Net Income $ 0.78 $ 0.81 $ 1.63 $ 2.08

Earnings Per Common Share—Assuming Dilution (Note 10)

Net Income $ 0.77 $ 0.80 $ 1.61 $ 2.06

Dividends Declared Per Common Share

$
0.45

$
0.45

$
1.35

$
1.35

Quarter Ended March 31

2003

2002

(in thousands, except per share amounts)

(unaudited)

Operating Revenues (Note 3)

Electric

$
836,883

$
779,376

Gas

398,913

190,064

Other

45,986

16,937

Total Operating Revenues

1,281,782

986,377

Operating Expenses

Fuel and purchased and exchanged power (Note 3)

279,483

229,290

Gas purchased (Note 3)

235,995

109,880

Operation and maintenance

326,661

262,578

Depreciation

106,023

98,566

Taxes other than income taxes

77,749

72,422

Total Operating Expenses

1,025,911

772,736

Operating Income

255,871

213,641

Equity in Earnings (Losses) of Unconsolidated Subsidiaries

592

4,689

Miscellaneous - Net

8,375

(1,309
)
Interest

60,564

61,223

Preferred Dividend Requirement of Subsidiary Trust

5,970

5,913

Income Before Taxes

198,304

149,885

Income Taxes

57,823

53,777

Preferred Dividend Requirements of Subsidiaries

858

858

Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles

139,623

95,250

Discontinued operations, net of tax

—

478

Cumulative effect of a change in accounting principles, net of tax (Note 1(j)(viii))

26,462

(10,899
)
Net Income

$
166,085

$
84,829

Average Common Shares Outstanding

173,387

164,295

Earnings Per Common Share (Note 9)

Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles

$
0.81

$
0.58

Discontinued operations, net of tax

—

—

Cumulative effect of a change in accounting principles, net of tax

0.15

(0.06
)
Net Income

$
0.96

$
0.52

Earnings Per Common Share - Assuming Dilution (Note 9)

Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles

$
0.80

$
0.58

Discontinued operations, net of tax

—

—

Cumulative effect of a change in accounting principles, net of tax

0.15

(0.06
)
Net Income

$
0.95

$
0.52

Dividends Declared Per Common Share

$
0.46

$
0.45

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
2
5

CINERGY CORP.

CONSOLIDATED BALANCE SHEETS
ASSETS

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

ASSETS
Current Assets
Cash and cash equivalents $ 119,267 $ 111,067
Restricted deposits 142,120 8,055
Notes receivable (Note 5) 78,946 31,173
Accounts receivable less accumulated provision for doubtful accounts of $17,943 at September 30, 2002, and $35,580 at December 31, 2001 (Note 5) 1,459,804 1,123,214
Materials, supplies, and fuel—at average cost 308,438 240,812
Energy risk management current assets (Note 1(c)) 363,132 449,397
Prepayments and other 133,505 110,311

Total Current Assets 2,605,212 2,074,029

Property, Plant, and Equipment—at Cost

Utility plant in service 8,547,851 8,089,961
Construction work in progress 366,099 464,560

Total Utility Plant 8,913,950 8,554,521
Non-regulated property, plant, and equipment 4,702,486 4,527,994
Accumulated depreciation 5,087,644 4,845,620

Net Property, Plant, and Equipment 8,528,792 8,236,895

Other Assets

Regulatory assets 1,049,266 1,015,863
Investments in unconsolidated subsidiaries 383,942 339,059
Energy risk management non-current assets (Note 1(c)) 161,995 134,445
Other investments 167,615 164,155
Goodwill 55,163 53,587
Other intangible assets 21,024 22,250
Other 232,531 259,530

Total Other Assets 2,071,536 1,988,889

Total Assets

$
13,205,540

$
12,299,813

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Assets

Cash and cash equivalents

$
259,159

$
221,083

Restricted deposits

8,221

8,116

Notes receivable

96,884

135,873

Accounts receivable less accumulated provision for doubtful accounts of $12,881 at March 31, 2003, and $16,374 at December 31, 2002

1,383,244

1,292,410

Materials, supplies, and fuel (Note 1(d))

245,061

319,456

Energy risk management current assets (Note 1(c))

439,358

464,028

Prepayments and other

108,367

118,208

Total Current Assets

2,540,294

2,559,174

Property, Plant, and Equipment - at Cost

Utility plant in service

9,100,552

8,641,351

Construction work in progress

508,021

469,300

Total Utility Plant

9,608,573

9,110,651

Non-regulated property, plant, and equipment

4,355,409

4,704,904

Accumulated depreciation (Note 1(j)(iii))

5,184,319

5,166,881

Net Property, Plant, and Equipment

8,779,663

8,648,674

Other Assets

Regulatory assets

1,016,477

1,022,696

Investments in unconsolidated subsidiaries

427,378

417,188

Energy risk management non-current assets (Note 1(c))

92,631

162,773

Other investments

165,130

163,851

Goodwill

43,717

43,717

Other intangible assets

14,117

14,736

Other

336,811

273,099

Total Other Assets

2,096,261

2,098,060

Assets of Discontinued Operations

1,916

1,120

Total Assets

$
13,418,134

$
13,307,028

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
3
6

CINERGY CORP.

CONSOLIDATED ~~BALANCE SHEETS~~
Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities

Accounts payable $ 1,448,647 $ 1,029,173
Accrued taxes 107,000 195,976
Accrued interest 43,076 56,216
Notes payable and other short-term obligations (Note 4) 714,125 1,155,786
Long-term debt due within one year (Note 4) 22,387 148,431
Energy risk management current liabilities (Note 1(c)) 316,179 429,794
Other 108,768 127,375

Total Current Liabilities 2,760,182 3,142,751

Non-Current Liabilities

Long-term debt (Note 3) 4,248,961 3,596,730
Deferred income taxes 1,531,030 1,301,407
Unamortized investment tax credits 120,416 127,385
Accrued pension and other postretirement benefit costs 488,276 438,962
Energy risk management non-current liabilities (Note 1(c)) 115,212 135,619
Other 315,918 246,340

Total Non-Current Liabilities 6,819,813 5,846,443

Total Liabilities

9,579,995

8,989,194

Preferred Trust Securities

Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company 307,752 306,327

Cumulative Preferred Stock of Subsidiaries

Not subject to mandatory redemption 62,828 62,833

Common Stock Equity (Note 2)

Common stock—$.01 par value; authorized shares—600,000,000; outstanding shares—168,267,726 at September 30, 2002, and 159,402,839 at December 31, 2001 1,683 1,594
Paid-in capital 1,889,119 1,619,659
Retained earnings 1,385,887 1,337,135
Accumulated other comprehensive income (loss) (21,724 ) (16,929 )

Total Common Stock Equity 3,254,965 2,941,459

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholders' Equity

$
13,205,540

$
12,299,813

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Liabilities

Accounts payable

$
1,455,370

$
1,321,968

Accrued taxes

235,646

254,823

Accrued interest

60,328

64,340

Notes payable and other short-term obligations (Note 5)

327,616

667,973

Long-term debt due within one year

318,949

191,454

Energy risk management current liabilities (Note 1(c))

434,111

407,710

Other

91,450

108,056

Total Current Liabilities

2,923,470

3,016,324

Non-Current Liabilities

Long-term debt (Note 4)

3,977,024

4,080,768

Deferred income taxes

1,507,089

1,471,872

Unamortized investment tax credits

115,792

118,095

Accrued pension and other postretirement benefit costs

642,121

626,167

Energy risk management non-current liabilities (Note 1(c))

84,805

143,991

Other

213,643

183,613

Total Non-Current Liabilities

6,540,474

6,624,506

Liabilities of Discontinued Operations

1,831

1,707

Total Liabilities

9,465,775

9,642,537

Preferred Trust Securities

Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company

308,702

308,187

Cumulative Preferred Stock of Subsidiaries

Not subject to mandatory redemption

62,828

62,828

Common Stock Equity (Note 2)

Common stock - $.01 par value; authorized shares - 600,000,000; outstanding shares - 175,876,919 at March 31, 2003, and 168,663,115 at December 31, 2002

1,759

1,687

Paid-in capital

2,116,222

1,918,136

Retained earnings

1,491,861

1,403,453

Accumulated other comprehensive income (loss)

(29,013
)
(29,800
)
Total Common Stock Equity

3,580,829

3,293,476

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholders’ Equity

$
13,418,134

$
13,307,028

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
4
7

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)
(unaudited)

Quarter Ended September 30, 2002

Balance at July 1, 2002

$
1,675

$
1,861,689

$
1,330,780

$
(4,787
)
$
3,189,357

Comprehensive income:
Net income 130,568 130,568
Other comprehensive income (loss), net of tax effect of $12,501
Foreign currency translation adjustment (Note 1(g)) 4,810 4,810
Unrealized gain (loss) on investment trusts (3,003 ) (3,003 )
Cash flow hedges (Note 1(b)) (18,744 ) (18,744 )

Total comprehensive income 113,631

Issuance of 781,597 shares of common stock—net

8

22,888

22,896

Dividends on common stock ($.45 per share) (75,469 ) (75,469 )
Other 4,542 8 4,550

Ending balance at September 30, 2002 $ 1,683 $ 1,889,119 $ 1,385,887 $ (21,724 ) $ 3,254,965

Quarter Ended September 30, 2001

Balance at July 1, 2001

$
1,591

$
1,623,458

$
1,240,761

$
(16,927
)
$
2,848,883

Comprehensive income:
Net income 128,471 128,471
Other comprehensive income (loss), net of tax effect of ($854)
Foreign currency translation adjustment (Note 1(g)) 7,664 7,664
Unrealized gain (loss) on investment trusts (1,191 ) (1,191 )
Minimum pension liability adjustment (4 ) (4 )
Cash flow hedges (Note 1(b)) (4,085 ) (4,085 )

Total comprehensive income 130,855

Issuance of 11,105 shares of common stock—net

587

587

Treasury shares reissued (190 ) (190 )
Dividends on common stock ($.45 per share) (71,593 ) (71,593 )
Other 1,488 9 1,497

Ending balance at September 30, 2001 $ 1,591 $ 1,625,343 $ 1,297,648 $ (14,543 ) $ 2,910,039

Common
Stock

Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Income (Loss)

Total
Common
Stock
Equity

(in thousands)

(unaudited)

Quarter Ended March 31, 2003

Balance at January 1, 2003 (168,663,115 shares)

$
1,687

$
1,918,136

$
1,403,453

$
(29,800
)
$
3,293,476

Comprehensive income:

Net income

166,085

166,085

Other comprehensive income (loss), net of tax effect of ($275)

Foreign currency translation adjustment

2,090

2,090

Unrealized gain (loss) on investment trusts

(851
)
(851
)
Cash flow hedges (Note 1(j)(iv))

(452
)
(452
)
Total comprehensive income

166,872

Issuance of common stock - net (7,213,804 shares)

72

193,896

193,968

Dividends on common stock ($.46 per share)

(77,685
)

(77,685
)
Other

4,190

8

4,198

Ending balance at March 31, 2003 (175,876,919 shares)

$
1,759

$
2,116,222

$
1,491,861

$
(29,013
)
$
3,580,829

Quarter Ended March 31, 2002

Balance at January 1, 2002 (159,402,839 shares)

$
1,594

$
1,619,659

$
1,337,135

$
(16,929
)
$
2,941,459

Comprehensive income:

Net income

84,829

84,829

Other comprehensive income (loss), net of tax effect of $1,084

Foreign currency translation adjustment

(1,584
)
(1,584
)
Unrealized gain (loss) on investment trusts

(1,051
)
(1,051
)
Minimum pension liability adjustment

136

136

Cash flow hedges (Note 1(j)(iv))

240

240

Total comprehensive income

82,570

Issuance of common stock - net (7,423,257 shares)

75

215,894

215,969

Dividends on common stock ($.45 per share)

(71,882
)

(71,882
)
Other

3,785

8

3,793

Ending balance at March 31, 2002 (166,826,096 shares)

$
1,669

$
1,839,338

$
1,350,090

$
(19,188
)
$
3,171,909

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
5
8

CINERGY CORP.

CONSOLIDATED STATEMENTS OF ~~CHANGES IN COMMON STOCK EQUITY~~

~~(Continued)~~
CASH FLOWS

Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Common
Stock
Equity

(dollars in thousands)
(unaudited)

Nine Months Ended September 30, 2002
Balance at January 1, 2002 $ 1,594 $ 1,619,659 $ 1,337,135 $ (16,929 ) $ 2,941,459
Comprehensive income:
Net income 271,279 271,279
Other comprehensive income (loss), net of tax effect of $7,879
Foreign currency translation adjustment (Note 1(g)) 20,123 20,123
Unrealized gain (loss) on investment trusts (4,637 ) (4,637 )
Minimum pension liability adjustment 136 136
Cash flow hedges (Note 1(b)) (20,417 ) (20,417 )

Total comprehensive income 266,484
Issuance of 8,864,887 shares of common stock—net 89 258,300 258,389
Dividends on common stock ($1.35 per share) (222,551 ) (222,551 )
Other 11,160 24 11,184

Ending balance at September 30, 2002 $ 1,683 $ 1,889,119 $ 1,385,887 $ (21,724 ) $ 3,254,965

Nine Months Ended September 30, 2001

Balance at January 1, 2001

$
1,590

$
1,619,153

$
1,179,113

$
(10,895
)
$
2,788,961

Comprehensive income:
Net income 331,685 331,685
Other comprehensive income (loss), net of tax effect of $490
Foreign currency translation adjustment (Note 1(g)) 4,959 4,959
Unrealized gain (loss) on investment trusts (1,334 ) (1,334 )
Cumulative effect of change in accounting principle (2,500 ) (2,500 )
Minimum pension liability adjustment 64 64
Cash flow hedges (Note 1(b)) (4,837 ) (4,837 )

Total comprehensive income 328,037
Issuance of 131,497 shares of common stock—net 1 4,278 4,279
Treasury shares purchased (10,015 ) (10,015 )
Treasury shares reissued 5,810 5,810
Dividends on common stock ($1.35 per share) (214,689 ) (214,689 )
Other 6,117 1,539 7,656

Ending balance at September 30, 2001 $ 1,591 $ 1,625,343 $ 1,297,648 $ (14,543 ) $ 2,910,039

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Activities

Net income

$
166,085

$
84,829

Items providing or (using) cash currently:

Depreciation

106,023

98,566

Loss (gain) on discontinued operations, net of tax

—

(478
)
Cumulative effect of a change in accounting principles, net of tax

(26,462
)
10,899

Change in net position of energy risk management activities

9,730

(50,005
)
Deferred income taxes and investment tax credits - net

18,013

2,594

Equity in (earnings) losses of unconsolidated subsidiaries

(592
)
(4,689
)
Allowance for equity funds used during construction

(3,579
)
(2,850
)
Regulatory assets deferrals

(20,588
)
(17,665
)
Regulatory assets amortization

27,966

29,976

Accrued pension and other postretirement benefit costs

15,954

(105
)
Deferred costs under gas recovery mechanism

(38,659
)
5,955

Changes in current assets and current liabilities:

Restricted deposits

(105
)
(728
)
Accounts and notes receivable

(51,845
)
76,442

Materials, supplies, and fuel

74,395

22,459

Prepayments

1,382

1,101

Accounts payable

133,402

(29,497
)
Accrued taxes and interest

(23,189
)
50,274

Other assets

3,489

13,449

Other liabilities

6,045

(6,918
)

Net cash provided by (used in) operating activities

397,465

283,609

Financing Activities

Change in short-term debt

(340,357
)
(205,918
)
Issuance of long-term debt

35,000

—

Redemption of long-term debt

(11,270
)
(30,722
)
Retirement of preferred stock of subsidiaries

—

(2
)
Issuance of common stock

193,968

215,969

Dividends on common stock

(77,685
)
(71,882
)

Net cash provided by (used in) financing activities

(200,344
)
(92,555
)

Investing Activities

Construction expenditures (less allowance for equity funds used during construction)

(151,187
)
(187,678
)
Acquisitions and other investments

(7,858
)
(18,125
)

Net cash provided by (used in) investing activities

(159,045
)
(205,803
)

Net increase (decrease) in cash and cash equivalents

38,076

(14,749
)

Cash and cash equivalents at beginning of period

221,083

111,067

Cash and cash equivalents at end of period

$
259,159

$
96,318

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:

Interest (net of amount capitalized)

$
67,259

$
48,373

Income taxes

$
66,477

$
19,242

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
6
9

~~CINERGY CORP.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

Year to Date
September 30

2002
2001

(dollars in thousands)
(unaudited)

Operating Activities
Net income $ 271,279 $ 331,685
Items providing or (using) cash currently:
Depreciation 303,996 277,876
Change in net position of energy risk management activities (61,838 ) (79,070 )
Deferred income taxes and investment tax credits—net 169,377 40,716
Equity in earnings of unconsolidated subsidiaries (7,956 ) 3,500
Allowance for equity funds used during construction (8,802 ) (5,163 )
Regulatory assets deferrals (69,923 ) (99,985 )
Regulatory assets amortization 93,163 93,978
Accrued pension and other postretirement benefit costs 49,314 26,237
Changes in current assets and current liabilities:
Restricted deposits (2,465 ) (4,281 )
Accounts and notes receivable (339,704 ) (114,127 )
Materials, supplies, and fuel (71,276 ) (68,785 )
Prepayments (31,247 ) (65,604 )
Accounts payable 429,778 108,518
Accrued taxes and interest (102,116 ) 51,475
Other items—net 51,291 20,259

Net cash provided by (used in) operating activities 672,871 517,229

Financing Activities

Change in short-term debt (441,661 ) 82,313
Issuance of long-term debt 649,020 870,661
Redemption of long-term debt (134,640 ) (42,403 )
Funds on deposit from issuance of debt securities (131,600 ) —
Retirement of preferred stock of subsidiaries (3 ) (1 )
Issuance of common stock 258,389 4,279
Dividends on common stock (222,551 ) (214,689 )

Net cash provided by (used in) financing activities (23,046 ) 700,160

Investing Activities

Construction expenditures (less allowance for equity funds used during construction) (593,682 ) (587,428 )
Acquisitions and other investments (47,943 ) (575,234 )

Net cash provided by (used in) investing activities (641,625 ) (1,162,662 )

Net increase (decrease) in cash and cash equivalents

8,200

54,727

Cash and cash equivalents at beginning of period

111,067

93,054

Cash and cash equivalents at end of period

$
119,267

$
147,781

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:
Interest (net of amount capitalized) $ 207,659 $ 186,059
Income taxes $ 30,900 $ 84,860
~~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

10

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Quarter Ended
September 30
Year to Date
September 30

2002
2001
2002
2001

(dollars in thousands)
(unaudited)

Operating Revenues (Note 1(d))
Electric $ 1,747,379 $ 1,275,979 $ 3,249,715 $ 3,420,928
Gas 41,452 53,217 277,069 457,717

Total Operating Revenues 1,788,831 1,329,196 3,526,784 3,878,645

Operating Expenses

Fuel and purchased and exchanged power (Note 1(d)) 1,391,221 930,433 2,300,565 2,521,137
Gas purchased 12,594 24,729 145,033 314,575
Operation and maintenance 150,247 117,067 394,443 349,462
Depreciation 49,005 47,135 146,057 139,398
Taxes other than income taxes 50,304 43,617 149,509 135,585

Total Operating Expenses 1,653,371 1,162,981 3,135,607 3,460,157

Operating Income

135,460

166,215

391,177

418,488

Miscellaneous—Net

4,140

336

4,002

(1,396
)
Interest 23,746 25,353 68,375 79,236

Income Before Taxes

115,854

141,198

326,804

337,856

Income Taxes

44,085

51,808

124,780

117,490

Net Income

$
71,769

$
89,390

$
202,024

$
220,366

Preferred Dividend Requirement

211

211

634

634

Net Income Applicable to Common Stock

$
71,558

$
89,179

$
201,390

$
219,732

Net Income

$
71,769

$
89,390

$
202,024

$
220,366

Other Comprehensive Income (Loss), Net of Tax Effect

(17,588
)

(4,608
)

(19,673
)

(7,268
)

Comprehensive Income

$
54,181

$
84,782

$
182,351

$
213,098

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Revenues (Note 3)

Electric

$
428,564

$
398,119

Gas

275,276

179,609

Total Operating Revenues

703,840

577,728

Operating Expenses

Fuel and purchased and exchanged power (Note 3)

130,554

107,248

Gas purchased

171,765

107,968

Operation and maintenance

134,760

105,855

Depreciation

49,264

48,160

Taxes other than income taxes

60,518

53,486

Total Operating Expenses

546,861

422,717

Operating Income

156,979

155,011

Miscellaneous - Net

6,584

(3,704
)
Interest

25,841

22,855

Income Before Taxes

137,722

128,452

Income Taxes

51,424

50,867

Income Before Cumulative Effect of a Change in Accounting Principles

86,298

77,585

Cumulative effect of a change in accounting principles, net of tax (Note 1(j)(viii))

30,938

—

Net Income

$
117,236

$
77,585

Preferred Dividend Requirement

211

211

Net Income Applicable to Common Stock

$
117,025

$
77,374

Net Income

$
117,236

$
77,585

Other Comprehensive Income (Loss), Net of Tax Effect

(306
)
(172
)

Comprehensive Income

$
116,930

$
77,413

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
9
11

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
ASSETS

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

ASSETS

Current Assets

Cash and cash equivalents $ 8,526 $ 9,074
Restricted deposits 88,305 3,540
Notes receivable from affiliated companies (Note 5) 51,772 —
Accounts receivable less accumulated provision for doubtful accounts of $6,005 at September 30, 2002, and $25,874 at December 31, 2001 (Note 5) 536,406 332,970
Accounts receivable from affiliated companies 2,012 12,112
Materials, supplies, and fuel—at average cost 131,543 138,119
Energy risk management current assets (Note 1(c)) 35,583 44,360
Prepayments and other 25,140 13,087

Total Current Assets 879,287 553,262

Property, Plant, and Equipment—at Cost

Utility plant in service
Electric 2,067,341 2,000,595
Gas 960,992 926,381
Common 242,205 253,978

Total Utility Plant In Service 3,270,538 3,180,954
Construction work in progress 99,475 96,247

Total Utility Plant 3,370,013 3,277,201
Non-regulated property, plant, and equipment 3,407,761 3,314,285
Accumulated depreciation 2,678,476 2,555,639

Net Property, Plant, and Equipment 4,099,298 4,035,847

Other Assets

Regulatory assets 597,001 592,491
Energy risk management non-current assets (Note 1(c)) 61,796 48,982
Other investments 983 1,080
Other 118,617 128,082

Total Other Assets 778,397 770,635

Total Assets

$
5,756,982

$
5,359,744

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Assets

Cash and cash equivalents

$
26,870

$
45,336

Restricted deposits

3,037

3,071

Notes receivable from affiliated companies

207,402

148,823

Accounts receivable less accumulated provision for doubtful accounts of $2,707 at March 31, 2003, and $5,942 at December 31, 2002

106,416

117,269

Accounts receivable from affiliated companies

27,650

97,584

Materials, supplies, and fuel

94,226

121,881

Energy risk management current assets (Note 1(c))

74,339

57,912

Prepayments and other

14,409

8,560

Total Current Assets

554,349

600,436

Property, Plant, and Equipment - at Cost

Utility plant in service

Electric

2,097,439

2,073,133

Gas

1,019,175

1,003,870

Common

249,593

248,938

Total Utility Plant In Service

3,366,207

3,325,941

Construction work in progress

80,664

84,249

Total Utility Plant

3,446,871

3,410,190

Non-regulated property, plant, and equipment

3,469,525

3,445,056

Accumulated depreciation (Note 1(j)(iii))

2,692,027

2,712,105

Net Property, Plant, and Equipment

4,224,369

4,143,141

Other Assets

Regulatory assets

596,271

604,776

Energy risk management non-current assets (Note 1(c))

33,946

64,762

Other investments

1,081

1,082

Other

193,325

127,550

Total Other Assets

824,623

798,170

Total Assets

$
5,603,341

$
5,541,747

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
10
12

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities

Accounts payable $ 531,770 $ 352,450
Accounts payable to affiliated companies 65,802 30,419
Accrued taxes 111,549 116,616
Accrued interest 14,336 16,570
Notes payable and other short-term obligations (Note 4) 196,100 196,100
Notes payable to affiliated companies (Note 4) 2,915 444,801
Long-term debt due within one year (Note 4) — 100,000
Energy risk management current liabilities (Note 1(c)) 19,757 23,341
Other 37,662 33,217

Total Current Liabilities 979,891 1,313,514

Non-Current Liabilities

Long-term debt (Note 3) 1,689,389 1,105,333
Deferred income taxes 865,925 779,295
Unamortized investment tax credits 86,709 91,246
Accrued pension and other postretirement benefit costs 172,459 165,326
Energy risk management non-current liabilities (Note 1(c)) 23,063 41,773
Other 138,966 105,681

Total Non-Current Liabilities

2,976,511

2,288,654

Total Liabilities

3,956,402

3,602,168

Cumulative Preferred Stock

Not subject to mandatory redemption 20,485 20,486

Common Stock Equity

Common stock—$8.50 par value; authorized shares—120,000,000; outstanding shares—89,663,086 at September 30, 2002, and December 31, 2001 762,136 762,136
Paid-in capital 571,926 571,926
Retained earnings 471,384 408,706
Accumulated other comprehensive income (loss) (25,351 ) (5,678 )

Total Common Stock Equity

1,780,095

1,737,090

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder's Equity

$
5,756,982

$
5,359,744

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Liabilities

Accounts payable

$
241,667

$
195,812

Accounts payable to affiliated companies

40,652

146,558

Accrued taxes

159,892

159,199

Accrued interest

18,042

22,872

Notes payable and other short-term obligations (Note 5)

112,100

112,100

Notes payable to affiliated companies (Note 5)

3,260

8,947

Long-term debt due within one year

230,000

120,000

Energy risk management current liabilities (Note 1(c))

89,627

49,288

Other

37,255

37,160

Total Current Liabilities

932,495

851,936

Non-Current Liabilities

Long-term debt

1,459,760

1,569,713

Deferred income taxes

916,930

882,628

Unamortized investment tax credits

83,695

85,198

Accrued pension and other postretirement benefit costs

205,087

201,284

Energy risk management non-current liabilities (Note 1(c))

20,335

31,326

Other

84,583

88,843

Total Non-Current Liabilities

2,770,390

2,858,992

Total Liabilities

3,702,885

3,710,928

Cumulative Preferred Stock

Not subject to mandatory redemption

20,485

20,485

Common Stock Equity

Common stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares - 89,663,086 at March 31, 2003, and December 31, 2002

762,136

762,136

Paid-in capital

586,292

586,292

Retained earnings

557,595

487,652

Accumulated other comprehensive income (loss)

(26,052
)
(25,746
)
Total Common Stock Equity

1,879,971

1,810,334

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder’s Equity

$
5,603,341

$
5,541,747

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
11
13

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year to Date
September 30

2002
2001

(dollars in thousands)
(unaudited)

Operating Activities
Net income $ 202,024 $ 220,366
Items providing or (using) cash currently:
Depreciation 146,057 139,398
Deferred income taxes and investment tax credits—net 95,730 18,788
Change in net position of energy risk management activities (19,560 ) (22,587 )
Allowance for equity funds used during construction 261 (1,526 )
Regulatory assets deferrals (45,007 ) (81,869 )
Regulatory assets amortization 38,024 46,346
Accrued pension and other postretirement benefit costs 7,133 537
Changes in current assets and current liabilities:
Restricted deposits (765 ) (3,859 )
Accounts and notes receivable (199,985 ) (112,724 )
Materials, supplies, and fuel 6,576 (36,473 )
Prepayments (14,830 ) 9,250
Accounts payable 214,900 125,173
Accrued taxes and interest (7,301 ) 27,658
Other items—net (5,759 ) (16,137 )

Net cash provided by (used in) operating activities 417,498 312,341

Financing Activities

Change in short-term debt, including net affiliate notes (451,627 ) 138,531
Issuance of long-term debt 580,570 —
Redemption of long-term debt (100,000 ) —
Funds on deposit from issuance of debt securities (84,000 ) —
Retirement of preferred stock (1 ) —
Dividends on preferred stock (634 ) (634 )
Dividends on common stock (138,712 ) (214,674 )

Net cash provided by (used in) financing activities (194,404 ) (76,777 )

Investing Activities

Construction expenditures (less allowance for equity funds used during construction) (223,740 ) (234,492 )
Other Investments 98 265

Net cash provided by (used in) investing activities (223,642 ) (234,227 )

Net increase (decrease) in cash and cash equivalents

(548
)

1,337

Cash and cash equivalents at beginning of period

9,074

20,637

Cash and cash equivalents at end of period $ 8,526 $ 21,974

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:
Interest (net of amount capitalized) $ 68,749 $ 67,464
Income taxes $ 16,121 $ 55,520

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Activities

Net income

$
117,236

$
77,585

Items providing or (using) cash currently:

Depreciation

49,264

48,160

Deferred income taxes and investment tax credits - net

13,092

7,465

Cumulative effect of a change in accounting principles, net of tax

(30,938
)
—

Change in net position of energy risk management activities

1,041

(2,069
)
Allowance for equity funds used during construction

(719
)
543

Regulatory assets deferrals

(5,949
)
(11,131
)
Regulatory assets amortization

16,376

11,494

Accrued pension and other postretirement benefit costs

3,803

(307
)
Deferred costs under gas cost recovery mechanism

(38,659
)
5,955

Changes in current assets and current liabilities:

Restricted deposits

34

(764
)
Accounts and notes receivable

103,008

121,927

Materials, supplies, and fuel

27,655

33,593

Prepayments

361

535

Accounts payable

(60,051
)
(59,074
)
Accrued taxes and interest

(4,137
)
34,192

Other assets

(4,677
)
4,331

Other liabilities

(6,924
)
980

Net cash provided by (used in) operating activities

179,816

273,415

Financing Activities

Change in short-term debt, including net affiliate notes

(86,487
)
(141,171
)
Dividends on preferred stock

(211
)
(211
)
Dividends on common stock

(47,082
)
(44,787
)

Net cash provided by (used in) financing activities

(133,780
)
(186,169
)

Investing Activities

Construction expenditures (less allowance for equity funds used during construction)

(64,501
)
(80,191
)
Other investments

(1
)
(840
)

Net cash provided by (used in) investing activities

(64,502
)
(81,031
)

Net increase (decrease) in cash and cash equivalents

(18,466
)
6,215

Cash and cash equivalents at beginning of period

45,336

9,074

Cash and cash equivalents at end of period

$
26,870

$
15,289

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:

Interest (net of amount capitalized)

$
30,010

$
9,551

Income taxes

$
29,451

$
12,620

The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
12
14

PSI ENERGY, INC.
AND SUBSIDIARY COMPANY
13
15

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Quarter Ended
September 30
Year to Date
September 30

2002
2001
2002
2001

(dollars in thousands)
(unaudited)

Operating Revenues (Note 1(d))
Electric $ 776,837 $ 1,266,683 $ 1,874,109 $ 3,380,809

Operating Expenses

Fuel and purchased and exchanged power (Note 1(d)) 474,748 998,561 1,078,596 2,668,729
Operation and maintenance 128,931 105,844 386,559 301,984
Depreciation 39,826 37,492 115,954 111,487
Taxes other than income taxes 13,446 15,000 46,992 37,535

Total Operating Expenses 656,951 1,156,897 1,628,101 3,119,735

Operating Income

119,886

109,786

246,008

261,074

Miscellaneous—Net

4,434

3,837

14,155

9,397

Interest 18,782 21,580 55,862 60,117

Income Before Taxes

105,538

92,043

204,301

210,354

Income Taxes

37,895

35,589

68,861

78,251

Net Income

$
67,643

$
56,454

$
135,440

$
132,103

Preferred Dividend Requirement

648

648

1,941

1,941

Net Income Applicable to Common Stock

$
66,995

$
55,806

$
133,499

$
130,162

Net Income

$
67,643

$
56,454

$
135,440

$
132,103

Other Comprehensive Income (Loss), Net of Tax Effect

(2,716
)

(965
)

(3,684
)

(1,092
)

Comprehensive Income

$
64,927

$
55,489

$
131,756

$
131,011

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Revenues (Note 3)

Electric

$
411,688

$
366,401

Operating Expenses

Fuel and purchased and exchanged power (Note 3)

166,872

123,049

Operation and maintenance

112,385

115,079

Depreciation

42,712

37,748

Taxes other than income taxes

15,882

16,397

Total Operating Expenses

337,851

292,273

Operating Income

73,837

74,128

Miscellaneous - Net

2,158

5,351

Interest

20,115

19,291

Income Before Taxes

55,880

60,188

Income Taxes

21,659

22,105

Income Before Cumulative Effect of a Change in Accounting Principle

34,221

38,083

Cumulative effect of a change in accounting principle, net of tax (Note 1(j)(viii))

(494
)
—

Net Income

$
33,727

$
38,083

Preferred Dividend Requirement

647

647

Net Income Applicable to Common Stock

$
33,080

$
37,436

Net Income

$
33,727

$
38,083

Other Comprehensive Income (Loss), Net of Tax Effect

(630
)
(497
)

Comprehensive Income

$
33,097

$
37,586

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
14
16

PSI ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
ASSETS

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

ASSETS

Current Assets

Cash and cash equivalents $ 5,724 $ 1,587
Restricted deposits 48,153 519
Notes receivable from affiliated companies (Note 5) 33,685 444,801
Accounts receivable less accumulated provision for doubtful accounts of $5,788 at September 30, 2002, and $6,773 at December 31, 2001 (Note 5) 68,982 336,994
Accounts receivable from affiliated companies 47,015 10,470
Materials, supplies, and fuel—at average cost 122,904 87,661
Energy risk management current assets (Note 1(c)) 13,063 28,201
Prepayments and other 39,932 41,041

Total Current Assets 379,458 951,274

Property, Plant, and Equipment—at Cost

Utility plant in service 5,277,313 4,909,007
Construction work in progress 266,624 368,313

Total Utility Plant 5,543,937 5,277,320
Accumulated depreciation 2,297,678 2,216,908

Net Property, Plant, and Equipment 3,246,259 3,060,412

Other Assets

Regulatory assets 452,265 423,372
Energy risk management non-current assets (Note 1(c)) 17,832 30,164
Other investments 55,573 57,633
Other 24,919 47,927

Total Other Assets 550,589 559,096

Total Assets

$
4,176,306

$
4,570,782

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Assets

Cash and cash equivalents

$
4,095

$
2,007

Restricted deposits

20

20

Notes receivable from affiliated companies

37,548

53,755

Accounts receivable less accumulated provision for doubtful accounts of $1,927 at March 31, 2003, and $5,656 at December 31, 2002

62,504

84,819

Accounts receivable from affiliated companies

439

437

Materials, supplies, and fuel

132,959

137,292

Energy risk management current assets (Note 1(c))

8,023

8,701

Prepayments and other

34,806

44,725

Total Current Assets

280,394

331,756

Property, Plant, and Equipment - at Cost

Utility plant in service

5,734,345

5,315,410

Construction work in progress

427,357

385,051

Total Utility Plant

6,161,702

5,700,461

Accumulated depreciation

2,374,840

2,334,157

Net Property, Plant, and Equipment (Note 11)

3,786,862

3,366,304

Other Assets

Regulatory assets

420,206

417,920

Energy risk management non-current assets (Note 1(c))

12,539

16,590

Other investments

54,477

54,683

Other

42,044

35,703

Total Other Assets

529,266

524,896

Total Assets

$
4,596,522

$
4,222,956

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
15
17

PSI ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities

Accounts payable $ 161,568 $ 312,707
Accounts payable to affiliated companies 30,710 27,370
Accrued taxes 110,977 102,317
Accrued interest 15,975 23,760
Notes payable and other short-term obligations (Note 4) 82,600 148,600
Notes payable to affiliated companies (Note 4) 80,749 422,263
Long-term debt due within one year (Note 4) 979 23,000
Energy risk management current liabilities (Note 1(c)) 11,634 23,185
Other 37,741 41,695

Total Current Liabilities 532,933 1,124,897

Non-Current Liabilities

Long-term debt (Note 3) 1,371,916 1,325,089
Deferred income taxes 595,007 486,694
Unamortized investment tax credits 33,707 36,139
Accrued pension and other postretirement benefit costs 159,771 154,799
Energy risk management non-current liabilities (Note 1(c)) 18,026 41,773
Other 80,750 63,557

Total Non-Current Liabilities 2,259,177 2,108,051

Total Liabilities

2,792,110

3,232,948

Cumulative Preferred Stock

Not subject to mandatory redemption 42,343 42,347

Common Stock Equity

Common stock—without par value; $.01 stated value; authorized shares—60,000,000; outstanding shares—53,913,701 at September 30, 2002, and December 31, 2001 539 539
Paid-in capital 416,412 416,414
Retained earnings 930,181 880,129
Accumulated other comprehensive income (loss) (5,279 ) (1,595 )

Total Common Stock Equity 1,341,853 1,295,487

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder's Equity

$
4,176,306

$
4,570,782

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Liabilities

Accounts payable

$
73,155

$
113,563

Accounts payable to affiliated companies

39,150

107,364

Accrued taxes

107,385

105,960

Accrued interest

26,811

23,078

Notes payable and other short-term obligations (Note 5)

—

35,000

Notes payable to affiliated companies (Note 5)

229,865

138,055

Long-term debt due within one year

83,838

56,000

Energy risk management current liabilities (Note 1(c))

7,133

8,000

Other

22,550

22,335

Total Current Liabilities

589,887

609,355

Non-Current Liabilities

Long-term debt (Note 4)

1,699,186

1,315,984

Deferred income taxes

536,174

538,745

Unamortized investment tax credits

32,097

32,897

Accrued pension and other postretirement benefit costs

188,107

184,299

Energy risk management non-current liabilities (Note 1(c))

15,837

17,157

Other

89,647

80,879

Total Non-Current Liabilities

2,561,048

2,169,961

Total Liabilities

3,150,935

2,779,316

Cumulative Preferred Stock

Not subject to mandatory redemption

42,343

42,343

Common Stock Equity

Common stock - without par value; $.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at March 31, 2003, and December 31, 2002

539

539

Paid-in capital

426,931

426,931

Retained earnings

984,523

981,946

Accumulated other comprehensive income (loss)

(8,749
)
(8,119
)
Total Common Stock Equity

1,403,244

1,401,297

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder’s Equity

$
4,596,522

$
4,222,956

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
1618

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year to Date
September 30

2002
2001

(dollars in thousands)
(unaudited)

Operating Activities
Net income $ 135,440 $ 132,103
Items providing or (using) cash currently:
Depreciation 115,954 111,487
Deferred income taxes and investment tax credits—net 46,376 25,100
Change in net position of energy risk management activities 8,443 (22,586 )
Allowance for equity funds used during construction (9,063 ) (3,637 )
Regulatory assets deferrals (24,916 ) (18,116 )
Regulatory assets amortization 55,139 47,632
Accrued pension and other postretirement benefit costs 4,972 8,229
Changes in current assets and current liabilities:
Restricted deposits (34 ) (679 )
Accounts and notes receivable 222,369 (250,537 )
Materials, supplies, and fuel (35,243 ) (30,059 )
Prepayments (3,857 ) (1,733 )
Accounts payable (147,681 ) 204,634
Accrued taxes and interest 875 24,177
Other items—net (3,826 ) (17,117 )

Net cash provided by (used in) operating activities 364,948 208,898

Financing Activities

Change in short-term debt, including net affiliate notes 37,287 (182,980 )
Issuance of long-term debt 47,600 322,471
Redemption of long-term debt (23,000 ) (19,825 )
Funds on deposit from issuance of debt securities (47,600 ) —
Retirement of preferred stock (2 ) (1 )
Dividends on preferred stock (1,940 ) (1,941 )
Dividends on common stock (83,448 ) —

Net cash provided by (used in) financing activities (71,103 ) 117,724

Investing Activities

Construction expenditures (less allowance for equity funds used during construction) (286,610 ) (289,916 )
Other investments (3,098 ) (6,982 )

Net cash provided by (used in) investing activities (289,708 ) (296,898 )

Net increase (decrease) in cash and cash equivalents

4,137

29,724

Cash and cash equivalents at beginning of period

1,587

1,311

Cash and cash equivalents at end of period

$
5,724

$
31,035

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:
Interest (net of amount capitalized) $ 75,807 $ 69,180
Income taxes $ 13,590 $ 40,452

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Activities

Net income

$
33,727

$
38,083

Items providing or (using) cash currently:

Depreciation

42,712

37,748

Cumulative effect of a change in accounting principle, net of tax

494

—

Deferred income taxes and investment tax credits - net

(2,654
)
(8,580
)
Change in net position of energy risk management activities

(1,245
)
133

Allowance for equity funds used during construction

(2,860
)
(3,393
)
Regulatory assets deferrals

(14,639
)
(6,534
)
Regulatory assets amortization

11,590

18,482

Accrued pension and other postretirement benefit costs

3,808

2,864

Changes in current assets and current liabilities:

Restricted deposits

—

(2
)
Accounts and notes receivable

38,520

99,305

Materials, supplies, and fuel

4,333

(16,776
)
Prepayments

1,345

1,074

Accounts payable

(108,622
)
(60,867
)
Accrued taxes and interest

5,158

37,874

Other assets

7,355

534

Other liabilities

1,066

128

Net cash provided by (used in) operating activities

20,088

140,073

Financing Activities

Change in short-term debt, including net affiliate notes

56,810

24,057

Issuance of long-term debt

35,000

—

Redemption of long-term debt

—

(23,000
)
Retirement of preferred stock

—

(2
)
Dividends on preferred stock

(647
)
(647
)
Dividends on common stock

(30,503
)
(26,944
)

Net cash provided by (used in) financing activities

60,660

(26,536
)

Investing Activities

Construction expenditures (less allowance for equity funds used during construction)

(77,833
)
(104,977
)
Other investments

(827
)
(3,557
)

Net cash provided by (used in) investing activities

(78,660
)
(108,534
)

Net increase (decrease) in cash and cash equivalents

2,088

5,003

Cash and cash equivalents at beginning of period

2,007

1,587

Cash and cash equivalents at end of period

$
4,095

$
6,590

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:

Interest (net of amount capitalized)

$
20,465

$
22,819

Income taxes

$
36,000

$
6,590

Non-cash financing and investing activities:

Issuance of promissory notes to affiliated company for acquisition of assets

$
375,969

$
—

The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
17
19

THE UNION LIGHT, HEAT AND POWER COMPANY
20

THE UNION LIGHT, HEAT AND POWER COMPANY
18

~~THE UNION LIGHT, HEAT AND POWER COMPANY~~

STATEMENTS OF INCOME

Quarter Ended
September 30
Year to Date
September 30

2002
2001
2002
2001

(dollars in thousands)
(unaudited)

Operating Revenues
Electric $ 68,353 $ 63,899 $ 175,346 $ 180,761
Gas 7,364 10,008 53,584 82,778

Total Operating Revenues 75,717 73,907 228,930 263,539

Operating Expenses

Electricity purchased from parent company for resale 48,445 48,230 123,091 119,597
Gas purchased 2,732 4,802 30,932 56,038
Operation and maintenance 14,819 10,781 38,199 28,982
Depreciation 4,277 4,285 13,009 12,689
Taxes other than income taxes 1,167 1,126 3,535 3,388

Total Operating Expenses 71,440 69,224 208,766 220,694

Operating Income

4,277

4,683

20,164

42,845

Miscellaneous—Net

1,690

(87
)

(2,516
)

(700
)

Interest

1,431

1,496

4,388

4,739

Income Before Taxes

4,536

3,100

13,260

37,406

Income Taxes

1,302

1,112

4,150

10,552

Net Income $ 3,234 $ 1,988 $ 9,110 $ 26,854

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Revenues

Electric

$
54,929

$
51,857

Gas

49,384

35,204

Total Operating Revenues

104,313

87,061

Operating Expenses

Electricity purchased from parent company for resale

39,123

36,838

Gas purchased

31,500

22,889

Operation and maintenance

12,585

9,452

Depreciation

4,445

4,220

Taxes other than income taxes

1,161

1,201

Total Operating Expenses

88,814

74,600

Operating Income

15,499

12,461

Miscellaneous - Net

1,479

(5,168
)
Interest

1,502

1,505

Income Before Taxes

15,476

5,788

Income Taxes

6,070

1,904

Net Income

$
9,406

$
3,884

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
19
21

THE UNION LIGHT, HEAT AND POWER COMPANY

BALANCE SHEETS
ASSETS

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

ASSETS

Current Assets

Cash and cash equivalents $ 3,792 $ 4,099
Notes receivable from affiliate companies (Note 5) 6,303 —
Accounts receivable less accumulated provision for doubtful accounts of $56 at September 30, 2002, and $1,196 at December 31, 2001 (Note 5) 847 16,785
Accounts receivable from affiliated companies 416 2,401
Materials, supplies, and fuel—at average cost 12,506 10,835
Prepayments and other 474 300

Total Current Assets 24,338 34,420

Property, Plant, and Equipment—at Cost

Utility plant in service
Electric 256,139 248,223
Gas 204,459 197,301
Common 30,482 50,289

Total Utility Plant In Service 491,080 495,813
Construction work in progress 18,595 11,004

Total Utility Plant 509,675 506,817
Accumulated depreciation 186,232 178,567

Net Property, Plant, and Equipment 323,443 328,250

Other Assets

Regulatory assets 4,582 7,838
Other investments 73 2
Other 16,514 6,580

Total Other Assets 21,169 14,420

Total Assets

$
368,950

$
377,090

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Assets

Cash and cash equivalents

$
7,559

$
3,926

Notes receivable from affiliated companies

9,902

13,337

Accounts receivable less accumulated provision for doubtful accounts of $91 at March 31, 2003, and $84 at December 31, 2002

710

703

Accounts receivable from affiliated companies

682

1,671

Materials, supplies, and fuel

3,516

8,182

Prepayments and other

158

316

Total Current Assets

22,527

28,135

Property, Plant, and Equipment - at Cost

Utility plant in service

Electric

262,800

258,094

Gas

221,244

215,505

Common

31,629

31,679

Total Utility Plant In Service

515,673

505,278

Construction work in progress

11,482

14,745

Total Utility Plant

527,155

520,023

Accumulated depreciation

191,743

187,876

Net Property, Plant, and Equipment

335,412

332,147

Other Assets

Regulatory assets

9,678

5,134

Other

22,309

16,811

Total Other Assets

31,987

21,945

Total Assets

$
389,926

$
382,227

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
20
22

THE UNION LIGHT, HEAT AND POWER COMPANY

BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY

September 30
2002
December 31
2001

(dollars in thousands)
(unaudited)

LIABILITIES AND SHAREHOLDER'S EQUITY

Current Liabilities

Accounts payable $ 4,547 $ 7,960
Accounts payable to affiliated companies 17,950 16,156
Accrued taxes 9,267 7,051
Accrued interest 621 643
Notes payable to affiliated companies (Note 4) 1,851 26,432
Other 6,014 5,322

Total Current Liabilities 40,250 63,564

Non-Current Liabilities

Long-term debt 74,645 74,621
Deferred income taxes 29,924 28,323
Unamortized investment tax credits 3,205 3,411
Accrued pension and other postretirement benefit costs 14,615 13,198
Amounts due to customers—income taxes 7,148 7,148
Other 20,525 14,622

Total Non-Current Liabilities 150,062 141,323

Total Liabilities

190,312

204,887

Common Stock Equity

Common stock—$15.00 par value; authorized shares—1,000,000; outstanding shares—585,333 at September 30, 2002, and December 31, 2001 8,780 8,780
Paid-in capital 21,111 21,111
Retained earnings 148,755 142,320
Accumulated other comprehensive income (loss) (8 ) (8 )

Total Common Stock Equity 178,638 172,203

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder's Equity

$
368,950

$
377,090

March 31
2003

December 31
2002

(in thousands)

(unaudited)

Current Liabilities

Accounts payable

$
13,565

$
8,816

Accounts payable to affiliated companies

20,331

22,297

Accrued taxes

1,016

1,487

Accrued interest

1,217

1,226

Long-term debt due within one year

20,000

20,000

Notes payable to affiliated companies (Note 5)

4,543

14,076

Other

6,658

6,368

Total Current Liabilities

67,330

74,270

Non-Current Liabilities

Long-term debt

54,661

54,653

Deferred income taxes

47,877

43,360

Unamortized investment tax credits

3,077

3,143

Accrued pension and other postretirement benefit costs

15,891

15,620

Other

14,520

14,017

Total Non-Current Liabilities

136,026

130,793

Total Liabilities

203,356

205,063

Common Stock Equity

Common stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares - 585,333 at March 31, 2003, and December 31, 2002

8,780

8,780

Paid-in capital

23,644

23,644

Retained earnings

154,206

144,800

Accumulated other comprehensive income (loss)

(60
)
(60
)
Total Common Stock Equity

186,570

177,164

Commitments and Contingencies (Note 7)

Total Liabilities and Shareholder’s Equity

$
389,926

$
382,227

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
21
23

THE UNION LIGHT, HEAT AND POWER COMPANY

STATEMENTS OF CASH FLOWS

Year to Date
September 30

2002
2001

(dollars in thousands)
(unaudited)

Operating Activities
Net income $ 9,110 $ 26,854
Items providing or (using) cash currently:
Depreciation 13,009 12,689
Deferred income taxes and investment tax credits—net 1,395 897
Allowance for equity funds used during construction (523 ) (123 )
Regulatory assets deferrals 4,168 1,393
Regulatory assets amortization (1,064 ) 103
Accrued pension and other postretirement benefit costs 1,417 122
Changes in current assets and current liabilities:
Accounts and notes receivable 17,142 18,558
Materials, supplies, and fuel (1,671 ) (5,961 )
Prepayment (174 ) (176 )
Accounts payable (1,619 ) (25,955 )
Accrued taxes and interest 2,194 10,000
Other items—net 9,903 (8,147 )

Net cash provided by (used in) operating activities 53,287 30,254

Financing Activities

Change in short-term debt, including net affiliate notes (24,581 ) (5,968 )
Dividends on common stock (2,675 ) (4,829 )

Net cash provided by (used in) financing activities (27,256 ) (10,797 )

Investing Activities

Construction expenditures (less allowance for equity funds used during construction) (26,268 ) (19,608 )
Other investments (70 ) —

Net cash provided by (used in) investing activities (26,338 ) (19,608 )

Net increase (decrease) in cash and cash equivalents

(307
)

(151
)

Cash and cash equivalents at beginning of period

4,099

6,460

Cash and cash equivalents at end of period $ 3,792 $ 6,309

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:
Interest (net of amount capitalized) $ 4,194 $ 4,493
Income taxes $ 2,398 $ 7,461

Quarter Ended
March 31

2003

2002

(in thousands)

(unaudited)

Operating Activities

Net income

$
9,406

$
3,884

Items providing or (using) cash currently:

Depreciation

4,445

4,220

Deferred income taxes and investment tax credits - net

4,451

(727
)
Allowance for equity funds used during construction

(85
)
(47
)
Regulatory assets deferrals

(33
)
4,687

Regulatory assets amortization

(22
)
(887
)
Accrued pension and other postretirement benefit costs

271

(43
)
Deferred costs under gas cost recovery mechanism

(9,372
)
4,347

Changes in current assets and current liabilities:

Accounts and notes receivable

4,417

14,388

Materials, supplies, and fuel

4,666

7,272

Prepayments

158

150

Accounts payable

2,783

3,648

Accrued taxes and interest

(480
)
1,990

Other assets

20

224

Other liabilities

174

397

Net cash provided by (used in) operating activities

20,799

43,503

Financing Activities

Change in short-term debt, including net affiliate notes

(9,533
)
(35,978
)

Net cash provided by (used in) financing activities

(9,533
)
(35,978
)

Investing Activities

Construction expenditures (less allowance for equity funds used during construction)

(7,633
)
(7,382
)
Other investments

—

(114
)

Net cash provided by (used in) investing activities

(7,633
)
(7,496
)

Net increase (decrease) in cash and cash equivalents

3,633

29

Cash and cash equivalents at beginning of period

3,926

4,099

Cash and cash equivalents at end of period

$
7,559

$
4,128

Supplemental Disclosure of Cash Flow Information

Cash paid during the period for:

Interest (net of amount capitalized)

$
1,437

$
875

Income taxes

$
3,000

$
1,901

The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
22
24

NOTES TO FINANCIAL STATEMENTS
In this reportCinergy (which includesCinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as ~~"we"~~“we”, ~~"our"~~“our”, or ~~"us"~~“us”.
1.                        Summary of Significant Accounting Policies
(a)                                  Presentation

Our Financial Statements reflect all adjustments (which include normal, recurring adjustments) necessary in the opinion of the registrants for a fair presentation of the interim results. These statements should be read in conjunction with the Financial Statements and the notes thereto included in the registrants’ combined ~~2001~~ Form 10-K offor the ~~registrants.~~year ended December 31, 2002 (2002 10-K). Certain amounts in the ~~2001~~2002 Financial Statements have been reclassified to conform to the ~~2002~~2003 presentation.
(b)                                  Financial Derivatives

We use derivative financial instruments to ~~manage:~~
•
manage funding ~~costs;~~

•
~~exposure~~costs and exposures to fluctuations in interest ~~rates; and~~

•
~~exposure to foreign currency exchange~~ rates.
We account for derivatives under Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (Statement 133), which requires all derivatives that are not exempted to be accounted for at fair value. Changes in the ~~derivative's~~derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivatives that qualify as hedges can (a) offset related fair value changes on the hedged item in the income statement for fair value hedges; or (b) be recorded in other comprehensive income for cash flow hedges. To qualify for hedge accounting, financial instruments must be designated as a hedge (for example, an offset of ~~foreign exchange or~~ interest rate risks) at the inception of the contract and must be effective at reducing the risk associated with the hedged item. Accordingly, changes in the fair values or cash flows of instruments designated as hedges must be highly correlated with changes in the fair values or cash flows of the related hedged items.
From time to time, we may use foreign currency contracts (for example, a contract obligating one party to buy, and the other to sell, a specified quantity of a foreign currency for a fixed price at a future date) and currency swaps (for example, a contract whereby two parties exchange principal and interest cash flows denominated in different currencies) to hedge foreign currency denominated purchase and sale commitments (cash flow hedges) and certain of our net investments in foreign operations (net investment hedges) against currency exchange rate fluctuations. Reclassification of unrealized gains or losses on foreign currency cash flow hedges from other comprehensive income occurs when the underlying hedged item is recorded in income.
We ~~also~~ use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for floating-interest rate cash flows) and treasury locks (an agreement ~~to exchange cash flows based~~that fixes the yield or price on a specific treasury security for a specific period, which we sometimes use in connection with the ~~movement in the underlying treasury benchmark over a specified period~~issuance of ~~time)~~fixed rate debt). ~~Effective with our adoption of Statement 133 in the first quarter of 2001, we began accounting~~We account for ~~all~~such derivatives ~~(including interest rate swaps and treasury locks) using~~at fair value, ~~accounting,~~ and we assess the effectiveness of any interest rate swaps and/or treasury locks used in hedging activities.
At ~~September 30, 2002,~~March 31, 2003, the ineffectiveness of instruments that we have classified as cash flow hedges of variable-rate debt instruments was not material. Reclassification of unrealized gains or losses on cash flow hedges of debt instruments fromAccumulated other comprehensive income (loss) occurs as interest is accrued on the debt instrument. We currently estimate that on an after-tax basis, $4$5 million of
23

unrealized losses will be reclassified as a charge toInterest during
25
~~Interest~~
~~during~~ the twelve-month period ending ~~September 30, 2003.~~March 31, 2004. See ~~Note 1(d)~~(j)(iviv) below for further discussion of Statement 133.
(c)                                  Energy Marketing and Trading

We market and trade electricity, natural gas, coal, and other energy-related products. We designate derivative transactions as ~~accrual~~trading or ~~trading~~non-trading at the time they are ~~originated.~~originated in accordance with Emerging Issues Task Force (EITF) Issue 02-3, Issues Involved inAccounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3). Derivatives are classified as ~~accrual~~non-trading only when we ~~(a)~~ have the intent and projected ability to fulfill substantially all obligations from company-owned assets, and (b) meet the requirements to consider the contract a normal purchase or sale under Statement 133 (if a derivative), or meet the requirements to consider the contract non-trading under Emerging Issues Task Force (EITF) 98-10,~~Accounting for Contracts Involved in Energy Trading and Risk Management Activities~~ ~~(EITF 98-10) (if not a derivative under Statement 133).~~assets. Such classification is generally limited to the sale of generation to third parties when it is not required to meet native load requirements (end-use customers within our public utility ~~companies'~~companies’ franchise service territory). All other energy ~~contracts~~derivatives (excluding electric, coal, and gas purchase contracts for use in serving our native load requirements) are classified as trading. Gas trading is comprised of transactions for which gas is physically delivered to a customer (physical gas trading), as well as transactions that are financial in nature for which delivery rarely occurs (financial gas trading). SinceCinergy owns no gas production and has limited transmission capabilities, all gas transactions (other than procurement and sale of gas to The Cincinnati Gas & Electric Company (CG&E) and to The Union Light, Heat and Power Company (ULH&P) retail customers) are considered trading whether physical or financial. Certain gas and coal contracts do not meet the definition of a derivative and, therefore, are not required to be classified as trading or non-trading.
We account for non-trading derivatives and non-derivative energy contracts on the accrual ~~transactions by recognizing revenues~~basis of accounting (accrual contracts). Non-trading derivatives are accounted for as accrual only if the contract qualifies for the normal purchases and ~~costs when the underlying commodity is delivered and~~sales scope exception in Statement 133. We account for all trading ~~transactions~~derivatives using the fair value method of accounting. Under the fair value method of accounting, unrealized trading ~~transactions~~derivatives are shown at fair value in our Balance Sheets asEnergy risk management assets and ~~and~~Energy risk management liabilities. All changes in fair value of such contracts are reflected as gains or losses in our Statements of Income. In October 2002, the EITF reached a consensus in EITF 02-3 to rescind EITF Issue ~~02-3~~98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF ~~02-3) to rescind EITF 98-10.~~98-10). This decision ~~will require~~required that non-derivative contracts ~~currently~~previously accounted for at fair value be accounted for on an accrual basis, ~~in the future.~~beginning January 1, 2003. See ~~Note 1(d)~~(j)(ii) below for further discussion.
        ~~We reflect unrealized gains and losses, resulting from changes in fair value, on a net basis in~~~~Operating Revenues~~~~. For physical gas trading and for all power trading,~~In 2003, we ~~recognize both revenues and costs on a gross basis in~~~~Operating Revenues~~ ~~and in~~~~Fuel and purchased and exchanged power~~ ~~and~~~~Gas purchased~~~~, respectively, when transactions are settled. For financial gas trading, realized gains and losses are recorded on a net basis in~~~~Operating Revenues~~ ~~when transactions are settled~~. ~~In June 2002, the EITF reached a consensus requiring~~began reflecting realized and unrealized gains and losses on trading derivatives on a net basis in Operating Revenues pursuant to the requirements of EITF 02-3, regardless of whether the transactions were settled physically. Prior to 2003, the realized results for trading contracts that were physical in nature were presented as either (a) Operating Revenues,if sales contractsor (b) Fuel and purchased and exchanged power expense or Gas purchased expense, if purchase contracts. The presentation for 2002 has been reclassified to conform to the new presentation. Non-trading derivatives, as well as substantially all energy ~~trading~~marketing contracts ~~to be~~that are not derivatives, are presented ~~net~~on a gross basis inOperating Revenues or ~~, beginning with the third quarter of 2002,~~Fuel and ~~reclassification of all periods presented. However, this conclusion was rescinded in October 2002,~~purchased and ~~was replaced with a new requirement to present all gains and losses on energy trading derivatives net beginning in 2003. See~~exchanged power expense. (For more information see Note ~~1(d)(~~i~~) below for further discussion.~~3).

26

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

•
least-cost alternative;
24
•
native load requirements; and

•
extreme weather.

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

We value ~~contracts in the~~ trading ~~portfolio~~derivatives using end-of-the-period fair values, utilizing the following factors (as applicable):
•
closing exchange prices (that is, closing prices for standardized electricity and natural gas products traded on an organized exchange, such as the New York Mercantile Exchange);

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

•
model pricing (which considers time value and historical volatility factors of electricity and natural gas).
(d)                                  ~~Accounting Changes~~Inventory
~~(i)    Energy Trading~~
        ~~The EITF has been discussing several issues related~~Prior to ~~the accounting and disclosure of energy~~January 1, 2003, natural gas inventory for our domestic gas trading activities under EITF 98-10. In June 2002, the EITF reached a consensus in EITF 02-3 requiring all realized and unrealized gains and losses on energy trading contracts be presented net in the income statement, whether or not settled physically. However, the EITF rescinded this consensus in October 2002 and replaced it with a requirement to present all gains and losses on energy trading derivatives on a net basis beginning in 2003. In addition, certain non-derivative contracts used in our trading activities would have been required to be presented net under the June 2002 consensus. Under the new consensus, these contracts will likely continue to be presented gross. Since most of our energy trading activities involve derivatives, we believe this new consensus will not have a substantially different impact than the June 2002 consensus, other than deferring the ultimate implementation date. We continue to expect substantial reductions in~~Operating Revenues, Fuel and purchased and exchanged power~~ ~~expense, and~~~~Gas purchased~~ ~~expense as a result of adopting net reporting. However,~~~~Operating Income~~ ~~and~~~~Net Income~~ ~~will not be affected by this change.~~~~Operating Revenues~~ ~~for~~operation, Cinergy,~~CG&E, and PSI Energy, Inc. (PSI), under the EITF's June 2002 consensus regarding net presentation, would have been as follows:~~

September 30, 2002

Quarter Ended
Year to Date

(in millions)

Cinergy(1) $ 1,098 $ 2,986
CG&Eand subsidiaries 526 1,566
PSI 472 1,222
~~(1)~~
~~The results ofCinergyalso include amounts related to non-registrants.~~
        ~~In October 2002, the EITF reached a consensus to rescind EITF 98-10. All energy trading contracts that do not qualify as a derivative will no longer be~~ Marketing & Trading, LP (Marketing & Trading) was accounted for at fair value. ~~Instead, accrual~~All other inventory was accounted for at the lower of cost or market, cost being determined through the weighted average method. Effective January 1, 2003, accounting ~~will be used. The consensus is immediately effective~~ for ~~all new contracts executed after October 25, 2002, and will require~~Marketing & Trading’s gas inventory was adjusted to the lower of cost or market method with a cumulative effect adjustment, ~~to income after tax in~~as required by EITF 02-3. See (j)(i) below for additional discussion of the ~~first quarter~~impacts of ~~2003 for all contracts executed prior to October 25, 2002. The magnitude of this adjustment will depend on the fair value as of January 1, 2003, of energy trading contracts meeting the criteria~~
25

~~outlined above.Cinergy~~ ~~has begun reviewing the various contracts to determine the effect of this change.~~adopting EITF 02-3.
During the October 2002 meeting, the EITF also rescinded a prior consensus reached in the June 2002 meeting regarding new disclosures for energy trading activities. In addition, the EITF elected not to provide guidance at this time on the recognition of inception gains on energy trading transactions. However, the decision to rescind EITF 98-10 will eliminate the recognition of inception gains on contracts that do not meet the definition of a derivative since such contracts will be accounted for on an accrual basis.
(e)~~(ii)    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. Statement 142 requires that goodwill be~~are not amortized. Goodwill is assessed for impairment ~~upon adoption and at least~~ annually, ~~thereafter~~or when circumstances indicate that the fair value of a reporting unit has declined significantly, by applying a fair-value-based ~~test, as opposed to the undiscounted cash flow test applied under prior accounting standards.~~test. This test ~~must be~~is applied at the ~~"reporting unit"~~“reporting unit” level, which is not ~~permitted to be~~ broader than the current business segments discussed in Note ~~9. Under Statement 142, an acquired~~8. Acquired intangible ~~asset should be~~assets are separately recognized if the benefit of the intangible asset is
27

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.
(f)                                    Impairment of Long-lived Assets
We ~~began applying Statement 141~~evaluate long-lived assets for impairment when events or changes in the third quarter of 2001 and Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill, which began in the first quarter of 2002, is not material to our financial position or results of operations. We have identified the reporting units for~~Cinergy~~ and finalized the initial transition impairment test. Based on the result of this test, the transition impact of applying Statement 142 is not material to our financial position or results of operations. We will continue to perform goodwill impairment tests annually, as required by Statement 142, or when circumstances indicate that the carrying value of such assets may not be recoverable. So long as an asset or group of assets is not held for sale, the determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a ~~reporting unit has declined significantly.~~provision for an impairment loss if the carrying value is greater than the fair value. Once assets are classified as held for sale, the comparison of undiscounted cash flows to carrying value is disregarded and an impairment loss is recognized for any amount by which the carrying value exceeds the fair value of the assets.

Cinergy has classified certain non-core investments as held for sale. The results of operations for these investments are presented as ~~(iii)    Asset Retirement Obligations~~Discontinued operations, net of tax in our financial statements.
(g)                                 Stock-Based Compensation

        ~~In July 2001,~~We have historically accounted for our stock-based compensation plans using the ~~FASB issued~~intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees (APB 25). Effective January 1, 2003, Cinergy adopted prospectively the fair value recognition provisions of Statement of Financial Accounting Standards No. ~~143,~~123, Accounting for Stock-Based Compensation (Statement 123), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure (Statement 148), for all employee awards granted or modified after January 1, 2003. The following table illustrates the effect on our Net Income and Earnings Per Common Share (EPS) if the fair value based method had been applied to all outstanding and unvested awards in each period.
28

Quarter Ended March 31

(in millions, except per share
amounts)

2003

2002

Net income, as reported

$
166

$
85

Add:
Stock-based employee compensation expense included in reported net income, net of related tax effects.

4

3

Deduct:
Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects.

5

3

Pro-forma net income

$
165

$
85

EPS - as reported

$
0.96

$
0.52

EPS - pro-forma

$
0.95

$
0.52

EPS Assuming Dilution - as reported

$
0.95

$
0.52

EPS Assuming Dilution - pro-forma

$
0.94

$
0.52

The pro-forma amounts reflect certain assumptions used in estimating fair values. As a result of this and other factors which may effect the timing and amounts of stock-based compensation, the pro-forma effect on Net Income and EPS may not be representative of future periods.
(h)                                 Asset Retirement Obligations ~~(Statement 143). Statement 143 requires~~
We recognize the fair value ~~recognition~~ of legal obligations ~~to retire~~associated with the retirement or removal of long-lived assets at the time the obligations are incurred. The initial recognition of this liability ~~will be~~is accompanied by a corresponding increase in property, plant, and equipment. Subsequent to the initial recognition, the liability ~~will be~~is 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~~is 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 have formed an implementation team and are continuing to analyze the impact of this statement. However, at this time, we have not determined whether its implementation will be material to our financial position or results of operations.
~~(iv)    Derivatives~~
        ~~During 1998, the FASB issued Statement 133. This standard was effective forCinergy~~ ~~beginning in 2001, and requires us to record derivative instruments, which are not exempt under certain provisions~~
26

of Statement 133, as assets or liabilities, measured at fair value (i.e., mark-to-market). Our financial statements reflect the adoption of Statement 133 in the first quarter of 2001. Since many of our derivatives were previously required to use fair value accounting, the effects of implementation were not material.
        Our adoption did not reflect the potential impact of applying fair value accounting to selected electricity options and capacity contracts. We had not historically accounted for these instruments at fair value because they were intended as either hedges of peak period exposure or sales contracts served with physical generation, neither of which were considered trading activities. At adoption, we classified these contracts as normal purchases or sales based on our interpretation of Statement 133 and in the absence of definitive guidance on such contracts. In June 2001, the FASB staff issued guidance on the application of the normal purchases and sales exemption to electricity contracts containing characteristics of options. While many of the criteria in this guidance are consistent with the existing guidance in Statement 133, some criteria were added. We adopted the new guidance in the third quarter of 2001, and the effects of implementation for these contracts were not material to our financial position or results of operations. We will continue to apply this guidance to any new electricity contracts that meet the definition of a derivative.
        In December 2001, the FASB staff revised the current guidance to make the evaluation of whether electricity contracts qualify as normal purchases and sales more qualitative than quantitative. This new guidance uses several factors to distinguish between capacity contracts, which qualify for the normal purchases and sales exemption, and options, which do not. These factors include deal tenor, pricing structure, specification of the source of power, and various other factors. We adopted this guidance in the third quarter of 2002, and its impact was not material to our financial position or results of operations.
        In October 2001, the FASB staff released final guidance on the applicability of the normal purchases and sales exemption to contracts that contain a minimum quantity (a forward component) and flexibility to take additional quantity at a fixed price (an option component). While this guidance was issued primarily to address optionality in fuel supply contracts, it applies to all derivatives (subject to certain exceptions for capacity contracts in electricity discussed in the previous paragraphs). This guidance concludes that such contracts are not eligible for the normal purchases and sales exemption due to the existence of optionality in the contract. We adopted this guidance in the second quarter of 2002, consistent with the transition provisions.~~Cinergy~~ has certain contracts that contain fixed-price optionality, primarily coal contracts, which we reviewed to determine the impact of this new guidance. Due to a lack of liquidity with respect to coal markets in our region, we determined that our coal contracts do not meet the net settlement criteria of Statement 133 and thus do not qualify as derivatives. Given these conclusions, the results of applying this new guidance were not material to our financial position or results of operations.
        In May 2002, the FASB issued an exposure draft that would amend Statement 133 to incorporate certain implementation conclusions reached by the FASB staff. The proposed effective date would be the first quarter of 2003. We do not ~~believe~~recognize liabilities for asset retirement obligations for which the ~~amendment as~~fair value cannot be reasonably estimated. CG&E and PSI Energy, Inc. (PSI) have asset retirement obligations associated with river structures at certain generating stations. However, the retirement date for these river structures cannot be determined; therefore, the fair value of the associated liability currently ~~drafted, will have a material effect on~~cannot be estimated and no amounts are recognized in the financial statements herein.
Effective with our ~~financial position or results~~adoption of ~~operations.~~
~~(v)    Asset Impairment~~
        ~~In August 2001, the FASB issued~~ Statement of Financial Accounting Standards No. ~~144,~~143, Accounting for Asset Retirement Obligations (Statement 143), on January 1, 2003, we do not accrue the ~~Impairment~~estimated cost of ~~Long-Lived Assets~~ ~~(Statement 144). Statement 144 addresses accounting and reporting~~removal when no obligation exists for any of our non-regulated assets, even if removal of the ~~impairment or disposal of long-lived assets. Statement 144 was effective beginning with the first quarter of 2002. The impact of implementation on~~asset is likely. For our ~~financial position or results of operations was not material.~~rate-regulated assets where our tariff rate
27
29

~~(vi)    Exit Activities~~
        ~~In August 2002, the FASB issued~~includes a cost of removal component, we recognize a charge for estimated cost of removal under Statement of Financial Accounting Standards No. ~~146,~~71, Accounting for ~~Costs Associated with Exit or Disposal Activities~~the Effects of Certain Types of Regulation (Statement 71), as part of depreciation. This includes most assets for PSI, ~~(Statement 146)~~CG&E, except for its generating assets, and ULH&P. ~~Statement 146 addresses accounting and reporting~~See (j)(iii) for the recognition of exit costs, including, but not limited to, one-time employee benefit terminations, contract cancellations, and facility consolidations. This statement requires that such costs be recognized only when they meet the definition of a liability under generally accepted accounting principles. Certain of the costs discussed in Note 8 were accrued under previous accounting standards that Statement 146 will supersede when it becomes effective. However, Statement 146 applies only to exit activities initiated in 2003 and after. All costs recorded through September 30, 2002, are unaffected by this pronouncement. The impact of implementation on our financial position or results of operations is not expected to be material.additional information.
~~(vii)    Accounting for Stock-Based Compensation~~
        ~~As discussed in the 2001 Form 10-K, we have historically accounted for our stock-based compensation plans under Accounting Principles Board (APB) Opinion No. 25,~~(i)~~Accounting for Stock Issued to Employees~~ ~~(APB 25). In July 2002,Cinergy~~ ~~announced that it will adopt Statement of Financial Accounting Standards No. 123,~~~~Accounting for Stock-Based Compensation~~ (Statement 123) effective with the next grant cycle (January 2003), and will begin measuring the compensation cost of stock-based awards under the fair value method. On October 4, 2002, the FASB issued an Exposure Draft of a Proposed Statement of Financial Accounting Standards,~~Accounting for Stock-Based Compensation-Transition and Disclosure~~ ~~that would amend Statement 123 and APB Opinion No. 28,~~~~Interim Financial Reporting.~~ This proposed statement provides alternative methods of transition to Statement 123 and more expanded disclosures about the method of accounting for stock-based employee compensation and the effect of the method used on reported results in both annual and interim financial statements.~~Cinergy~~ intends to adopt the transition provisions that require expensing options prospectively in the year of adoption consistent with the original pronouncement. Existing awards will continue to follow the intrinsic value method prescribed by APB 25. The anticipated impact of adoption on our financial position and results of operations, assuming award levels and fair values similar to past years, is not expected to be material. This change will primarily impact the accounting for stock options related to the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan, Cinergy Corp. Stock Option Plan, and Cinergy Corp. Employee Stock Purchase and Savings Plan.
~~(e)~~                                    Operating Revenues

Our operating companies recordOperating revenues for electric and gas service when delivered 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"~~“unbilled revenue” and is a widely recognized and accepted practice for utilities. In making our estimates of unbilled revenue, we use complex systems that consider various factors, including weather, in our calculation of retail customer consumption at the end of each month. Given the use of these systems and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when revenue is subsequently billed.
The amount of unbilled revenues forCinergy,CG&E, PSI, andULH&P~~PSI~~ as of March 31, 2003 and 2002, were ~~$124~~as follows:

2003

2002

(in millions)

Cinergy

$
119

$
123

CG&E and subsidiaries

67

68

PSI

52

55

ULH&P

12

11

(j)                                    Accounting Changes
(i)                    Energy Trading
In October 2002, the EITF reached consensus in EITF 02-3, to (a) rescind EITF 98-10, (b) generally preclude the recognition of gains at the inception of new derivatives, and (c) require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically. The consensus to rescind EITF 98-10 required most energy trading contracts that do not qualify as derivatives to be accounted for on an accrual basis, rather than at fair value. The consensus was immediately effective for all new contracts executed after October 25, 2002, and required a cumulative effect adjustment to income, net of tax, on January 1, 2003, for all contracts executed on or prior to October 25, 2002. The cumulative effect adjustment, on a net of tax basis, was a loss of $13 million ~~$63~~for Cinergy and $8 million ~~(including~~for CG&E, which includes primarily the impact of certain coal contracts, gas inventory, and certain gas contracts, which were all accounted for at fair value. We expect the ongoing impact of this rescission to have the largest impact on our gas trading business, which uses financial contracts, physical contracts, and gas inventory to take advantage of various arbitrage opportunities. Prior to the rescission of EITF 98-10, all of these activities were
30

accounted for at fair value. Under the revised guidance, only certain items are accounted for at fair value, which could increase volatility in reported results of operations.
The consensus to require all gains and losses on energy trading derivatives to be presented net in the Statements of Income was effective January 1, 2003, and required reclassification for all periods presented. This resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense. However, Operating Income and Net Income were not affected by this change. See Note 3 for additional information.
(ii)                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. Statement 142 requires that goodwill be assessed for impairment upon adoption (transition impairment test) and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under prior accounting standards. This test must be applied at the “reporting unit” level, which is not permitted to be broader than the current business segments discussed in Note 8. Under Statement 142, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer’s intent to do so.
We began applying Statement 141 in the third quarter of 2001 and Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill, which began in the first quarter of 2002, was not material to our financial position or results of operations. We finalized our transition impairment test in the fourth quarter of 2002 and have recognized a non-cash impairment charge of approximately $11 million (net of tax) for goodwill related to certain of our international assets. This amount is reflected in Cinergy’s Statements of Income as a Cumulative effect of a change in accounting principles, net of tax. While Statement 142 did not require the initial transition impairment test to be completed until December 31, 2002, it required a transition impairment charge to be reflected as of January 1, 2002. We will continue to perform goodwill impairment tests annually, as required by Statement 142, or when circumstances indicate that the fair value of a reporting unit has declined significantly.
(iii)            Asset Retirement Obligations
In July 2001, the FASB issued Statement 143, which requires fair value recognition beginning January 1, 2003, of legal obligations associated with the retirement or removal of long-lived assets, at the time the obligations are incurred. The initial recognition of this liability is accompanied by a corresponding increase in property, plant, and equipment. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected cash flows of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and
31

for accretion of the liability due to the passage of time (recognized as an operation expense). Additional depreciation expense is recorded prospectively for any property, plant, and equipment increases.
We previously accrued costs of removal on many long-lived assets through depreciation expense if we believed removal of the assets at the end of their useful life was likely. The Securities and Exchange Commission (SEC) staff has interpreted Statement 143 to disallow the accrual of estimated cost of removal when no obligation exists under Statement 143, even if removal of the asset is likely. As a result, all accumulated cost of removal for our non-regulated assets, primarily CG&E’s generation assets, was reversed upon adoption. However, accrued cost of removal for rate-regulated assets is recoverable through our rates as a component of depreciation. Since Statement 71 applies, accruing estimated cost of removal continues to be acceptable. As a result, accumulated cost of removal was not reversed upon adoption of Statement 143 for the rate-regulated assets of PSI, CG&E, and ULH&P.
)We adopted Statement 143 on January 1, 2003, and Cinergy and CG&E both recognized a gain of $39 million (net of tax) for the cumulative effect of this change in accounting principle. Substantially all of this adjustment reflects the reversal of previously accrued cost of removal for CG&E’s generating assets, which do not apply Statement 71. Accumulated Depreciation at adoption includes $316 million, $25 million, and $146 million of accumulated cost of removal related to PSI’s, ULH&P’s, and ~~$61 million,~~CG&E’s utility plant in service assets, respectively, ~~at September 30, 2002.~~which represent regulatory liabilities and were not included as part of the cumulative effect adjustment. The increases in assets and liabilities from adopting Statement 143 were not material to our financial position.
Pro-forma results as if Statement 143 was applied retroactively for the years ended December 31, 2002, 2001, and 2000 and the quarter ended March 31, 2002 are not materially different from reported results.
~~(f)~~(iv)              ~~Related Party Transactions~~Derivatives

        ~~To supplement native load~~During 1998, the FASB issued Statement 133. This standard was effective for Cinergy beginning in 2001, and requires us to record derivative instruments, which are not exempt under certain provisions of Statement 133, as assets or liabilities, measured at fair value (i.e., mark-to-market). Our financial statements reflect the adoption of Statement 133 in the first quarter of 2001. Since many of our derivatives were previously required to use fair value accounting, the effects of implementation were not material.
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149). Statement 149 primarily amends Statement 133 to incorporate implementation conclusions previously cleared by the FASB staff, to clarify the definition of a derivative and to require derivative instruments that include up-front cash payments to be classified as a financing activity in the statement of cash flows. Implementation issues that have been previously cleared by the FASB staff will continue to be applied in accordance with their respective effective dates at the time that they were cleared and new guidance has varying implementation provisions, none of
32

which will apply until the third quarter of 2003. We have begun to evaluate the impacts of adopting Statement 149 but are currently unable to determine whether the impacts will be material to our results of operations or financial position.
There has been recent discussion about the use of broad market indices (e.g., consumer price index) in power sales contracts and whether such indices disqualify capacity contracts that otherwise qualify for the use of the normal purchases and sales scope exception. In April 2003, the FASB staff provided some proposed clarifications on this issue. This guidance is currently open for public comment. We expect this guidance to be finalized sometime during the summer of 2003, with a proposed effective date for Cinergy of October 1, 2003. We are unable to determine whether the impact of this recent interpretation would be material to our results of operations or financial position until the FASB staff finalizes its guidance.
(v)                  Exit Activities
In August 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities (Statement 146). Statement 146 addresses accounting and reporting for the recognition of exit costs, including, but not limited to, one-time employee benefit terminations, contract cancellations, and facility consolidations. This statement requires that such costs be recognized only when they meet the definition of a liability under generally accepted accounting principles. However, Statement 146 applies only to exit activities initiated in 2003 and after. All costs recorded through December 31, 2002, were unaffected by this pronouncement. The impact of adoption on our financial position and results of operations was not material.
(vi)              Accounting for Stock-Based Compensation
We have historically accounted for our stock-based compensation plans under APB 25. In July 2002, Cinergy announced that it would adopt Statement 123 for all employee awards granted or modified after January 1, 2003, and would begin measuring the compensation cost of stock-based awards under the fair value method. In December 2002, the FASB issued Statement 148, which amends Statement 123 and APB Opinion No. 28, Interim Financial Reporting. Statement 148 provides alternative methods of transition to Statement 123 and more expanded disclosures about the method of accounting for stock-based employee compensation and the effect of the method used on reported results in both annual and interim financial statements. Cinergy adopted Statement 148 on January 1, 2003, and has adopted the transition provisions that require expensing options prospectively beginning in the year of adoption. Awards granted prior to January 1, 2003, will continue to follow the intrinsic value method prescribed by APB 25. The impact of adoption on our financial position and results of operations, assuming award levels and fair values similar to past years, is not material. This change will primarily impact the accounting for stock options and other performance based awards related to the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan, the Cinergy Corp. Employee Stock Purchase and Savings Plan, and the Cinergy Corp. Stock Option Plan.
33

(vii)          Consolidation of Special Purpose Entities (SPE)
The FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities in January 2003. This interpretation will significantly change the consolidation requirements for ~~2002,CG&E~~SPEs. We have begun reviewing the impact of this interpretation but have not yet concluded whether consolidation of certain SPEs will be required. There are two SPEs for which consolidation may be required. These SPEs have individual power sale agreements to an unrelated third party for approximately 45 megawatts (MW) of capacity, ending in 2009, and~~PSI~~ 35 MW of capacity, ending in 2016. In addition, the SPEs have ~~agreed to~~individual power purchase ~~peaking power from~~agreements with Cinergy Capital & Trading, Inc. (Capital & Trading)~~, an indirect wholly-owned subsidiary~~ to supply the power. Capital & Trading also provides various services, including certain credit support facilities.
Cinergy’s quantifiable exposure to loss as a result of~~Cinergy Corp., pursuant to the terms of a wholesale market-based tariff. For the nine months ended September 30, 2002, payments under~~ involvement with these ~~contracts totaled approximately $20 million forCG&E~~ ~~and~~two SPEs is $28 million, ~~forPSI~~.which includes investments in these entities of $3 million and exposure under the capped credit facilities of approximately $25 million. There is also a non-capped facility, but it can only be called upon in the event the SPE breaches representations, violates covenants, or other unlikely events.
28

~~(g)~~    ~~Foreign Currency~~
        ~~We translate the~~If appropriate, consolidation of all assets and liabilities of ~~foreign subsidiaries, whose functional currency (generally,~~these two SPEs, at their carrying values, will be required in the ~~local currency~~third quarter of 2003. Approximately $225 million of non-recourse debt would be included in Cinergy’s Balance Sheet upon initial consolidation. However, the ~~country~~impact on results of operations would be expected to be immaterial.
Cinergy believes that its accounts receivable sale facility, as discussed in ~~which~~ the ~~subsidiary is located) is not the United States (U.S.) dollar, using the appropriate exchange rate as~~2002 10-K, would remain unconsolidated since it involves transfers of ~~the end of the month. 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)~~,financial assets to a qualifying SPE, which is exempted from consolidation by Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and this interpretation.
34

(viii)      Cumulative effect of a ~~component~~change in accounting principles, net of ~~common stock equity.~~tax
The following table summarizes the various cumulative effect adjustments (net of tax) discussed above for the rescission of EITF 98-10, and the adoption of Statement 142 and Statement 143:

Quarter Ended March 31

2003

2002

(in thousands)

Cinergy(1)

Goodwill impairment (Statement 142 adoption)

$
—

$
(10,899
)
Rescission of EITF 98-10 (EITF 02-3 adoption)

(12,512
)
—

Asset retirement obligation (Statement 143 adoption)

38,974

—

26,462

(10,899
)

CG&E

Rescission of EITF 98-10 (EITF 02-3 adoption)

(8,239
)
—

Asset retirement obligation (Statement 143 adoption)

39,177

—

30,938

—

PSI

Rescission of EITF 98-10 (EITF 02-3 adoption)

(494
)
—

(494
)
—

(1)
The results of Cinergy also include amounts related to non-registrants.
2.                        Common Stock
~~2.    Common Stock~~
        ~~In February 2002,Cinergy Corp.~~ ~~sold 6.5 million shares of its common stock with net proceeds of approximately $200 million. The net proceeds from the transaction were used to repay a portion of short-term debt ofCinergy Corp.~~
As discussed in the ~~2001 Form~~2002 10-K, ~~it is~~Cinergy currently~~Cinergy's~~ ~~policy to issue~~ issues newCinergy Corp. common stock shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. During the first quarter of 2003, Cinergy ~~has~~ issued ~~2.4~~approximately 1.5 million shares under these ~~plans~~plans.
On January 15, 2003, Cinergy Corp. filed a registration statement with the SEC with respect to the issuance of common stock, preferred stock, and other securities in ~~2002.~~an aggregate offering amount of $750 million. On February 5, 2003, Cinergy sold 5.7 million shares of common stock of Cinergy Corp. with net proceeds of approximately $175 million under this registration statement. The net proceeds from the transaction were used to reduce short-term debt of Cinergy Corp. and for other general corporate purposes.
3.                        Change in Method of Revenue Presentation for Energy Trading Derivatives
In October 2002, the EITF reached consensus in EITF 02-3 to require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically. This consensus was effective beginning January 1, 2003, and required reclassification for the quarter ended March 31, 2002.
35

We have reclassified amounts in our Statements of Income in accordance with EITF 02-3. The table below presents the effect of the change in revenue presentation on Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense for the quarter ended March 31, 2002. Operating Income and Net Income were not affected by this change.

Cinergy(1)

CG&E and subsidiaries

PSI

(in thousands)

Electric Operating Revenues as previously reported

$
1,283,424

$
635,886

$
629,844

Adjustment for effect of EITF 02-3 implementation

(492,921
)
(237,767
)
(263,443
)
Other(2)

(11,127
)
—

—

Electric Operating Revenues as adjusted

779,376

398,119

366,401

Gas Operating Revenues as previously reported

903,261

179,609

—

Adjustment for effect of EITF 02-3 implementation

(713,197
)
—

—

Gas Operating Revenues as adjusted

190,064

179,609

—

Fuel and purchased and exchanged power expense as previously reported

727,547

345,015

386,492

Adjustment for effect of EITF 02-3 implementation

(492,921
)
(237,767
)
(263,443
)
Other(2)

(5,336
)
—

—

Fuel and purchased and exchanged power expense as adjusted

229,290

107,248

123,049

Gas purchased expense as previously reported

823,077

107,968

—

Adjustment for effect of EITF 02-3 implementation

(713,197
)
—

—

Gas purchased expense as adjusted

109,880

107,968

—

(1)
The results of Cinergy also include amounts related to non-registrants and include the elimination of certain intercompany amounts.
(2)
Item represents amounts reclassified to Discontinued operations, net of tax.
4.                                      Long-term Debt
In October 2002, PSI filed a petition with the Indiana Utility Regulatory Commission (IURC) for the purpose of securing authorization and approval to issue two subordinated promissory notes to Cinergy Corp. for the acquisition of the Butler County, Ohio and Henry County, Indiana peaking plants. In January ~~2002,~~2003, the IURC granted this request, and in February 2003, PSI ~~paid at maturity $23 million~~ issued the notes. One subordinated note was for the principal amount of ~~Medium-Term Notes, Series A. The securities were not replaced by new issues of long-term debt.~~
        ~~In May 2002,~~$200 million with an indirect, wholly-owned subsidiary of Cinergy Global Resources, Inc. entered into a senior term loan and a junior term loan, borrowing $13.1 million and $7 million, respectively. Each of the loans have periodic principal reduction payments, with the senior loan having a final maturity of March 15, 2019, and the junior loan having a final maturity of March 15, 2012. In July 2002, borrowings under the senior and junior loans were increased to $13.8 and $7.1 million, respectively. At that time, the annual interest rate of 6.302% and will mature on ~~the senior loan~~April 15, 2004. The second subordinated note was ~~fixed at 6.97%~~for $176 million with an annual interest rate of 6.403% and ~~the junior loan was fixed at 6.35%. Previously, interest~~will mature on ~~the loans was at a variable rate.~~
        On September 1, ~~2002,CG&E~~ ~~paid at maturity $100 million principal amount of First Mortgage Bonds, 7~~¹/4~~% Series.~~2004.
36
        ~~On September 10, 2002,~~
~~CG&E~~ borrowed the proceeds from the issuance by the Ohio Air Quality Development Authority of $84 million principal amount of its State of Ohio Air Quality Development Revenue Refunding Bonds 2002 Series A, due September 1, 2037. The issuance consists of two $42 million tranches, with the interest rate on one tranche being reset every 35 days by auction and the interest rate on the other tranche being reset every 7 days by auction. The initial interest rates for the 35-day and 7-day tranches were 1.40% and 1.35%, respectively. Proceeds from the borrowing were used on October 7, 2002 to redeem, at par, two $42 million Series 1985 A&B Air Quality Development Authority State of Ohio Customized Purchase Revenue Bonds, due December 1, 2015. The redeemed bonds had been classified in~~Notes payable and other short-term obligations~~.
On ~~September 12, 2002,~~March 7, 2003, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of ~~$23~~$35 million ~~principal amount~~ of its Environmental Refunding Revenue Bonds Series ~~2002A,~~2003, due ~~March~~April 1, ~~2031. The initial interest rate for the bonds~~2022. Interest was ~~1.40%. The interest rate resets~~initially set at 1.05% and will reset every 35 days by auction. ~~Proceeds~~The bonds are not putable by the holders; therefore, PSI’s debt obligation is classified as Long-term debt. On March 28, 2003, the proceeds from this borrowing plus the ~~borrowing~~interest income earned were used ~~on October 1, 2002~~ to ~~redeem, at par,~~cause the ~~$23~~refunding of the $35 million principal amount outstanding of ~~Indiana Development Finance Authority Environmental Refunding Revenue Bonds Series 1998, due August 1, 2028. The redeemed bonds had been classified in~~~~Notes payable and other short-term obligations~~.
29

        ~~On September 12, 2002,PSI~~ ~~borrowed~~ the proceeds from the issuance by the Indiana Development Finance Authority of $24.6 million principal amount of its Environmental Refunding Revenue Bonds Series 2002B, due March 1, 2019. The initial interest rate for the bonds was 1.35%. The interest rate resets every 7 days by auction. Proceeds from the issuance were used on October 1, 2002 to redeem, at par, the $24.6 million principal amount of City of Princeton, Indiana Pollution Control Revenue Refunding Bonds, ~~1996 Series, due March 1, 2019. The~~1997 Series.
On April 25, 2003, PSI redeemed ~~bonds had been classified in~~~~Notes payable and other short-term obligations~~.
        ~~The holders~~$26.8 million of the newly issued Ohio Air Quality Development Authority and Indiana Development Finance Authority bonds mentioned above have the benefit of a financial guaranty insurance policy that insures the payment of principal of, and interest on, the bonds when due.~~CG&E~~ ~~andPSI~~ ~~have each entered into an insurance agreement with the bond insurer and have pledged first mortgage bonds to secure their respective reimbursement obligations under such agreements.~~following Series A, Medium-term Notes:
        ~~On September 23, 2002,CG&E~~ issued $500 million principal amount senior unsecured debentures due September 15, 2012, with an interest rate of 5.70%. Proceeds from the offering were used to repay short-term indebtedness incurred in connection with general corporate purposes including capital expenditures related to environmental compliance construction, and the repayment at maturity of $100 million principal amount of~~CG&E~~ ~~First Mortgage Bonds, 7~~¹/4~~% Series. In July 2002,CG&E~~ executed a treasury lock with a notional amount of $250 million, which was designated as a cash flow hedge of 50 percent of the forecasted interest payments on this debt offering. The treasury lock effectively fixed the benchmark interest rate (i.e., the treasury component of the interest rate, but not the credit spread) for 50 percent of the offering from July 2002 through the issuance date in order to reduce the exposure associated with treasury rate volatility. With the issuance of the debt, the treasury lock was settled. Given the use of hedge accounting, this settlement is reflected in~~Accumulated other comprehensive income (loss)~~ ~~on an after-tax basis in the amount of $13 million, rather than a charge to net income. This amount will be reclassified to~~~~Interest~~ ~~expense over the 10-year life of the related debt as interest is accrued.~~
Principal Amount

Interest Rate

Maturity Date

(in millions)

$2.0

8.37
%
11/08/2006

5.0

8.81

05/16/2022

3.0

8.80

05/18/2022

16.8

8.67

06/01/2022

4.5.                        Notes Payable and Other Short-term Obligations
        ~~In February 2002,~~At March 31, 2003, Cinergy Corp. had $796 million remaining unused and available capacity relating to its $1 billion revolving credit facilities. These revolving credit facilities included the following:
Credit Facility

Expiration

Established
Lines

Outstanding
and
Committed

Unused and
Available

(in millions)

364-day senior revolving

April 2003

Direct borrowing

$

$
—

$

Commercial paper support

193

Total 364-day facility

600

193

407

Three-year senior revolving

May 2004

Direct borrowing

—

Commercial paper support

—

Letter of Credit support

11

Total three-year facility

400

11

389

Total credit facilities

$
1,000

$
204

$
796

In April 2003, Cinergy Corp. successfully placed a $600 million, 364-day senior unsecured revolving credit facility. This facility replaces a ~~$400~~$600 million, 364-day ~~senior revolving credit~~ facility that expired ~~in February 2002; a $225 million, 364-day senior revolving credit facility that expired in March 2002; and a $150 million, three-year senior revolving credit facility that expired in June 2002.~~April 30, 2003.
37
        ~~In October 2002,~~
~~CG&E~~The following table summarizes our ~~andPSI~~ caused the redemption of certain series of variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes) with a principal amount of $84 million and $47.6 million, respectively. Holders of the notes had the option of having their notes redeemed at various times ranging from any business day to annually. Because the optional redemption features were one year or less, the notes are reflected inNotes payable and other short-term obligations ~~in the Balance Sheets forCinergy~~,~~CG&E~~, and~~PSI~~. The notes were redeemed with proceeds from the issuance of new series of variable rate pollution control notes that do not have the redemption features mentioned above, and are therefore classified as~~Long-term debt~~ ~~obligations. See Note 3 for further discussion of variable rate pollution control notes.~~
30

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

September 30, 2002
December 31, 2001

Established
Lines
Outstanding
Established
Lines
Outstanding

(in millions)

Cinergy Corp.
Revolving lines $ 1,000 $ 50 $ 1,175 $ 599
Uncommitted lines(1) 65 20 40 —
Commercial paper(2) 800 311 800 125

Operating companies

Uncommitted lines(1) 75 — 75 66
Pollution control notes N/A 279 N/A 279

Non-regulated subsidiaries

Revolving lines 15 9 46 38
Short-term debt 45 45 49 49

Cinergy Total

$
714

$
1,156

CG&E and subsidiaries

Uncommitted lines(1) $ 15 $ — $ 15 $ —
Pollution control notes(3) N/A 196 N/A 196
Money pool N/A 3 N/A 445

CG&E Total

$
199

$
641

PSI

Uncommitted lines(1) $ 60 $ — $ 60 $ 66
Pollution control notes(3) N/A 83 N/A 83
Money pool N/A 80 N/A 422

PSI Total

$
163

$
571

March 31, 2003

December 31, 2002

Established
Lines

Outstanding

Established
Lines

Outstanding

(in millions)

Cinergy

Cinergy Corp.

Revolving lines

$
1,000

$
—

$
1,000

$
25

Uncommitted lines (1)

65

—

65

—

Commercial paper (2)

193

473

Operating companies

Uncommitted lines (1)

75

—

75

—

Pollution control notes

112

147

Non-regulated subsidiaries

Revolving lines

8

1

7

1

Short-term debt

22

22

22

22

Cinergy Total

$
328

$
668

CG&E and subsidiaries

Uncommitted lines (1)

$
15

$
—

$
15

$
—

Pollution control notes

112

112

Money pool

3

9

CG&E Total

$
115

$
121

PSI

Uncommitted lines (1)

$
60

$
—

$
60

$
—

Pollution control notes

—

35

Money pool

230

138

PSI Total

$
230

$
173

ULH&P

Money pool

$
5

$
14

ULH&P Total

$
5

$
14

~~(1)~~
~~Outstanding amounts may be greater than established lines as uncommitted lenders are, at times, willing to loan funds in excess of the established lines.~~

~~(2)~~
~~The commercial paper program is supported byCinergy Corp.'s~~ ~~revolving lines.~~

~~(3)~~
~~Includes $84 million and $47.6 million forCG&E~~ ~~andPSI, respectively, which were redeemed in October 2002.~~
(1)
Outstanding amounts may be greater than established lines as uncommitted lenders are, at times, willing to loan funds in excess of the established lines.
(2)
The commercial paper program is limited to $800 million and is supported by Cinergy Corp.’s revolving lines.
In our credit facilities,Cinergy Corp. has covenanted to maintain:
•
a consolidated net worth of $2 billion; and

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

38

A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of available credit and acceleration of the related indebtedness include:
•
bankruptcy;

•
defaults in the payment of other indebtedness; and
31
•
judgments against the company that are not paid or insured.

The latter two events, however, are subject to dollar-based materiality thresholds.
~~5.    Sales of Accounts Receivable~~
        ~~In February 2002,CG&E~~,~~PSI, andULH&P~~ ~~replaced their existing agreement to sell certain of their accounts receivable and related collections.Cinergy Corp.~~ ~~formed Cinergy Receivables Company, LLC (Cinergy Receivables) to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections ofCG&E~~,~~PSI, andULH&P~~.~~Cinergy Corp.~~ does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying special-purpose entity. The sales of receivables are accounted for under Statement of Financial Accounting Standards No. 140,~~Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities~~ ~~(Statement 140).~~
        The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25 percent of the total proceeds). The note is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid to~~CG&E~~,~~PSI, andULH&P~~.
        ~~This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under Statement 140 and is classified within~~~~Notes receivable from affiliated companies~~ ~~in the accompanying Balance Sheets ofCG&E~~,~~PSI, andULH&P~~ ~~and is classified within~~~~Notes receivable~~ on~~Cinergy Corp.'s~~ ~~Balance Sheets. In addition,Cinergy Corp.'s~~ investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held by~~CG&E~~,~~PSI, andULH&P~~. The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses and selection of discount rates. Because (a) the receivables generally turn in less than two months, (b) credit losses are reasonably predictable due to each company's broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated basis of the subordinated notes are not materially different than their face value. Interest accrues to~~CG&E~~,~~PSI, andULH&P~~ ~~on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent.Cinergy Corp.~~ records income from Cinergy Receivables in a similar manner. We record an impairment charge against the carrying value of both the retained interests and purchased beneficial interest whenever we determine that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).
32

        ~~The key assumptions used in measuring the retained interests for sales since the inception of the new agreement are as follows:~~

Cinergy
CG&E and
subsidiaries
PSI
ULH&P

Anticipated credit loss rate 0.6 % 0.6 % 0.5 % 1.0 %
Discount rate on expected cash flows 5.0 % 5.0 % 5.0 % 5.0 %
Receivables turnover rate(1) 13.2 % 13.6 % 12.7 % 14.2 %
~~(1)~~
~~Receivables at period end divided by annualized sales for period.~~
        The hypothetical effect on the fair value of the retained interests assuming both a 10 percent and 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.
~~CG&E~~ retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to~~CG&E~~,~~PSI, andULH&P~~ ~~in the event of a loss. While no direct recourse toCG&E~~,~~PSI, andULH&P~~ exists, these entities do risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid to~~CG&E~~ ~~approximates a market rate.~~
        ~~The following table shows the gross and net receivables sold, retained interest, and purchased beneficial interest as of September 30, 2002.~~

Cinergy
CG&E and
subsidiaries
PSI
ULH&P

(in millions)

Receivables sold as of period end $ 438 $ 252 $ 186 $ 36
Less: Retained Interest 76 42 34 6

Net receivables sold as of period end $ 362 $ 210 $ 152 $ 30

Purchased beneficial interest

$
9

$
—

$
—

$
—
        ~~A decline in the long-term senior unsecured credit ratings ofCG&E~~,~~PSI, orULH&P~~ below investment grade would result in a termination of the sale program and discontinuance of future sales of receivables, and could prevent Cinergy Receivables from borrowing additional funds from commercial paper conduits.
6.                        Energy Trading Credit Risk

~~Cinergy's~~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 ~~September 30, 2002,~~March 31, 2003, approximately 98 percent of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or the counterparties’ obligations were guaranteed by a parent company or other entity rated Investment Grade. No single non-investment grade counterparty accounts for more than one percent of our total credit exposure. Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities 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 U.S. 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
33

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(d)(iv~~)). These contracts were recognized at fair value when the contracts were terminated in the fourth quarter of 2001.~~
We continually review and monitor our credit exposure to all counterparties and secondary counterparties. If appropriate, we may adjust our credit reserves to attempt to compensate for increased credit risk within the industry. Counterparty credit limits may be adjusted on a daily basis in response to changes in a ~~counterparty's~~counterparty’s creditworthiness, financial status, or public debt ratings.
7.                        Commitments and Contingencies
(a)                                  Guarantees

In the ordinary course of business, Cinergy ~~Corp.~~ ~~has made separate guarantees~~enters into various agreements providing financial or performance assurances to ~~certain counterparties regarding performance~~third parties on behalf of ~~commitments by our consolidated subsidiaries,~~certain unconsolidated subsidiaries and joint ventures. WeThese agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these entitieson a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish their intended commercial purposes. The guarantees have various termination dates, from short-term (less than one year) to open-ended.
In many cases, the maximum potential amount of an outstanding guarantee is an express term, set forth in the guarantee agreement, representing the maximum potential obligation of Cinergy under that guarantee (excluding, at times, certain legal fees to which a guaranty beneficiary may be entitled). In those cases where there is no maximum potential amount expressly set forth in
39

the guarantee agreement, we calculate the maximum potential amount by considering the terms of the guaranteed transactions, to the extent such amount is estimable.
Cinergy has guaranteed the payment of $33 million as of March 31, 2003, for unconsolidated subsidiaries’ debt and for borrowings by individuals under the Director, Officer, and Key Employee Stock Purchase Program. Cinergy may be obligated to pay the debt’s principal and any related interest in the event of an unexcused breach of a guaranteed payment obligation by the unconsolidated subsidiary or an unexcused breach of guaranteed payment obligations by certain directors, officers, and key employees. The majority of these guarantees expire in two years.
Cinergy Corp. has also provided performance guarantees on behalf of certain unconsolidated subsidiaries and joint ventures. These guarantees support performance under various agreements and instruments (such as construction contracts, operation and maintenance agreements and energy service agreements). Cinergy Corp. may be liable in the event of an unexcused breach of a guaranteed performance obligation by an unconsolidated subsidiary. Cinergy Corp. has estimated its maximum potential amount to be $133 million under these guarantees as of March 31, 2003. Cinergy Corp. may also have recourse to third parties for claims required to be paid under certain of these guarantees. The majority of these guarantees expire at the completion of the underlying performance agreements, generally 15 to 20 years.
Cinergy has entered into contracts that include indemnification provisions as a routine part of its business activities. Examples of thesecontracts include purchase and sale agreements and operating agreements. In general, these provisions indemnify the counterparty for matters such as breaches of representations and warranties and covenants contained in the contract. In some cases, particularly with respect to purchase and sale agreements, the potential liability for certain indemnification obligations is capped, in whole or in part (generally at an aggregate amount not exceeding the sale price), and subject to a ~~Securities~~deductible amount beforeany payments would become due.In other cases (such as indemnifications for willful misconduct of employees in a joint venture), the maximum potential amount is not estimable given that the magnitude of any claims under those indemnifications would be a function of the extent of damages actually incurred, which is not practicable to estimate unless and ~~Exchange Commission order~~until the event occurs. Cinergy has estimated the maximum potential amount, where estimable, to be $129 million under these indemnification provisions and considers the ~~Public Utility Holding Company Act~~likelihood of ~~1935, as amended, which limits~~making any material payments under these provisions to be remote. The termination period for the ~~amount we can have outstanding under guarantees at~~majority of matters provided by indemnification provisions in purchase and sale agreements generally ranges from one to six years.
We believe the likelihood that Cinergy would be required to perform or otherwise incur any ~~one time to $2 billion. As~~significant losses associated with any or all of ~~September 30, 2002, we had $547 million outstanding under~~ the guarantees ~~issued, of which approximately 75 percent represents guarantees of obligations reflected onCinergy's~~ ~~Consolidated Balance Sheets. These outstanding guarantees relate to subsidiary and joint venture indebtedness and performance commitments.~~described in the preceding paragraphs is remote.
(b)                                  Ozone Transport Rulemakings

In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the ~~U.S.~~ Environmental Protection Agency (EPA) to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant
40

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 (SIP) for achieving emissions reductions to address air quality concerns. The EPA must approve all SIPs.~~

(i)~~(i)~~               Nitrogen Oxide (NO_X) ~~SIP~~State Implementation Plan (SIP) Call

In October 1998, the EPA finalized its ozone transport rule, also known as the NO_X SIP Call. It applied to 22 states in the ~~Eastern~~eastern half of the ~~U.S.~~United States (U.S.), including the three states in which our electric utilities operate, and proposed a model NO_X emission ~~allowance-trading~~allowance trading program. This rule recommended that states reduce NO_X emissions primarily from industrial and utility sources to a certain level by May 2003. ~~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~~In August 2000, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals).
        ~~Following a number of rulings and appeals, in August 2000, the Court of Appeals~~ extended the deadline for NO_X reductions to May 31, 2004. ~~The states and other groups sought review of the Court of Appeals ruling by the U.S. Supreme Court (Supreme Court). In March 2001, the Supreme Court decided not to grant that review.~~
In June 2001, the Court of Appeals remanded portions of the NO_X SIP Call to the EPA for reconsideration of how growth was factored into the state NO_X budgets. On May 1, 2002, the EPA published, in the Federal Register, a final rule reaffirming its growth factors and state NO_X budgets,
34

with additional explanation. The states of West Virginia and Illinois, along with various industry groups (some of which we are a member), have challenged the growth factors and state NO_X budgets in an action filed in the Court of Appeals. It is unclear when the Court of Appeals will reach a decision in this case, or whether this decision will result in an increase or decrease in the size of the NO_X reduction requirement, or a deferral of the May 31, 2004 compliance deadline.
The states of Indiana and Kentucky developed final NO_X SIP rules in response to the NO_X SIP Call, through cap and trade programs, in June and July of 2001, respectively. On November 8, 2001, the EPA approved ~~Indiana's~~Indiana’s SIP rules, which became effective December 10, 2001. On April 11, 2002, the EPA proposed direct final approval of ~~Kentucky's~~Kentucky’s rules and they became effective on June 10, 2002. The state of Ohio completed its NO_X SIP rules in response to the NO_X SIP Call on July 8, 2002, with an effective date of July 18, ~~2002,~~2002. On January 16, 2003, the EPA proposed a direct final rule to approve Ohio’s SIP. The EPA has since withdrawn that proposal, and now intends to issue a conditional approval, which will not take effect until Ohio changes one specific aspect of its final rule (relating to the ~~EPA's approval is expected later this year.~~date flow control takes effect). Cinergy’s~~Cinergy's~~ current plans for compliance with the ~~EPA's~~EPA’s NO_X SIP Call would also satisfy compliance with ~~Indiana's~~Indiana’s, Kentucky’s, and ~~Kentucky's~~Ohio’s SIP ~~rules and Ohio's proposed~~ rules.
On September 25, 2000,Cinergy announced a plan for its subsidiaries,CG&E andPSI, to invest in pollution control equipment and other methods to reduce NO_X emissions. This plan includes the following:
•                  install nine selective catalytic reduction units at several different generating stations;
•                  install other pollution control technologies, including new computerized combustion controls, at all generating stations;
•                  make combustion improvements; and
•                  utilize the NO_X allowance market to buy or sell NO_X allowances as appropriate.
The current estimate offor additional expenditures for this investment is approximately ~~$350~~$238 million ~~(in nominal dollars)~~ and ~~includes~~is in addition to the ~~following:~~
•
~~install selective catalytic reduction units (SCR) 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~~$604 million already incurred 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.~~comply with this program.

41

(ii)           Section 126 Petitions

In February 1998, several northeast states filed petitions seeking the ~~EPA's~~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_Xemissions. This ruling affected all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and ~~requires~~required us to reduce our NO_X emissions to a certain level by May 2003. In May 2001, the Court of Appeals substantially upheld a challenge to the Section 126 requirements, and remanded portions of the rule to the EPA for reconsideration of how growth was factored into the emission limitations. On ~~August 24, 2001, the Court of Appeals temporarily suspended the Section 126 compliance deadline, pending the EPA's reconsideration of growth factors. On~~ May 1, 2002, the EPA issued a final rule extending the Section 126 rule compliance deadline to May 31, 2004, thus harmonizing the deadline with that for the NO_X SIP Call.
~~(iii)    State Ozone Plans~~
On ~~November 15, 1999,~~April 4, 2003, the EPA issued a proposed rule withdrawing the Section 126 rule in states with approved SIPs under the NO_X SIP Call, which include 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.Kentucky. The ~~Greater Louisville Area has since attained the one-hour ozone standard, and on October 23, 2001,~~proposed rule states that the EPA ~~re-designated~~will withdraw the ~~area as being~~Section 126 in ~~attainment with~~Ohio once Ohio has a fully approved SIP. As a result of these actions, we anticipate that ~~standard. Previous SIP amendments called for, among other things, statewide NO~~_X ~~reductions from utilities in~~the Section 126 rule will not affect any of our facilities.
35

~~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~~_X ~~control 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 March 18, 2002, Kentucky completed the withdrawal of this regulation in favor of its completed and more restrictive regulations in response to the NO~~_X ~~SIP Call.~~
See (e) 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.
(c)                                  New Source Review (NSR)

The ~~CAA's~~CAA’s NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major modification to an existing facility, unless the changes are exempt.
        ~~On September 15, 1999, November 3, 1999, and February 2, 2001, the Attorneys General of New York, Connecticut, and New Jersey, respectively, issued letters notifyingCinergy~~ ~~andCG&E~~ ~~of their intent to sue under the citizens' suit provisions of the CAA. These states alleged violations of the CAA by constructing and continuing to operate a major modification ofCG&E's~~ ~~W.C. Beckjord Generating Station (Beckjord Station) without obtaining the required NSR pre-construction permits.~~
On November 3, 1999, the ~~EPA~~United States sued a number of holding companies and electric utilities, includingCinergy,CG&E, andPSI, in various U.S. District ~~Courts (District Court).~~Courts. TheCinergy,CG&E, andPSI suit alleged violations of the CAA at two of our generating stations relating to NSR and New Source Performance Standards requirements. The suit sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at CG&E’s W.C. Beckjord Generating Station (Beckjord Station) and atPSI’s~~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,~~ Since that time, two amendments to the ~~EPA filed an amended~~ complaint ~~againstCinergy~~,~~CG&E, andPSI. The amended complaint added alleged violations of the NSR requirements of the CAA at two of our generating stations contained in a notice of violation (NOV)~~have been 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 (d)).~~
        ~~The amended complaint sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station andPSI's~~ Cayuga Station, Wabash River Generating Station, and Gallagher Generating Station, and such other measures as necessary, and (2) civil penalties in amounts of up to $27,500 per day for each violation.
        ~~On March 1, 2000, the EPA also filed an amended complaint in a separate lawsuit~~United States, alleging additional violations of the CAA, ~~relating to NSR, Prevention of Significant Deterioration (PSD)~~including allegations involving different generating units. In addition, three northeast states and two environmental groups have intervened in the case.
On December 21, 2000, Cinergy, CG&E, and ~~Ohio SIP requirements regarding various generating stations, including~~PSI reached an agreement in principle with the parties in the litigation for a ~~generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, the Dayton Power and Light Company (DP&L), andCG&E~~. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. On April 4, 2001, the District Court in that case ruled that neither the Government nor the intervening plaintiff environmental groups could obtain civil penalties for any alleged violations that occurred more than five years prior to the filingnegotiated resolution of the ~~complaint, but that both parties could seek injunctive relief~~CAA claims in the litigation. See (e) below for ~~alleged violations that occurred more than five years before the filing~~a discussion 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 forcedtentative EPA Agreement, which relates to ~~install the controls required under the CAA. Neither party appealed that decision.~~matters discussed within this note.
36
42

        ~~On June 28, 2000, the EPA issued an NOV toCinergy~~,~~CG&E, andPSI~~ ~~for alleged violations of NSR, PSD, and SIP requirements atCG&E's~~ ~~Miami Fort Generating Station andPSI's~~ ~~Gibson Generating Station. In addition,Cinergy~~ ~~andCG&E~~ have been informed by DP&L, the operator of J.M. Stuart Generating Station (Stuart Station), that on June 30, 2000, the EPA issued an NOV to DP&L for alleged violations of NSR, PSD, and SIP requirements at this station.~~CG&E~~ owns 39 percent of the Stuart Station. The NOVs indicated the EPA may (1) issue an order requiring compliance with the requirements of the SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation.
        On August 2, 2001, the states of New York, New Jersey, and Connecticut filed an assented to motion to intervene in this litigation. Their motion was granted by the District Court on August 3, 2001. The states' proposed complaint is an exhibit to the motion to intervene.~~Cinergy~~,~~CG&E, andPSI~~ ~~are in the process of evaluating the states' complaint, and their answer is due to be filed by November 30, 2002. At this time,Cinergy~~,~~CG&E, andPSI~~ ~~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.~~
        On January 17, 2002, the Hoosier Environmental Council and the Ohio Environmental Council (Environmental Groups) filed an unopposed motion to intervene as plaintiffs in this litigation. The motion was granted by the District Court on March 19, 2002, and the complaint of the Environmental Groups' was filed on May 1, 2002.~~Cinergy~~,~~CG&E, andPSI~~ ~~are in the process of evaluating the Environmental Groups' complaint, and their answer is due to be filed by November 30, 2002. At this time,Cinergy~~,~~CG&E, andPSI~~ ~~are unable to determine the effect, if any, this filing will have upon the issues affecting us regarding NSR, as framed in the EPA's amended complaint.~~
        On July 18, 2002, the U.S. District Court for the Southern District of Indiana (Indiana District Court), issued an order on a motion for partial summary judgment in a similar case involving the Southern Indiana Gas and Electric Company (SIGECO). The narrow issue presented by SIGECO's motion was at what point does an owner or operator of facilities have to determine whether a pre-construction permit is required under the CAA. The Indiana District Court, relying in part upon a decision issued by the Environmental Appeals Board in a similar case involving the Tennessee Valley Authority, ruled that the owner or operator must review evidence of the projected post-project emissions increases to determine if the pre-construction permit is required, and may not rely upon evidence of actual post-project emissions. The Indiana District Court is the same court in which~~Cinergy's~~ ~~case is pending, so it could be expected that this order would influence a decision upon any similar motion filed byCinergy. No such motion is pending at this date. At this timeCinergy~~ ~~cannot predict the impact any such ruling might have on its financial position or results of operations.~~
        On July 26, 2002, the Indiana District Court also issued an order on a motion for partial summary judgment in the SIGECO case. The issue presented by SIGECO's motion was whether the general federal five-year statute of limitations bars an action for civil penalties for allegedly unlawful construction projects that were completed more than five years prior to the filing of suit. The Indiana District Court held that an NSR preconstruction violation accrues on the first day of construction without a permit, and continues only through the end of construction. Accordingly, the government may not collect civil penalties for allegedly unlawful projects for which construction ended more than five years before the filing of an enforcement action.~~Cinergy~~ ~~is not aware that any notice of appeal has been filed regarding that order.Cinergy~~ ~~will file a similar motion if the parties fail to enter into a consent decree to settle all issues. At this timeCinergy~~ cannot predict the impact on our financial position or results of operations, although the amount of penalties, if any, that could potentially be awarded by the Indiana District Court if the ruling is not reversed, would be significantly smaller than the amount claimed by the EPA in its amended complaint against~~Cinergy~~.
37

        On October 25, 2002, the Indiana District Court also issued an order on a motion for summary judgment in the SIGECO case. The issue presented by SIGECO's motion was whether or not the Government violated the Congressional Review of Agency Rule Making Act, 5 U.S.C. Section 801,~~et seq.~~ (CRA) by establishing a new agency rule without submitting a report to Congress about the rule as required by the CRA. SIGECO had argued that, at least since the filing of the NSR lawsuit against it in November 1999, the EPA was interpreting more strictly the NSR routine maintenance exemption that had been validated by the Seventh Circuit Court of Appeals in~~Wisconsin Electric Power Co. v. Reilly, 893 F.2d 901 (7~~^th Cir. 1990), and that this new, stricter interpretation in effect established a new agency rule. In denying SIGECO's motion, the Indiana District Court held that SIGECO had failed to demonstrate that the EPA had changed its longstanding interpretation of the NSR routine maintenance exemption. As the Indiana District Court is the same court in which~~Cinergy's~~ ~~case is pending, it could be expected that this order would influence a decision upon any similar motion filed byCinergy. However, no such motion is pending at this date.Cinergy~~ ~~cannot predict the impact any such ruling might have on its financial position or results of operations.~~
On October 4, 2002, the Indiana District Court issued a Revised Case Management Plan inCinergy’s~~Cinergy's~~ case that sets forth the dates by which various events in the litigation, such as discovery and the filing of dispositive motions, must be completed. Consistent with the plan, on October 9, 2002, the Indiana District Court set the case for trial by jury commencing on October 4, 2004.
~~See (e) below for~~
At this time, it is not possible to predict whether a ~~discussion~~final agreement implementing the agreement in principle can be reached. The parties continue to negotiate. If the settlement is not completed, we intend to defend against the allegations vigorously in court. In such an event, it is not possible to determine the likelihood that the plaintiffs would prevail upon their claims or whether resolution of ~~the tentative EPA Agreement, which relates to~~these matters ~~discussed within this note.~~would have a material effect on our financial position or results of operations.
(d)                                  Beckjord Station ~~NOV~~Notice of Violation (NOV)

On November 30, 1999, the EPA filed an NOV againstCinergy andCG&E, alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit. ~~The NOV indicated 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 (c) 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.~~Station. The NOV/FOV indicated the EPA may issue an administrative compliance order, issue an administrative penalty order, or bring a civil or criminal action.
See (e) below for a discussion of the tentative EPA Agreement, which relates to matters discussed within this note.
(e)                                  EPA Agreement

On December 21, 2000,Cinergy,CG&E, andPSI reached an agreement in principle with the ~~EPA, the U.S. Department of Justice (Justice Department),~~United States, three northeast states, and two environmental groups ~~that could serve as the basis~~ for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated byCinergy’s~~Cinergy's~~ operating subsidiaries. The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties. If a final agreement is reached with these parties, it would resolve past claims of alleged NSR violations as well as the Beckjord Station NOVs/FOV discussed previously under (c) and (d).
In addition, the intent of the tentative agreement is that we would be allowed to continue on-going activities to maintain reliability and availability without subjecting the plants to future litigation regarding federal NSR permitting requirements.
38

In return for resolution of claims regarding past maintenance activities, as well as future operational certainty, we have tentatively agreed to:
•
shut down or repower with natural gas, nine small coal-fired boilers at three power plants beginning in 2004;

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

•
•
upgrade existing particulate control systems;

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

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

•
•
pay a civil penalty of $8.5 million to the U.S. government; and
43

•
implement $21.5 million in environmental mitigation projects, including retiring 50,000 tons of SO₂ allowances by 2005.
The estimated cost for these capital expenditures is expected to be approximately $700 million through 2013. These capital expenditures are in addition to our previously announced commitment to install NO_X controls as discussed in (b) above, but ~~includes~~does include capital costs thatCinergy would ~~otherwise~~ expect to spend regardless of the settlement due to new environmental requirements expected in the second half of this decade.

Cinergy,CG&E, andPSI have accrued costs related to certain aspects of the tentative agreement. In reaching the tentative agreement, we did not admit any wrongdoing and remain free to continue our current maintenance practices, as well as implement future projects for improved reliability.
        ~~In January 2002, the Justice Department completed its review of NSR, after considering dismissal of the lawsuits, and decided to pursue the pending lawsuits, including the suit againstCinergy~~,~~CG&E, andPSI. We will continue to pursue a negotiated settlement of these lawsuits if that continues to be in the best interests of the company.~~
At this time, it is not possible to predict whether a final agreement implementing the agreement in principle can be reached. The parties continue to negotiate. If the settlement is not completed, we intend to defend against the allegations, discussed in (c) and (d) above, vigorously in court. In such an event, it is not possible to determine the likelihood that the plaintiffs would prevail onupon their claims or whether resolution of these matters would have a material effect on our financial position or results of operations.
(f)                                    Manufactured Gas Plant (MGP) Sites
~~(i)    General~~
Prior to the 1950s, gas was produced at MGP sites through a process that involved the heating of coal and/or oil. The gas produced from this process was sold for residential, commercial, and industrial uses.
~~(ii)    PSI~~
Coal tar residues, related hydrocarbons, and various metals associated with MGP sites have been found at former MGP sites in Indiana, including at least 21 sites whichPSI or its predecessors previously owned.PSI acquired four of the sites from Northern Indiana Public Service Company (NIPSCO) in 1931. At the same time,PSI sold NIPSCO the sites located in Goshen and Warsaw, Indiana. In 1945,PSI sold 19 of these sites (including the four sites it acquired from NIPSCO) to the predecessor of the Indiana Gas Company, Inc. (IGC). IGC later sold the site located in Rochester, Indiana to NIPSCO.
39

IGC ~~(in 1994)~~ and NIPSCO ~~(in 1995) both~~ made claims againstPSI~~. The basis of these claims was thatPSI~~ ~~is a Potentially Responsible Party with respect to the 21 MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted thatPSI~~ ~~was legally responsible~~ for the costs of investigating and remediating the sites. In ~~August 1997, NIPSCO filed suit againstPSI~~ ~~in federal court, claiming recovery (pursuant to CERCLA) of NIPSCO's past and future costs of investigating and remediating MGP-related contamination at the Goshen, Indiana MGP site.~~
        ~~In November~~ 1998, NIPSCO, IGC, andPSI entered into a Site Participation and Cost Sharing ~~Agreement (Agreement)~~Agreements (Agreements). ~~This Agreement~~These Agreements allocated ~~CERCLA~~the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) liability for past and future costs at ~~seven~~the MGP sites in Indiana among the three companies. ~~As a result of the Agreement, NIPSCO's lawsuit againstPSI~~ was dismissed. The parties have assigned lead responsibility for managing further investigation and remediation activities at each of the sites to one of the parties. Similar agreements were reached between IGC 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
44

Indiana against its general liability insurance carriers.PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims againstPSI, or (2) payPSI’s~~PSI's~~ costs of defense and compensatePSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. The lawsuit was moved to the Hendricks County Superior Court ~~(Superior Court)~~ in July 1998.~~PSI~~ ~~and its insurance carriers filed briefs on various issues for decision by the Superior Court in hearings held in November 2001. On February 1, 2002, the Superior Court~~ The trial court issued ~~rulings on motions for summary judgment. The Superior Court granted the motions~~a variety of several insurance carriers that claimed there was insufficient evidence concerning the terms of their insurance policies. The insurance policies in question were between 1950-1958 and 1961-1964. The Superior Court entered a final judgment with respect to these "lost policies" on March 25, 2002. 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. On February 15, 2002,PSI~~ ~~requested~~ rulings on certain remaining summary judgment issues and a clarification of certain of the Superior Court's summary judgment rulings. That request was denied on April 1, 2002. On March 15, 2002, one of the insurance carriers filed a motion for partial summary judgment asserting a Lack of Justiciability. That motion was heard on April 26, 2002, and denied by the Superior Court on April 30, 2002.
        ~~On April 23, 2002,PSI~~ ~~filed a notice of appeal with the Indiana Court of Appeals~~ with respect to the ~~Superior Court's March 25, 2002 order granting final judgment with respect~~claims and defenses in the litigation. PSI has appealed certain adverse rulings to ~~certain "lost policies." On June 21, 2002, the Superior Court granted the motions ofPSI~~ ~~and the insurance carriers and certified four orders for interlocutory review by~~ the Indiana Court of Appeals. Unlike the "lost policies" appeal that is an appeal of right, the appeal of these four certified orders is discretionary and the Indiana Court of Appeals can accept or reject any or all of the issues certified. At the present time,PSI cannot predict the outcome of this litigation, including the outcome of the appeals to the Indiana Court of Appeals.
40

~~(iii)~~    ~~CG&E~~
CG&E ~~and its utility subsidiaries are~~ is 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~~ has begun preliminary site assessments to obtain information about some of these MGP sites.

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

CG&E andPSI have been named in lawsuits related to Asbestos at their electric generating stations. In these lawsuits, plaintiffs claim to have been exposed to Asbestos containing products in the course of their work at theCG&E andPSI generating stations. The plaintiffs further claim that as the property owner of the generating stations,CG&E andPSI should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any Asbestos exposure. A majority of the lawsuits to date have been brought against PSI. The impact onCG~~&E's~~&E’s and ~~and~~PSI’s~~PSI's~~ financial position or results of operations of these cases to date has not been material.
One specific case filed againstPSI has been tried to verdict. ~~Following a ten week trial of the case entitled~~~~William Lee Roberts, Jr. and Beverly Roberts v. AC&S, Inc., et al., PSI Energy, Inc.~~~~, Marion Superior Court 2, on May 24, 2002, the~~The jury returned a verdict againstPSI in the amount of ~~$494,000~~approximately $500,000 on a negligence claim and forPSI on punitive damages.PSI is appealing the judgment in this case. The total damages were immaterial toPSI’s~~PSI's~~ financial position and results of operations. ~~However, future verdicts in any of the pending lawsuits could be material.~~ At this time,CG&E andPSIare not able to predict the ultimate outcome of these lawsuits or the ~~impacts~~impact onCG~~&E's~~&E’s and ~~and~~PSI’s~~PSI's~~ financial position or results of operations.
(h)                                 Gas Customer Choice
In January 2000, Cinergy Investments ~~Inc.~~ (Investments) sold Cinergy Resources, Inc. (Resources), a former subsidiary, to Licking Rural Electrification, Inc., doing business as The Energy
45

Cooperative (Energy Cooperative). In February 2001,Cinergy,CG&E, and Resources were named as defendants in three class action lawsuits brought by customers relating to Energy ~~Cooperative's~~Cooperative’s removal from the Ohio Gas Customer Choice program and the failure to deliver gas to customers.
Subsequently, these class action suits were amended and consolidated into one suit.CG&E has been dismissed as a defendant in the consolidated suit. In March 2001,Cinergy,CG&E, and Investments were named as defendants in a lawsuit filed by both Energy Cooperative and Resources. This lawsuit concerns any obligations or liabilities Investments may have to Energy Cooperative following its sale of Resources. This lawsuit is pending in the Licking County Common Pleas Court. Trial is anticipated to occur in late 2003 or early 2004. In October 2001, Cinergy,CG&E, and Investments initiated litigation ~~in October 2001~~ against the Energy Cooperative requesting indemnification by the Energy Cooperative for the claims asserted by former customers in the class action litigation. ~~Trial~~This customer litigation is ~~scheduled to occur~~pending in ~~mid-2003.~~the Hamilton County Common Pleas Court. A trial date has not been set. We intend to vigorously defend these lawsuits. At the present time,~~Cinergy~~ we cannot predict the outcome of these suits.
41

(i)                                    PSI Fuel Adjustment Charge

        ~~As discussed in the 2001 Form 10-K,PSI~~ ~~defers fuel costs that are recoverable in future periods subject to Indiana Utility Regulatory Commission (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. In June 2001,PSI~~ ~~formally requested that the IURC reconsider its disallowance decision. In August 2001, the IURC indicated that it would reconsider its decision andPSI~~ ~~continued the deferral of these costs. In August 2002, the IURC issued its final ruling allowingPSI~~ ~~to fully recover the $14 million.~~
        ~~In June 2001,PSI~~ filed a petition with the IURC requesting authority to recover $16 million in ~~under-billed~~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~~under billed deferred fuel costs. A hearing was held in July 2002, and in March 2003 the IURC issued an order giving final approval to PSI’s recovery of the $16 million.
(j)                                    PSI Retail Rate Case
In December 2002, PSI filed a petition with the IURC seeking approval of a base retail electric rate increase. PSI filed initial testimony in this case in March 2003. PSI proposes an increase in revenues of approximately $200 million, or an average increase of approximately 15 percent over PSI’s retail electric rates in effect at the end of 2002. An IURC decision is expected in the first quarter of 2004.
46

(k)                                PSI Construction Work in Progress (CWIP) Ratemaking Treatment for NO_X Equipment
In April 2003, PSI filed an application with the IURC requesting that its CWIP rate adjustment mechanism be updated for expenditures through December 2002 related to NO_X equipment currently being installed at certain PSI generation facilities. CWIP ratemaking treatment allows for the recovery of carrying costs on certain pollution control equipment while and after the equipment is under construction. Testimony and exhibits supporting PSI’s second CWIP rate adjustment mechanism update have not yet been filed. However, amounts proposed for potential recovery are presented below:
PSI CWIP Ratemaking for NO_X Equipment

PSI

(in millions)

Total retail CWIP expenditures as of December 31, 2002

$
305

Proposed total amount requested through CWIP mechanism(1)

35

Less: previously approved CWIP mechanism amounts

(28
)
Proposed incremental CWIP mechanism amounts

$
7

(1)
Amounts include retail customers’ portion only and represent an annual return on qualified NO_X equipment expenditures.
PSI’s initial CWIP rate mechanism adjustment (authorized in July 2002) resulted in an approximately one percent increase in customer rates. Under the IURC’s CWIP rules, PSI may update its CWIP tracker at six-month intervals. The first such update to PSI’s CWIP rate mechanism occurred in the first quarter of 2003. The IURC’s July 2002 order also authorized PSI to defer, for subsequent recovery, post-in-service depreciation and to continue the accrual for allowance for funds used during construction (AFUDC). Pursuant to Statement of Financial Accounting Standards No. 92, Regulated Enterprises-Accounting for Phase-in Plans, the equity component of AFUDC will not be deferred for financial reporting after the related assets are placed in service.
(l)                                    PSI Purchased Power Tracker (Tracker)
The Tracker 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.
PSI is authorized to seek recovery of 90 percent of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portion), with the remaining 10 percent deferred for subsequent recovery in PSI’s general rate case. In March 2002, PSI filed a petition with the IURC seeking approval to extend the Tracker process beyond the summer of 2002. A hearing was held on January 16, 2003, and the case is now awaiting an IURC order. We cannot predict the outcome of this proceeding at this time.
47

(m)                              CG&E Gas Rate Case
In the third quarter of 2001, CG&E filed a retail gas rate case with the Public Utilities Commission of Ohio (PUCO) seeking to increase base rates for natural gas distribution service and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $716 million over 10 years. CG&E entered into a settlement agreement with most of the parties and a hearing on this matter was held in April 2002. An order was issued in May 2002, in which the PUCO approved the settlement agreement and authorized a base rate increase of approximately $15 million, or 3.3 percent overall, effective May 30, 2002. ~~We anticipate a decision~~In addition, the PUCO authorized CG&E to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program, subject to certain rate caps that increase in amount annually through May 2007, through the effective date of new rates in CG&E’s next retail gas rate case. In the fourth quarter of ~~2002.~~2002, CG&E filed an application to increase its rates under the tracking mechanism. In April 2003, CG&E entered into a settlement agreement with the parties, providing for an increase of $6.5 million, which the PUCO subsequently approved.
~~(j)~~(n)                                 ULH&P Gas Rate Case
As discussed in the 2002 10-K, in the second quarter of 2001, ULH&P filed a retail gas rate case with the Kentucky Public Service Commission (KPSC) seeking to increase base rates for natural gas distribution services and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $112 million over 10 years. ULH&P made its second annual filing for an increase under the tracking mechanism in March 2003. The application seeks an increase of $2 million. ULH&P expects the KPSC to rule on the application during the second quarter of 2003. At the present time, ULH&P cannot predict the outcome of this proceeding. The Kentucky Attorney General has appealed the KPSC’s approval of the tracking mechanism to the Franklin Circuit Court and has also appealed the KPSC’s August 2002 order approving the new tracking mechanism rates. At the present time, ULH&P cannot predict the timing or outcome of this litigation.
(o)                                  Contract Disputes

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

Cinergy, through a subsidiary of Capital & Trading, is ~~involved~~ in arbitration with a ~~billing dispute with respect to billings for the supply of wholesale~~counterparty concerning various disputes under an agreement whereby we market natural gas ~~to a customer. This dispute, if not satisfactorily resolved by~~that the ~~parties, is subject to arbitration.Cinergy~~ ~~has~~counterparty produces or acquires in North America. We have reserved for a portion of the amount billed based on the current estimate of net realizable value. Absent a voluntary resolution to the disputes, we intend to pursue the arbitration vigorously.
48

Although we cannot predict the outcome of these matters, we believe the ultimate impact onCinergy’s~~Cinergy's~~ financial position and results of operations, beyond amounts reserved, will not be material.
~~8.    Employee Severance Programs~~(p)                                  Enron Corp. (Enron) Bankruptcy
In ~~March 2002, a Voluntary Early Retirement Program (VERP) offering was made to approximately 280 non-union employees. As a result~~December 2001, Enron filed for protection under Chapter 11 of the ~~213 employees electing the VERP~~U.S. Bankruptcy Code in the ~~second quarter~~Southern District of ~~2002,~~New York. We decreased our trading activities with Enron in the months prior to its bankruptcy filing and have filed a motion with the bankruptcy court overseeing the Enron bankruptcy seeking appropriate netting of the various payables and receivables between and among Enron and Cinergy,~~CG&E~~, entities. We intend to resolve any contract differences pursuant to the terms of those contracts, business practices, and~~PSI~~ ~~recorded expenses~~ the applicable provisions of ~~approximately $35 million, $16 million (including $2 million related toULH&P), and $18 million, respectively,~~the U.S. 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 ~~benefits provided to the VERP participants. In the second quarter~~those contracts would have a material impact on our financial position or results of ~~2002,Cinergy~~,~~CG&E, andPSI~~ ~~incurred approximately $13 million, $2 million, and $4 million, respectively, in additional expenses related to other employee severance programs.~~operations.
        In June 2002, a VERP was also offered to approximately 70 Utility Workers of America / Independent Utilities Union # 600 (IUU) employees. As a result of the 41 employees electing the VERP in the third quarter of 2002,~~Cinergy~~,~~CG&E, andPSI~~ ~~recorded expenses of approximately $4 million, $2 million (including $1 million related toULH&P), and $1 million, respectively, in the third quarter of 2002 relating to benefits provided to IUU VERP participants.~~
9.8.                        Financial Information by Business Segment

As discussed in the ~~2001 Form~~2002 10-K, 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
42
•
Power Technology and Infrastructure Services Business Unit (Power Technology).

The following section describes the activities of our business units as of ~~September 30, 2002.~~March 31, 2003.

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

•
~~financial restructuring services;~~

•
proprietary arbitrage activities;

and
•
customized energy ~~solutions; and~~

•
~~directs our renewable energy investing activities.~~
solutions.
Regulated Businesses consists ofPSI’s~~PSI's~~ regulated, integrated utility operations, andCinergy’s~~Cinergy's~~ other regulated electric and gas transmission and distribution systems. Regulated Businesses plans, constructs, operates, and maintainsCinergy’s~~Cinergy's~~ transmission and distribution systems and delivers gas and electric energy to consumers. Regulated Businesses also earns revenues from wholesale customers primarily by transmitting electric power throughCinergy’s~~Cinergy's~~ transmission system.
Power Technology primarily manages the development, marketing, and sales of our non-regulated retail energy and energy-related businesses. This is accomplished through various subsidiaries and joint ventures. Power Technology also manages Cinergy Ventures, LLC
49

(Ventures),Cinergy’s~~Cinergy's~~ venture capital subsidiary. Ventures invests in emerging energy technologies that can benefit futureCinergy business development activities.
~~Financial~~
Following are the financial results by business ~~unit are as indicated below.~~unit. Certain amounts for the prior year have been restated to reflect ~~segment restructuring which includes~~implementation of EITF 02-3 and other prior year amounts have been reclassified to conform to the ~~consolidation of all of our international operations into Energy Merchant. This restructuring became effective January 1, 2002.~~current presentation.

50

Financial results by business unit for the quarters ended ~~September 30,~~March 31, 2003, and March 31, 2002 ~~and September 30, 2001~~ are as indicated below.
Business Units

Cinergy Business Units

Energy Merchant
Regulated Businesses
Power Technology
Total
Reconciling Eliminations(1)
Consolidated

(in thousands)

Quarter ended September 30, 2002

Operating revenues—

External customers $ 3,206,647 $ 669,605 $ 9,736 $ 3,885,988 $ — $ 3,885,988
Intersegment revenues 48,444 — — 48,444 (48,444 ) —
Segment profit (loss)(2) 59,262 74,939 (3,633 ) 130,568 — 130,568

Quarter ended September 30, 2001

Operating revenues—

External customers $ 2,682,498 $ 655,005 $ 9,811 $ 3,347,314 $ — $ 3,347,314
Intersegment revenues 45,756 — — 45,756 (45,756 ) —
Segment profit (loss)(2) 57,941 77,690 (7,160 ) 128,471 — 128,471
~~(1)~~
~~The Reconciling Eliminations category eliminates the intersegment revenues of Energy Merchant.~~

~~(2)~~
~~Management utilizes segment profit (loss) to evaluate segment performance.~~
43
~~Financial results by business unit for the nine months ended September 30, 2002 and September 30, 2001 are as indicated below.~~
Business Units

Cinergy Business Units

Energy Merchant
Regulated Businesses
Power Technology
Total
Reconciling Eliminations(1)
Consolidated

(in thousands)

Nine months ended September 30, 2002

Operating revenues—

External customers $ 6,599,040 $ 1,942,789 $ 27,945 $ 8,569,774 $ — $ 8,569,774
Intersegment revenues 123,091 — — 123,091 (123,091 ) —
Segment profit (loss)(2) 115,158 176,877 (20,756 ) 271,279 — 271,279

Nine months ended September 30, 2001

Operating revenues—

External customers $ 8,642,396 $ 2,059,722 $ 34,836 $ 10,736,954 $ — $ 10,736,954
Intersegment revenues 114,482 — — 114,482 (114,482 ) —
Segment profit (loss)(2) 131,322 215,560 (15,197 ) 331,685 — 331,685
~~(1)~~
~~The Reconciling Eliminations category eliminates the intersegment revenues of Energy Merchant.~~

~~(2)~~
~~Management utilizes segment profit (loss) to evaluate segment performance.~~

Business Units

Cinergy Business Units

Energy
Merchant

Regulated
Businesses

Power
Technology

Total

Reconciling
Eliminations(1)

Consolidated

(in thousands)

Quarter ended March 31, 2003

Operating revenues-

External customers

$
447,466
(3)
$
834,315
(4)
$
1

$
1,281,782

$
—

$
1,281,782

Intersegment revenues

39,123

—

—

39,123

(39,123
)
—

Cost of sales -

Fuel and purchased and exchanged power

138,495

140,988

—

279,483

—

279,483

Gas purchased

64,230

171,765

—

235,995

—

235,995

Discontinued operations, net of tax

—

—

—

—

—

—

Cumulative effect of a change in accounting principles, net of tax

26,462

—

—

26,462

—

26,462

Segment profit (loss)(2)

97,105

74,069

(5,089
)
166,085

—

166,085

Quarter ended March 31, 2002

Operating revenues -

External customers

$
271,613

$
714,762

$
2

$
986,377

$
—

$
986,377

Intersegment revenues

36,838

—

—

36,838

(36,838
)
—

Cost of sales -

Fuel and purchased and exchanged power

107,569

121,721

—

229,290

—

229,290

Gas purchased

1,912

107,968

—

109,880

—

109,880

Discontinued operations, net of tax

478

—

—

478

—

478

Cumulative effect of a change in accounting principle, net of tax

(10,899
)
—

—

(10,899
)
—

(10,899
)

Segment profit (loss)(2)

16,638

72,797

(4,606
)
84,829

—

84,829

(1)
The Reconciling Eliminations category eliminates the intersegment revenues of Energy Merchant.
(2)
Management utilizes segment profit (loss) to evaluate segment performance.
(3)
The increase in 2003 is primarily due to the increase in the average price realized on wholesale commodity non-firm transactions and the sale of synthetic fuel which began in July 2002.
(4)
The increase in 2003 is primarily due to the increase in the average price received per thousand cubic feet (mcf) delivered reflecting a substantial increase in the wholesale gas commodity costs, which is passed directly to the retail customer dollar-for-dollar under the state mandated gas cost recovery mechanism. Also contributing to this increase was higher mcf volumes sold due to colder than normal weather.
51

Total segment assets at ~~September 30, 2002~~March 31, 2003, and December 31, ~~2001,~~2002, were as follows:

Cinergy Business Units

Business Units
Energy Merchant
Regulated Businesses
Power Technology
Total
All Other(1)
Consolidated

(in thousands)

Total segment assets at September 30, 2002 $ 5,483,625 $ 7,432,558 $ 228,549 $ 13,144,732 $ 60,808 $ 13,205,540
Total segment assets at December 31, 2001 4,956,109 7,084,104 213,260 12,253,473 46,340 12,299,813
~~(1)~~
~~The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment performance measurement.~~
44
~~10.  Earnings Per Common Share (EPS)~~Business Units

Cinergy Business Units

Energy
Merchant

Regulated
Businesses

Power
Technology

Total

All
Other(1)

Consolidated

(in thousands)

Total segment assets at March 31, 2003

$
5,305,552

$
7,902,311

$
159,185

$
13,367,048

$
51,086

$
13,418,134

Total segment assets at December 31, 2002

5,774,750

7,283,812

155,252

13,213,814

93,214

13,307,028

(1)
The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment performance measurement.
52

9.                        EPS
A reconciliation of EPS to ~~EPS—~~EPS – Assuming Dilution (EPS - assuming ~~dilution~~dilution) is presented below for the quarters ended ~~September 30, 2002~~March 31, 2003 and ~~September 30, 2001:~~March 31, 2002:

Income
Shares
EPS

(in thousands, except per share amounts)

Quarter ended September 30, 2002
EPS:
Net Income $ 130,568 167,967 $ 0.78

Effect of dilutive securities:

Common stock options 843
Directors' compensation plans 160
Contingently issuable common stock 1,118

EPS—assuming dilution:
Net income plus assumed conversions $ 130,568 170,088 $ 0.77

Quarter ended September 30, 2001

EPS:
Net Income $ 128,471 159,097 $ 0.81

Effect of dilutive securities:

Common stock options 948
Directors' compensation plans 144
Contingently issuable common stock 491

EPS—assuming dilution:
Net income plus assumed conversions $ 128,471 160,680 $ 0.80

Income

Shares

EPS

(in thousands, except per share amounts)

Quarter ended March 31, 2003

EPS:

Income before cumulative effect of a change in accounting principles

$
139,623

$
0.81

Cumulative effect of a change in accounting principles, net of tax

26,462

0.15

Net Income

$
166,085

173,387

$
0.96

Effect of dilutive securities:

Common stock options

724

Directors’ compensation plans

134

Contingently issuable common stock

717

EPS - assuming dilution:

Net income plus assumed conversions

$
166,085

174,962

$
0.95

Quarter ended March 31, 2002

EPS:

Income before discontinued operations and cumulative effect of a change in accounting principle

$
95,250

$
0.58

Discontinued operations, net of tax

478

—

Cumulative effect of a change in accounting principle, net of tax

(10,899
)

(0.06
)
Net Income

$
84,829

164,295

$
0.52

Effect of dilutive securities:

Common stock options

976

Employee stock purchase and savings plan

1

Directors’ compensation plans

151

Contingently issuable common stock

542

EPS - assuming dilution:

Net income plus assumed conversions

$
84,829

165,965

$
0.52

Options to purchase shares of common stock are excluded from the calculation of ~~EPS—~~EPS - assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period. For the quarters ended ~~September 30,~~March 31, 2003 and 2002, ~~and 2001,~~ approximately ~~3.3~~3.5 million and ~~2.1~~3.1 million shares, respectively, were excluded from the ~~EPS—~~EPS - assuming dilution calculation.
Also excluded from the ~~EPS—~~EPS - assuming dilution calculation for the ~~quarter~~quarters ended ~~September 30,~~March 31, 2003 and 2002, are up to 10.8 million shares issuable pursuant to the stock purchase contracts associated with the preferred trust securities issued byCinergy Corp. in December 2001. ~~These stock purchase contracts would impact EPS—assuming dilution only to the extent thatCinergy's~~ average stock price were to exceed $34.40 per share, which is the maximum price payable by the holders of the stock purchase contracts, during any period for which earnings per share are presented. As discussed in the 2001 Form 10-K, theThe number of shares ~~issued~~issuable pursuant to the stock purchase contracts is contingent upon the market price ofCinergy Corp. stock in February 2005 and could range between 9.2 and 10.8 million shares.
45
53

~~A reconciliation of EPS to EPS—assuming dilution is presented below for the nine months ended September 30, 2002 and September 30, 2001:~~

Income
Shares
EPS

(in thousands, except per share amounts)

Nine months ended September 30, 2002
EPS:
Net Income $ 271,279 166,544 $ 1.63

Effect of dilutive securities:

Common stock options 981
Employee stock purchase and savings plan 5
Directors' compensation plans 160
Contingently issuable common stock 1,138

EPS—assuming dilution:
Net income plus assumed conversions $ 271,279 168,828 $ 1.61

Nine months ended September 30, 2001

EPS:
Net Income $ 331,685 159,049 $ 2.08

Effect of dilutive securities:

Common stock options 1,023
Directors' compensation plans 144
Contingently issuable common stock 498

EPS—assuming dilution:
Net income plus assumed conversions $ 331,685 160,714 $ 2.06
10.                 Ohio Deregulation
Options to purchase shares of common stock are excluded from the calculation of EPS—assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period. For the nine months ended September 30, 2002 and 2001, approximately 2.7 million and 2.1 million shares, respectively, were excluded from the EPS—assuming dilution calculation.
        Also excluded from the EPS—assuming dilution calculation for the nine months ended September 30, 2002, are up to 10.8 million shares issuable pursuant to the stock purchase contracts associated with the preferred trust securities issued by~~Cinergy Corp.~~ ~~in December 2001. These stock purchase contracts would impact EPS—assuming dilution only to the extent thatCinergy's~~ ~~average stock price were to exceed $34.40 per share, which is the maximum price payable by the holders of the stock purchase contracts, during any period for which earnings per share are presented.~~ As discussed in the ~~2001 Form~~2002 10-K, CG&E is in a market development period, beginning the ~~number of shares~~transition to ~~be issued pursuant to the stock purchase contracts is contingent upon the market price ofCinergy Corp.~~ ~~stock in February 2005 and could range between 9.2 and 10.8 million shares.~~
~~11.  Ohio Deregulation~~
        ~~As discussed~~electric deregulation in the ~~2001 Form 10-K, in July 1999, Ohio Governor Robert Taft signed~~state of Ohio. The transition period is governed by 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 provides for a market development period that began January 1, 2001, and ends no later than December 31, 2005. During the market development period, electric rates to~~CG&E~~ ~~customers are frozen.~~
46

        ~~In May 2000,CG&E~~ ~~reached~~ a stipulated agreement ~~with the Public Utilities Commission of Ohio (PUCO) staff~~adopted and ~~various other interested parties with respect to its proposal to implement electric customer choice in Ohio effective January 1, 2001. In August 2000, the PUCO~~ approved~~CG&E's~~ ~~stipulation agreement. Subsequently, two parties filed applications for rehearing with~~ by the PUCO. ~~In October 2000, the PUCO denied these applications. One of the parties appealed to the Ohio Supreme Court in the fourth quarter of 2000 and~~Under CG&E&E’s ~~subsequently intervened in that case. In April 2002, the Ohio Supreme Court affirmed the PUCO's stipulated agreement withCG&E~~ ~~with respect to implementing electric customer choice. The Ohio Supreme Court ruling leavesCG&E's~~ ~~transition plan entirely intact.~~
        ~~UnderCG&E's~~ transition plan, retail customers continue to receive transportation services fromCG&E, but may purchase electricity from another supplier. Retail customers that purchase electricity from another supplier receive shopping credits fromCG&E. The shopping credits generally reflect the costs of electric generation included inCG~~&E's~~&E’s frozen rates. However, shopping credits for the first 20 percent of electricity usage in each customer class to switch suppliers are higher thanCG~~&E's~~&E’s electric generation costs in order to stimulate the development of the competitive retail electric ~~retail~~ service market.
CG&E recovers its regulatory assets and other transition costs through a Regulatory Transition Charge (RTC) paid by all retail customers. As the RTC is collected from customers, CG&E amortizes the deferred balance of regulatory assets and other transition costs. A portion of the RTC collected from customers is recognized currently as a return on the deferred balance of regulatory assets and other transition costs and as reimbursement for the difference in the shopping credits provided to customers and the wholesale revenues from switched generation. The ability of CG&E to recover its regulatory assets and other transition costs is dependent on several factors, including, but not limited to, the level of CG&E’s electric sales, prices in the wholesale power markets, and the amount of customers switching to other electric suppliers.
On January 10, 2003, CG&E filed an application with the PUCO for approval of a methodology to establish how market-based rates for non-residential customers will be determined when the market development period ends. In the filing, CG&E seeks to establish a market-based standard service offer rate for non-residential customers that do not switch suppliers and a process for establishing the competitively bid generation service option required by the Electric Restructuring Bill. As of March 31, 2003, more than 20 percent of the load in each of CG&E’s non-residential customer classes has switched to other electric suppliers. Under its transition plan, CG&E may end the market development period for those classes of customers once 20 percent switching has been achieved; however, PUCO approval of the standard service offer rate and competitive bidding process is required before the market development period can be ended. CG&E is not requesting to end the market development period for non-residential customers at this time. CG&E is unable to predict the outcome of this proceeding.
11.                 Transfer of Generating Assets
In December 2002, the IURC approved a settlement agreement among PSI, the Indiana Office of the Utility Consumer Counselor, and the IURC Testimonial Staff authorizing PSI’s purchase of the Henry County, Indiana and Butler County, Ohio, gas-fired peaking plants from two non-regulated affiliates. In February 2003, the Federal Energy Regulatory Commission (FERC) issued an order ~~that was effective April 2002, allowedCinergy~~ ~~to jointly dispatch the regulated generating assets ofPSI~~ ~~in conjunction with the deregulated generating assets ofCG&E. The order also authorizes the transfer~~under Section 203 of the Federal Power Act authorizing PSI’s~~CG&E~~ ~~generating assets to a non-regulated affiliate. However,Cinergy~~ ~~has determined that it can realize the benefits~~ acquisition of the ~~new joint dispatch agreement without transferringCG&E's~~ ~~generation assets. Therefore, whileCG&E~~ ~~will continue~~plants, which occurred on February 5, 2003. Subsequently, in April 2003, the FERC issued a tolling order allowing additional time to ~~pursue any remaining regulatory and other approvals already~~consider a request for rehearing filed in ~~process that are necessary for~~response to the ~~transfer~~February 2003 FERC order. At this time, we cannot predict the outcome of~~CG&E's~~ ~~generation assets,Cinergy~~ ~~does not plan to transferCG&E's~~ ~~generating assets to a non-regulated affiliate in the foreseeable future.~~ this matter.
47

54

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
        ~~In this report we discuss various matters that may make management's corporate vision~~This document includes forward-looking statements within the meaning of Section 27A of the ~~future clearer for you. This report outlines management's goals~~Securities Act of 1933 and ~~projections for~~Section 21E of the ~~future. These goals and projections are considered forward-looking statements and are based on management's beliefs and assumptions.~~Securities Exchange Act of 1934. These forward-looking statements are identified by terms and phrases such as ~~"anticipate"~~“anticipate”, ~~"believe"~~“believe”, ~~"intend"~~“intend”, ~~"estimate"~~“estimate”, ~~"expect"~~“expect”, ~~"continue"~~“continue”, ~~"should"~~“should”, ~~"could"~~“could”, ~~"may"~~“may”, ~~"plan"~~“plan”, ~~"project"~~“project”, ~~"predict"~~“predict”, ~~"will"~~“will”, and similar expressions.

Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ ~~are often presented with forward-looking statements. In addition, other factors could cause actual results to differ~~ materially from those indicated in any forward-looking ~~statement. These include:~~statement include, but are not limited to:
•
Factors affecting operations, such as:

(1)
~~(1)~~
~~unusual~~          unanticipated weather conditions;

(2)
~~catastrophic weather-related damage;~~

~~(3)~~
unscheduled generation outages;

~~(4)~~
(3)unusual maintenance or repairs;

~~(5)~~
(4)unanticipated changes in ~~fossil fuel~~costs;
(5)          environmental incidents, including costs ~~gas supply costs, or availability constraints;~~of compliance with existing

~~(6)~~
and future environmental ~~incidents;~~requirements; and

~~(7)~~
(6)electric transmission or gas pipeline system constraints.

•
~~State, federal and local legislative~~                  Legislative and regulatory initiatives.

•
~~The timing and extent of the entry of additional~~                  Additional competition in electric or gas markets and ~~the effects of~~ continued industry ~~consolidation through the pursuit of mergers, acquisitions, and strategic alliances.~~

consolidation.
•
Regulatory factors such as changes in the policies or procedures that set rates; changes in our ability to recover expenditures for environmental compliance, purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases.

•
Financial or regulatory accounting ~~principles or policies imposed by governing bodies.~~

principles.
•
Political, legal, and economic conditions and developments in the ~~United States (U.S.) and the foreign~~ countries in which we have a presence. ~~These would include inflation rates and monetary fluctuations.~~

•
Changing market conditions and other factors related to physical energy and financial trading activities. ~~These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.~~

•
The performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities.

•
Availability of, or cost of, capital.

•
Employee workforce ~~factors, including changes in key executives, collective bargaining agreements with union employees, and work stoppages.~~

factors.
•
~~Legal and regulatory delays~~                  Delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
48
55

•
Costs and effects of legal and administrative proceedings, settlements, investigations, and claims. Examples can be found in Note 7 of the ~~"Notes~~“Notes to Financial ~~Statements"~~Statements” in ~~"Part I.~~“Part 1. Financial ~~Information."~~

•
~~Changes in international, federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.~~
Information”.
~~Unless we otherwise have a duty~~
We undertake no obligation to ~~do so,~~update the Securities and Exchange Commission's (SEC) rules do not require forward-looking statements to be revised or updated (whether as a result of changes in actual results, changes in assumptions, or other factors affecting the statements). Our forward-looking statements reflect our best beliefs as of the time they are made and may not be updated for subsequent developments.information contained herein.
49

56

MD&A - - INTRODUCTION
ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In this reportCinergy (which includesCinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as ~~"we"~~“we”, ~~"our"~~“our”, or ~~"us"~~“us”.

The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this report and the ~~2001~~combined Form ~~10-K.~~10-K for the year ended December 31, 2002 (2002 10-K). The results discussed below are not necessarily indicative of the results that may occur in any future periods.
~~Introduction~~INTRODUCTION
In ~~Management's~~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 and capital resources and results of operations. Specifically, we discuss the following:
•
factors affecting current and future operations;

•
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.
~~Organization~~

ORGANIZATION
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 ~~SEC~~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.;

•
Cinergy Services, Inc. (Services);

•
Cinergy Investments, Inc.;

and
•
Cinergy Global Resources, Inc.~~; and~~

•
~~Cinergy Technologies, Inc.~~

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~~&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~~&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
57

MD&A - - LIQUIDITY AND CAPITAL RESOURCES
Public Utilities Commission of Ohio (PUCO) approved costs and retail electric rates are frozen during this market development period.

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

The majority of our operating revenues are derived from the sale of electricity and the sale and/or transportation of natural gas.
50

LIQUIDITY AND CAPITAL RESOURCES
Environmental Issues
Cinergy’s 2002 10-K, includes a discussion of certain environmental issues that could affect our liquidity. These include:
•Ambient Air ~~Standards~~Standards;
•                  Regional Haze;
•                  Global Climate Change; and
•                  Air Toxics Regulation.

In 1997, the Environmental Protection Agency (EPA) revised the National Ambient Air Quality Standards (NAAQS) 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 in scope. 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, and also that the EPA had improperly failed to consider the beneficial health effects of ozone (shielding from Ultraviolet-B radiation) when it established the NAAQS ozone standards. In June 1999, the EPA appealed the conclusion that its standards constituted an invalid delegation of legislative authority, but did not appeal the decision that it is required to consider the beneficial health effects of ozone when setting the NAAQS. 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.
        Following the Supreme Court's ruling, the Court of Appeals reconsidered 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. On March 26, 2002, the Court of Appeals ruled in the EPA's favor on all remaining issues. Nonetheless, before the standards can be implemented, the EPA must conduct rulemaking to: (1) assess the beneficial health effects of ozone in connection with the NAAQS ozone standards; and (2) develop an approach for implementing the ozone standard in accordance with the Supreme Court's opinion. At this time, the EPA predicts that emissions reductions will be required in the 2007-2019 timeframe, but we currently cannot predict the exact amount and timing of required reductions.
        ~~See~~addition, see Note 7 of the ~~"Notes~~“Notes to Financial ~~Statements"~~Statements” in ~~"Part I.~~“Item 1. Financial ~~Information"~~Information” contained herein, for additional ~~Environmental Issues~~information regarding other environmental items and other matters that could effect our liquidity.
Pensions
Cinergy maintains qualified defined benefit pension plans covering substantially all United States (U.S.) employees meeting certain minimum age and service requirements. Plan assets consist of investments in equity and fixed income securities. Funding for the qualified defined benefit pension plans is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. Due to the decline in market value of the investment portfolio over the last few years, assets held in trust to satisfy plan obligations have decreased. Additionally, recent decreases in long-term interest rates have the effect of increasing the measured liability for funding purposes. As a result of these events, future funding obligations could increase substantially. Cinergy’s minimum required contributions for calendar year 2003 are $11 million, as compared to $4 million for the calendar year 2002. We are considering additional discretionary contributions of up to $50 million for the calendar year 2003. The discretionary contributions would be intended to improve the overall funding of the plan.
Other Investing Activities
Our ability to invest in growth initiatives is limited by certain legal and regulatory requirements, including 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
58

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:
•                  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 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. A FUCO may not derive any income, directly or indirectly, from the generation, transmission or distribution of electric energy for sale or the distribution of gas at retail within the U.S. An entity claiming status as a FUCO must provide notification thereof to the 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 March 31, 2003, we had invested or committed to invest $1.0 billion in EWGs and FUCOs, leaving available investment capacity under the May 2001 order of $2.4 billion.
•                  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 percent 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 March 31, 2003, we had invested and/or guaranteed approximately $0.5billion of the $1.3 billion available.
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 March 31, 2003, we had $608 million outstanding under the guarantees issued, of which approximately 88 percent represents guarantees of obligations reflected on Cinergy’s Consolidated Balance Sheets. The amount outstanding represents Cinergy Corp.’s guarantees of liabilities and commitments of its
59

consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. See Note 7(a) of the “Notes to Financial Statements” in “Item 1. Financial Information” for a discussion of guarantees in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (Interpretation 45). Interpretation 45 requires disclosure of maximum potential liabilities for guarantees issued on behalf of unconsolidated subsidiaries and joint ventures and under indemnification clauses in various contracts. The Interpretation 45 disclosure differs from the PUHCA restrictions in that it requires a calculation of maximum potential liability, rather than actual amounts outstanding; it excludes guarantees issued on behalf of consolidated subsidiaries; and it includes potential liabilities under indemnification clauses.
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 March 31, 2003 trading portfolio, if such an event were to occur, Cinergy would be required to issue up to approximately $75 million in collateral related to its gas and power trading operations.
Capital Resources

We meet our current and future capital requirement needs through a combination of internally and externally generated funds, including the issuance of debt and/or equity securities.Cinergy believes that it has adequate financial resources to meet its future needs.
60

Notes Payable and Other Short-term Obligations
~~Short-term Borrowings~~
        ~~At September 30, 2002,~~We are required to secure authority to issue short-term debt from the SEC under the PUHCA and from the PUCO. The SEC under the PUHCA regulates the issuance of short-term debt by Cinergy Corp., PSI, and ULH&P. The PUCO has regulatory jurisdiction over the issuance of short-term debt by CG&E.

Short-term Regulatory Authority
March 31, 2003

(millions)

Authority

Outstanding

Cinergy Corp.

$
5,000
(1)
$
193

CG&E and subsidiaries

671

3

PSI

600

230

ULH&P

65

5

(1)
Cinergy Corp., under the PUHCA, was granted approval to increase total capitalization (excluding retained earnings and accumulated other comprehensive income (loss)), which may be any combination of debt and equity securities, by $5 billion. Outside this requirement, Cinergy Corp. is not subject to specific regulatory debt authorizations.
For the purposes of quantifying regulatory authority, short-term debt includes revolving credit borrowings, uncommitted credit line borrowings, inter-company money pool obligations, and commercial paper.
61

Cinergy Corp.’s short-term borrowing consists primarily of unsecured revolving lines of credit and the sale of commercial paper. Cinergy Corp.’s $1 billion revolving credit facilities and $800 million commercial paper program also support the short-term borrowing needs of CG&E and PSI. In addition, Cinergy, CG&E, and PSI maintain uncommitted lines of credit. These facilities are not firm sources of capital but rather informal agreements to lend money, subject to availability, with pricing determined at the time of advance. The following is a summary of outstanding short-term borrowings for Cinergy, CG&E, PSI, and ULH&P, including variable rate pollution control notes:

Short-term Borrowings
March 31, 2003

Established
Lines

Outstanding

Unused

Standby
Liquidity(3)

Available
Revolving
Lines of
Credit

(in millions)

Cinergy

Cinergy Corp.

Revolving lines

$
1,000

$
—

$
1,000

$
204

$
796

Uncommitted lines(1)

65

—

65

Commercial paper(2)

193

607

Operating companies

Uncommitted lines(1)

75

—

75

Pollution control notes

112

Non-regulated subsidiaries

Revolving lines

8

1

7

7

Short-term debt

22

22

—

Cinergy Total

$
328

$
803

CG&E and subsidiaries

Uncommitted lines(1)

$
15

$
—

$
15

Pollution control notes

112

Money pool

3

CG&E Total

$
115

PSI

Uncommitted lines(1)

$
60

$
—

$
60

Pollution control notes

—

Money pool

230

PSI Total

$
230

ULH&P

Money pool

$
5

ULH&P Total

$
5

(1)
Outstanding amounts may be greater than established lines as uncommitted lenders are, at times, willing to loan funds in excess of the established lines.
(2)
The commercial paper program is limited to $800 million and is supported by Cinergy Corp.’s revolving lines.
(3)
Standby liquidity is reserved against the revolving lines to support the commercial paper program and outstanding letters of credit (currently $193 million and $11 million, respectively).
62

At March 31, 2003, Cinergy Corp. had ~~$630~~$796 million remaining unused and available capacity relating to its $1 billion revolving credit facilities. ~~The~~These revolving credit facilities ~~are comprised of a $400 million, three-year senior revolving credit facility expiring in May 2004 and~~included the following:
Credit Facility

Expiration

Established
Lines

Outstanding
and
Committed

Unused and
Available

(in millions)

364-day senior revolving

April 2003

Direct borrowing

$

$
—

$

Commercial paper support

193

Total 364-day facility

600

193

407

Three-year senior revolving

May 2004

Direct borrowing

—

Commercial paper support

—

Letter of Credit support

11

Total three-year facility

400

11

389

Total credit facilities

$
1,000

$
204

$
796

In April 2003, Cinergy Corp. successfully placed a $600 million, 364-day senior unsecured revolving credit facility. This facility ~~expiring in February~~replaces a $600 million, 364-day facility that expired April 30, 2003. ~~At September 30, 2002, certain of our non-regulated subsidiaries had $6 million of unused and available revolving credit lines.~~
51

In our credit facilities,Cinergy Corp. has covenanted to maintain:
•
a consolidated net worth of $2 billion; and

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

A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of available credit and acceleration of the related indebtedness include:
•
bankruptcy;

•
defaults in the payment of other indebtedness; and

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

The latter two events, however, are subject to dollar-based materiality thresholds.
        ~~As of September 30, 2002, our operating companies had regulatory authority to borrow up to a total of $1.27 billion in short-term debt ($671 million forCG&E~~ ~~and its subsidiaries, including $65 million forULH&P, and $600 million forPSI). As of September 30, 2002,CG&E~~ ~~and its subsidiaries had $667 million (including $63 million forULH&P) unused and available andPSI~~ ~~had $520 million unused and available under their respective regulatory authority.~~
63
~~Uncommitted Lines~~
        ~~In addition to revolving credit facilities,Cinergy~~,~~CG&E, andPSI~~ also maintain uncommitted lines of credit represented by written, enforceable agreements. However, the lenders under such agreements are not obligated to make advances and, therefore, we pay no fees for these lines of credit. The purpose of these agreements is to provide the framework (including conditions to lending and events of default) for making borrowings at an interest rate and for a term that would be determined at the time that the borrower requests an advance. At September 30, 2002,~~Cinergy Corp.~~ ~~had uncommitted lines of $65 million, of which $45 million remained unused.CG&E~~ ~~andPSI~~ ~~have established uncommitted lines of $15 million and $60 million, respectively, all of which remained unused at September 30, 2002.~~
~~Commercial Paper~~
        ~~Cinergy Corp.~~ ~~has a commercial paper program with a maximum outstanding principal amount of $800 million. This program is supported byCinergy Corp.'s~~ ~~$1 billion revolving credit facilities. The commercial paper program at theCinergy Corp.~~ ~~level, in part, supports the short-term borrowing needs ofCG&E~~ ~~andPSI. At September 30, 2002,Cinergy Corp.~~ ~~had $311 million in commercial paper outstanding.~~
Variable Rate Pollution Control Notes

CG&E ~~andPSI~~ ~~have~~ has issued certain variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes). Because the holders of these notes have the right to ~~redeem~~have their notes redeemed on a daily, monthly, or annual basis, they are reflected inNotes payable and other short-term obligations in on the Balance Sheets forCinergy, and CG&E~~, andPSI~~. At ~~September 30, 2002,~~March 31, 2003, CG&E ~~andPSI~~ had ~~$196 million and $83~~$112 million outstanding in ~~short-term~~ variable rate pollution control notes, ~~respectively. In October 2002,~~classified as short-term debt. PSI had no outstanding short-term pollution control notes. Any short-term pollution control note borrowings outstanding do not reduce the unused and available short-term debt regulatory authority of CG&E ~~and~~, PSI ~~redeemed $84 million~~, and ~~$47.6 million, respectively,~~ULH&P. See Notes 4 and 5 of ~~variable rate~~the “Notes to Financial Statements” in “Item 1. Financial Information” for additional information regarding pollution control ~~notes (see Notes 3 and 4 of the "Notes to Financial Statements" in "Part I. Financial Information" for additional information).~~notes.
52

Money Pool

Cinergy Corp., Services, and our operating companies participate in a money pool arrangement to better manage cash and working capital requirements. Under this arrangement, those companies with surplus short-term funds provide short-term loans to affiliates (other thanCinergy Corp.) participating under this arrangement. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as a component of Notes receivable from affiliated companies and/or orNotes payable to affiliated companies on the Balance Sheets ofCG&E,PSI, andULH&P. Any money pool borrowings outstanding reduce the unused and available short-term debt regulatory authority ofCG&E,PSI, andULH&P.
.Long-term Debt
~~Capital Leases~~
        Our operating companies are able to enter into capital leases subject to the authorization limitations of the applicable state utility commissions. New financing authority is subject to the approval of the respective commissions. On May 22, 2002,~~ULH&P~~ received approval from the Kentucky Public Service Commission (KPSC) to enter into up to an additional $25 million of capital lease obligations for the period ending December 31, 2004. On June 26, 2002,~~PSI~~ ~~received approval from the Indiana Utility Regulatory Commission (IURC) to enter into an additional $100 million of capital lease obligations for the period ending December 31, 2003.~~
~~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 byCinergy 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~~
64

A summary of our long-term debt authorizations at March 31, 2003, is as follows:

Authorized

Used

Available

(in millions)

Cinergy Corp.

PUHCA total capitalization(1)

$
5,000

$
1,521

$
3,479

CG&E and subsidiaries(2)

State Public Utility Commissions

575

—

575

PSI

State Public Utility Commission

500

83

417

ULH&P

State Public Utility Commission

75

—

75

(1)
Cinergy Corp., under PUHCA, was granted approval to increase total capitalization (excluding retained earnings and accumulated other comprehensive income (loss)), which may be any combination of debt and equity securities, by $5 billion. Outside this requirement, Cinergy Corp. is not subject to specific regulatory debt authorizations.
(2)
Includes amounts for ULH&P.
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 has 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 percent of~~Cinergy Corp.'s~~ ~~consolidated capital structure and thatCinergy Corp., under certain circumstances, maintains an investment grade rating on its senior debt obligations.~~
        ~~In July 2002,CG&E~~ ~~filed a~~effective shelf registration statement with the SEC relating to the issuance of up to $750 million in any combination of common stock, preferred stock, stock purchase contracts or unsecured debt securities, of which approximately $573 million remains available for issuance. CG&E has an effective shelf registration statement with the SEC relating to the issuance of up to $500 million in any combination of unsecured debt securities, first mortgage bonds, or preferred stock, all of which remains available for issuance. PSI has an effective shelf registration statement with the SEC relating to the issuance of up to $700 million in any combination of unsecured debt securities, first mortgage bonds, or preferred ~~stock. This shelf registration statement became~~stock, all of which remains available for issuance. ULH&P has effective ~~in September 2002, and on September 23, 2002,CG&E~~ ~~sold $500 million of senior unsecured debentures thereby reducing the standby capacity of its shelf registration statement to $200 million.PSI~~ ~~maintains~~ shelf registration statements with the SEC ~~with authority remaining~~relating to ~~issue $400 million in unsecured debentures, $205 million in first mortgage bonds, and $40 million in preferred stock.ULH&P~~ ~~may issue~~the issuance of up to ~~$30~~$50 million in ~~secured or~~ unsecured debt securities and up to $40 million in first mortgage bonds, of which $30 million in unsecured debt securities and $20 million in first mortgage ~~bonds.~~bonds remain available for issuance.
~~CG&E~~,~~PSI, andULH&P~~ ~~are also subject to the various state public utility commissions for authority to issue securities. At September 30, 2002,PSI~~ ~~had authority to issue up to $452 million in any combination of unsecured debt securities or first mortgage bonds, andULH&P~~ ~~had authority to issue up to $75 million in secured or unsecured bonds. As a result of the issuance of $500 million of unsecured debentures,CG&E~~ ~~had no remaining authority for the issuance of securities.CG&E~~ ~~intends to file for additional authority from the PUCO in the fourth quarter of 2002.~~
        ~~On October 18, 2002,PSI~~ ~~filed a petition with the IURC for the purpose of securing authorization and approval to issue promissory notes toCinergy~~ ~~for the acquisition of the Butler County, Ohio and Henry County, Indiana peaking plants. These peaking plants are currently owned by indirect wholly-~~
53

~~owned subsidiaries ofCinergy. In the petition,PSI~~ ~~seeks the approval to issue two promissory notes toCinergy~~. One promissory note will be for the principal amount of $200 million with an annual interest rate of 6.302% and will mature on April 15, 2004. The second promissory note will be for the remainder of the purchase price, which will be determined by the IURC, with an annual interest rate of 6.403% and will mature on September 1, 2004. Each promissory note will be pre-payable at the option of~~PSI~~, in whole or in part, at any time before its scheduled maturity, without penalty or premium. The promissory notes will be subordinated and subject in right of payment to the full prior payment of all senior debt of~~PSI. At this time,PSI~~ ~~cannot predict the outcome of this matter. For further discussion of the acquisition, see "Transfer of Generating Assets toPSI" in "Results of Operations—Future."~~
Off-Balance Sheet Financing
As discussed in the ~~2001 Form~~2002 10-K,Cinergy uses special-purpose entities (SPE) to finance various projects. The ~~Financial Accounting Standards Board (FASB)~~FASB issued ~~an exposure draft~~Interpretation No. 46, Consolidation of Variable Interest Entities (Interpretation 46) in ~~July 2002 on a proposed~~January 2003. This interpretation ~~of consolidation accounting standards that would~~will significantly change the consolidation requirements for SPEs. We have ~~reviewed~~begun reviewing the impact of this ~~proposal~~interpretation but have not yet concluded whether consolidation of certain SPEs will be required. There are two SPEs for which consolidation may be required. These SPEs have individual power sale agreements to an unrelated third party for approximately 45 megawatts (MW) of capacity, ending in 2009, and ~~if adopted~~35 MW of capacity, ending in ~~its current form, we believe that~~2016. In addition, the SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading) to supply the power. Capital & Trading also provides various services, including certain credit support facilities.
65

Cinergy’s quantifiable exposure to loss as a result of involvement with these two SPEs is $28 million, which includes investments in these entities of $3 million and exposure under the capped credit facilities of approximately $25 million. There is also a non-capped facility, but it ~~would require~~can only be called upon in the event the SPE breaches representations, violates covenants, or other unlikely events.
If appropriate, consolidation of all ~~the~~assets and liabilities of these two SPEs, ~~discussed~~at their carrying values, will be required in the ~~2001 Form 10-K, except~~third quarter of 2003. Approximately $225 million of non-recourse debt would be included in Cinergy’s Consolidated Balance Sheets upon initial consolidation. However, the impact on results of operations would be expected to be immaterial.
Cinergy believes that its accounts receivable sale facility, as discussed in ~~Note 5 of~~ the ~~"Notes to Financial Statements" in "Part I. Financial Information." The accounts receivable sale facility~~2002 10-K, would remain unconsolidated since it involves transfers of financial assets to a qualifying SPE, which is exempted from consolidation by Statement of Financial Accounting Standards No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (Statement 140) and ~~this proposal. This exposure draft proposes that SPEs not meeting~~Interpretation 46.
Cinergy holds investments in various unconsolidated subsidiaries which are accounted for under the ~~required criteria be consolidated at fair value, effective in the second quarter of 2003 forCinergy~~.
        ~~As discussed in the 2001 Form 10-K,Cinergy~~equity method and has ~~an arrangement with an SPE that has contracted to buy five combustion turbines (turbines). In the second quarter of 2002,Cinergy~~ ~~exercised its option to purchase the contractual rights to two~~guaranteed approximately $8 million of the ~~turbines and subsequently sold those rights to third parties.Cinergy~~ ~~recognized a loss~~debt of ~~$6.9 million on~~ these ~~sales. The rights to the remaining turbines remain with the SPE.~~entities.
54
66

Securities Ratings

As of ~~September 30, 2002,~~March 31, 2003, the major credit ratings agencies rated our securities as follows:

Fitch(1)
~~Moody's(2)~~Moody’s(2)
S&P(3)
Cinergy Corp.
Corporate Credit
BBB+
Baa2
BBB+
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~~

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)~~
~~Fitch IBCA (Fitch)~~

~~(2)~~
~~Moody's Investors Service (Moody's)~~

~~(3)~~
~~Standard & Poor's Ratings Services (S&P)~~
~~The lowest investment grade credit rating for Fitch is BBB-, Moody's~~
(1)
Fitch IBCA (Fitch )
(2)
Moody’s Investors Service (Moody’s )
(3)
Standard & Poor’s Ratings Services (S&P )
The lowest investment grade credit rating for Fitch is BBB-, Moody’s is Baa3, and S&P is BBB-.
        ~~In April 2002, Moody's affirmed the credit ratings ofCinergy Corp.~~ ~~and its operating subsidiaries,CG&E~~ ~~andPSI. Moody's also removedCinergy Corp.~~ ~~from review for possible downgrade, and assigned stable outlooks to the debt and preferred stock ofCinergy Corp.~~ ~~and all of its operating subsidiaries.~~
        ~~In June 2002, S&P affirmedCinergy Corp.'s~~ ~~corporate credit rating, the rating of the company's commercial paper program, and the secured debt ratings ofCG&E~~ ~~andPSI, while lowering the credit ratings on other issuances. S&P removed all of theCinergy Corp.~~,~~CG&E, andPSI~~ ~~ratings from CreditWatch with negative implications and assigned a stable outlook.~~
        ~~Also in June 2002, Fitch affirmed the credit ratings ofCinergy Corp.~~ ~~Fitch also changed the rating outlook on these securities from negative to stable and affirmed the ratings ofCG&E~~ ~~andPSI~~.
These securities ratings may be revised or withdrawn at any time, and each rating should be evaluated independently of any other rating.
Equity Securities
As discussed in the 2002 10-K, under the SEC’s June 2000 Order, Cinergy Corp. is permitted to increase its total capitalization by $5 billion. The proceeds from any new issuances will be used for general corporate purposes.
        InOn January 15, 2003, Cinergy Corp. filed a registration statement with the SEC with respect to the issuance of common stock, preferred stock, and other securities in an aggregate offering amount of $750 million. On February ~~2002,~~5, 2003, Cinergy ~~issued 6.5~~ sold 5.7 million shares of common stock of Cinergy Corp.with net proceeds of approximately ~~$200 million. As discussed in the 2001 Form 10-K, in November 2001,Cinergy~~ ~~chose to~~$175 million under this registration statement.
55

~~reinstitute the practice of issuing newCinergy Corp.~~ ~~common shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan.~~ See Note 2 of the ~~"Notes~~“Notes to Financial ~~Statements"~~Statements” in ~~"Part I.~~“Part 1. Financial ~~Information"~~Information” for additional information ~~on issued shares.~~
        ~~In July 2002,Cinergy~~ ~~announced that it is implementing a policy that will generally prohibit executive officers and directors from selling~~regarding other common stock ~~acquired by exercising options until 90 days after they leave the company or board.~~issuances.
67

~~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 a SEC order under the PUHCA, which limits the amount we can have outstanding under guarantees at any one time to $2 billion. As of September 30, 2002, we had $547 million outstanding under the guarantees issued, of which approximately 75 percent represents guarantees of obligations reflected on~~Cinergy's~~ ~~Consolidated Balance Sheets. These outstanding guarantees relate to subsidiary and joint venture indebtedness and performance commitments.~~
~~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 September 30, 2002 trading portfolio, if such an event were to occur,~~Cinergy~~ ~~would be required to issue up to approximately $48 million in collateral related to its gas and power trading operations in connection with a downgrade to anything below an investment grade rating.~~
56

MD&A - - ~~2002~~ QUARTERLY RESULTS OF ~~OPERATIONS—~~OPERATIONS - HISTORICAL
2003 QUARTERLY RESULTS OF OPERATIONS - HISTORICAL
Summary of Results
Electric and gas gross margins and net income forCinergy,CG&E, andPSI for the quarters ended ~~September 30,~~March 31, 2003 and 2002 ~~and 2001~~ were as follows:

Cinergy(1)

CG&E and subsidiaries

PSI

Cinergy(1)
CG&E and subsidiaries
PSI

2003

2002

2003

2002

2003

2002

2002
2001
2002
2001
2002
2001

(in thousands)

(in thousands)

Electric gross margin $ 683,322 $ 650,671 $ 356,158 $ 345,546 $ 302,089 $ 268,122

$
557,400

$
550,086

$
298,010

$
290,871

$
244,816

$
243,352

Gas gross margin 37,904 25,020 28,858 28,488 — —

162,918

80,184

103,511

71,641

—

—

Net income 130,568 128,471 71,769 89,390 67,643 56,454

166,085

84,829

117,236

77,585

33,727

38,083

Net income for the ~~third~~first quarter of ~~2002~~2003 was ~~$131~~$166 million ($~~.77~~.95 per share on a diluted basis) as compared to ~~$128~~$85 million ($~~.80~~.52 per share on a diluted basis) for the same period last year. Income before taxes for the period was ~~$176~~$198 million compared to ~~$208~~$150 million for the same period a year ago. Increased gross margins, primarily from wholesale and retail gas operations, were partially offset by higher operating costs. These gas margins primarily reflect the results of our domestic gas trading operation, Cinergy Marketing & Trading, LP (Marketing & Trading) as well as an increased volume of retail sales due to colder than normal weather during the quarter. Also contributing to the gas margin increase over 2002 was the impact of accounting changes that required certain gas contracts and inventory to be accounted for on the accrual basis beginning in 2003. Cinergy’s ~~Cinergy's~~increased income also reflects a ~~reduction~~net gain resulting from the implementation of certain accounting changes, which have been reflected as a cumulative effect of a change in ~~income taxes primarily related~~accounting principles. See Note 1(j)(viii) of the “Notes to ~~tax credits associated with the production of synthetic fuel, beginning~~Financial Statements” in ~~July 2002.~~“Item 1. Financial Information” for further information regarding these accounting changes.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

ITEM 2. MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

IntroductionINTRODUCTION

ORGANIZATION

67

2003 QUARTERLY RESULTS OF OPERATIONS - HISTORICAL

Summary of Results

OtherGas Operating Revenues

Other Revenues

Operating Expenses

Depreciation

SIGNATURES

	Registrant			Description	Shares

Cinergy Corp.		Par value $.01 per share	~~168,326,377~~ 176,091,329

The Cincinnati Gas & Electric Company		Par value $8.50 per share	89,663,086

PSI Energy, Inc.		Without par value, stated value $.01 per share	53,913,701

The Union Light, Heat and Power Company		Par value $15.00 per share	585,333

Item Number				Page Number
PART I FINANCIAL INFORMATION
1	Financial Statements
		*Cinergy Corp.*		1
			Consolidated Statements of Income	2
			Consolidated Balance Sheets	3
			Consolidated Statements of Changes in Common Stock Equity	5
			Consolidated Statements of Cash Flows	7
		*The Cincinnati Gas & Electric Company*
			Consolidated Statements of Income and Comprehensive Income	9
			Consolidated Balance Sheets	10
			Consolidated Statements of Cash Flows	12
		*PSI Energy, Inc.*
			Consolidated Statements of Income and Comprehensive Income	14
			Consolidated Balance Sheets	15
			Consolidated Statements of Cash Flows	17
		*The Union Light, Heat and Power Company*
			Statements of Income	19
			Balance Sheets	20
			Statements of Cash Flows	22
	Notes to Financial Statements			23
	Cautionary Statements Regarding Forward-Looking Information			48
2	Management's Discussion and Analysis of Financial Condition and Results of Operations
			Introduction	50
			Organization	50
			Liquidity and Capital Resources	51
			2002 Quarterly Results of Operations—Historical	57
			2002 Year to Date Results of Operations—Historical	61
			Results of Operations—Future	66
3	Quantitative and Qualitative Disclosures About Market Risk			80
4	Controls and Procedures			80
PART II OTHER INFORMATION
1	Legal Proceedings			80
6	Exhibits and Reports on Form 8-K			81
	Signatures			82
	Certifications			83

Item Number
PART I FINANCIAL INFORMATION

1	Financial Statements
		*Cinergy Corp.*
			Consolidated Statements of Income
			Consolidated Balance Sheets
			Consolidated Statements of Changes in Common Stock Equity
			Consolidated Statements of Cash Flows

		*The Cincinnati Gas & Electric Company*
			Consolidated Statements of Income and Comprehensive Income
			Consolidated Balance Sheets
			Consolidated Statements of Cash Flows

		*PSI Energy, Inc.*
			Consolidated Statements of Income and Comprehensive Income
			Consolidated Balance Sheets
			Consolidated Statements of Cash Flows

		*The Union Light, Heat and Power Company*
			Statements of Income
			Balance Sheets
			Statements of Cash Flows

	Notes to Financial Statements

	Cautionary Statements Regarding Forward-Looking Information

2	Management’s Discussion and Analysis of Financial Condition and Results of Operations
			Introduction
			Organization
			Liquidity and Capital Resources
			2003 Quarterly Results of Operations - Historical
			Results of Operations - Future

3	Quantitative and Qualitative Disclosures About Market Risk

4	Controls and Procedures

PART II OTHER INFORMATION

1	Legal Proceedings

4	Submission of Matters to a Vote of Security Holders

6	Exhibits and Reports on Form 8-K

	Signatures

	Certifications

			Quarter Ended September 30					Year to Date September 30
			2002		2001			2002		2001
			(in thousands, except per share amounts) (unaudited)
Operating Revenues (Note 1(d))
	Electric		$	2,554,687	$	2,539,365		$	5,178,481	$	6,838,286
	Gas			1,281,411		786,345			3,301,625		3,836,946
	Other			49,890		21,604			89,668		61,722

		Total Operating Revenues		3,885,988		3,347,314			8,569,774		10,736,954
Operating Expenses
	Fuel and purchased and exchanged power (Note 1(d))			1,871,365		1,888,694			3,357,585		5,131,209
	Gas purchased (Note 1(d))			1,243,507		761,325			3,142,899		3,667,603
	Operation and maintenance			365,373		265,518			973,165		782,073
	Depreciation			103,565		97,109			303,996		277,876
	Taxes other than income taxes			64,890		59,325			201,559		175,826

		Total Operating Expenses		3,648,700		3,071,971			7,979,204		10,034,587
Operating Income				237,288		275,343			590,570		702,367
Equity in Earnings (Losses) of Unconsolidated Subsidiaries				3,248		(4,333	)		7,956		(3,500	)
Miscellaneous—Net				5,035		5,366			888		13,845
Interest				63,543		68,762			186,414		200,379
Preferred Dividend Requirement of Subsidiary Trust				5,966		—			17,847		—
Income Before Taxes				176,062		207,614			395,153		512,333
Income Taxes				44,635		78,284			121,299		178,073
Preferred Dividend Requirements of Subsidiaries				859		859			2,575		2,575

Net Income			$	130,568	$	128,471		$	271,279	$	331,685

Average Common Shares Outstanding				167,967		159,097			166,544		159,049
Earnings Per Common Share(Note 10)
	Net Income		$	0.78	$	0.81		$	1.63	$	2.08
Earnings Per Common Share—Assuming Dilution (Note 10)
	Net Income		$	0.77	$	0.80		$	1.61	$	2.06
Dividends Declared Per Common Share			$	0.45	$	0.45		$	1.35	$	1.35

	Quarter Ended March 31
	2003		2002
	(in thousands, except per share amounts)
	(unaudited)
Operating Revenues (Note 3)
Electric	$	836,883	$	779,376
Gas	398,913		190,064
Other	45,986		16,937
Total Operating Revenues	1,281,782		986,377

Operating Expenses
Fuel and purchased and exchanged power (Note 3)	279,483		229,290
Gas purchased (Note 3)	235,995		109,880
Operation and maintenance	326,661		262,578
Depreciation	106,023		98,566
Taxes other than income taxes	77,749		72,422
Total Operating Expenses	1,025,911		772,736

Operating Income	255,871		213,641

Equity in Earnings (Losses) of Unconsolidated Subsidiaries	592		4,689
Miscellaneous - Net	8,375		(1,309		)
Interest	60,564		61,223
Preferred Dividend Requirement of Subsidiary Trust	5,970		5,913

Income Before Taxes	198,304		149,885

Income Taxes	57,823		53,777
Preferred Dividend Requirements of Subsidiaries	858		858

Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles	139,623		95,250

Discontinued operations, net of tax	—		478
Cumulative effect of a change in accounting principles, net of tax (Note 1(j)(viii))	26,462		(10,899		)
Net Income	$	166,085	$	84,829

Average Common Shares Outstanding	173,387		164,295

Earnings Per Common Share (Note 9)
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles	$	0.81	$	0.58
Discontinued operations, net of tax	—		—
Cumulative effect of a change in accounting principles, net of tax	0.15		(0.06		)
Net Income	$	0.96	$	0.52

Earnings Per Common Share - Assuming Dilution (Note 9)
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principles	$	0.80	$	0.58
Discontinued operations, net of tax	—		—
Cumulative effect of a change in accounting principles, net of tax	0.15		(0.06		)
Net Income	$	0.95	$	0.52

Dividends Declared Per Common Share	$	0.46	$	0.45

				September 30 2002		December 31 2001
				(dollars in thousands) (unaudited)
ASSETS
Current Assets
	Cash and cash equivalents			$	119,267	$	111,067
	Restricted deposits				142,120		8,055
	Notes receivable (Note 5)				78,946		31,173
	Accounts receivable less accumulated provision for doubtful accounts of $17,943 at September 30, 2002, and $35,580 at December 31, 2001 (Note 5)				1,459,804		1,123,214
	Materials, supplies, and fuel—at average cost				308,438		240,812
	Energy risk management current assets (Note 1(c))				363,132		449,397
	Prepayments and other				133,505		110,311

			Total Current Assets		2,605,212		2,074,029
Property, Plant, and Equipment—at Cost
	Utility plant in service				8,547,851		8,089,961
	Construction work in progress				366,099		464,560

		Total Utility Plant			8,913,950		8,554,521
	Non-regulated property, plant, and equipment				4,702,486		4,527,994
	Accumulated depreciation				5,087,644		4,845,620

			Net Property, Plant, and Equipment		8,528,792		8,236,895
Other Assets
	Regulatory assets				1,049,266		1,015,863
	Investments in unconsolidated subsidiaries				383,942		339,059
	Energy risk management non-current assets (Note 1(c))				161,995		134,445
	Other investments				167,615		164,155
	Goodwill				55,163		53,587
	Other intangible assets				21,024		22,250
	Other				232,531		259,530

			Total Other Assets		2,071,536		1,988,889
Total Assets				$	13,205,540	$	12,299,813

	March 31 2003		December 31 2002
	(in thousands)
	(unaudited)

Current Assets
Cash and cash equivalents	$	259,159	$	221,083
Restricted deposits	8,221		8,116
Notes receivable	96,884		135,873
Accounts receivable less accumulated provision for doubtful accounts of $12,881 at March 31, 2003, and $16,374 at December 31, 2002	1,383,244		1,292,410
Materials, supplies, and fuel (Note 1(d))	245,061		319,456
Energy risk management current assets (Note 1(c))	439,358		464,028
Prepayments and other	108,367		118,208
Total Current Assets	2,540,294		2,559,174

Property, Plant, and Equipment - at Cost
Utility plant in service	9,100,552		8,641,351
Construction work in progress	508,021		469,300
Total Utility Plant	9,608,573		9,110,651
Non-regulated property, plant, and equipment	4,355,409		4,704,904
Accumulated depreciation (Note 1(j)(iii))	5,184,319		5,166,881
Net Property, Plant, and Equipment	8,779,663		8,648,674

Other Assets
Regulatory assets	1,016,477		1,022,696
Investments in unconsolidated subsidiaries	427,378		417,188
Energy risk management non-current assets (Note 1(c))	92,631		162,773
Other investments	165,130		163,851
Goodwill	43,717		43,717
Other intangible assets	14,117		14,736
Other	336,811		273,099
Total Other Assets	2,096,261		2,098,060

Assets of Discontinued Operations	1,916		1,120

Total Assets	$	13,418,134	$	13,307,028

			September 30 2002			December 31 2001
			(dollars in thousands) (unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts payable		$	1,448,647		$	1,029,173
	Accrued taxes			107,000			195,976
	Accrued interest			43,076			56,216
	Notes payable and other short-term obligations (Note 4)			714,125			1,155,786
	Long-term debt due within one year (Note 4)			22,387			148,431
	Energy risk management current liabilities (Note 1(c))			316,179			429,794
	Other			108,768			127,375

		Total Current Liabilities		2,760,182			3,142,751
Non-Current Liabilities
	Long-term debt (Note 3)			4,248,961			3,596,730
	Deferred income taxes			1,531,030			1,301,407
	Unamortized investment tax credits			120,416			127,385
	Accrued pension and other postretirement benefit costs			488,276			438,962
	Energy risk management non-current liabilities (Note 1(c))			115,212			135,619
	Other			315,918			246,340

		Total Non-Current Liabilities		6,819,813			5,846,443
Total Liabilities				9,579,995			8,989,194
Preferred Trust Securities
	Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company			307,752			306,327
Cumulative Preferred Stock of Subsidiaries
	Not subject to mandatory redemption			62,828			62,833
Common Stock Equity (Note 2)
	Common stock—$.01 par value; authorized shares—600,000,000; outstanding shares—168,267,726 at September 30, 2002, and 159,402,839 at December 31, 2001			1,683			1,594
	Paid-in capital			1,889,119			1,619,659
	Retained earnings			1,385,887			1,337,135
	Accumulated other comprehensive income (loss)			(21,724	)		(16,929	)

		Total Common Stock Equity		3,254,965			2,941,459
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholders' Equity			$	13,205,540		$	12,299,813

			Common Stock		Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
			(dollars in thousands) (unaudited)
Quarter Ended September 30, 2002
Balance at July 1, 2002			$	1,675	$	1,861,689		$	1,330,780		$	(4,787	)	$	3,189,357
Comprehensive income:
	Net income								130,568						130,568
	Other comprehensive income (loss), net of tax effect of $12,501
		Foreign currency translation adjustment (Note 1(g))										4,810			4,810
		Unrealized gain (loss) on investment trusts										(3,003	)		(3,003	)
		Cash flow hedges (Note 1(b))										(18,744	)		(18,744	)

	Total comprehensive income														113,631
Issuance of 781,597 shares of common stock—net				8		22,888									22,896
Dividends on common stock ($.45 per share)									(75,469	)					(75,469	)
Other						4,542			8						4,550

Ending balance at September 30, 2002			$	1,683	$	1,889,119		$	1,385,887		$	(21,724	)	$	3,254,965

Quarter Ended September 30, 2001
Balance at July 1, 2001			$	1,591	$	1,623,458		$	1,240,761		$	(16,927	)	$	2,848,883
Comprehensive income:
	Net income								128,471						128,471
	Other comprehensive income (loss), net of tax effect of ($854)
		Foreign currency translation adjustment (Note 1(g))										7,664			7,664
		Unrealized gain (loss) on investment trusts										(1,191	)		(1,191	)
		Minimum pension liability adjustment										(4	)		(4	)
		Cash flow hedges (Note 1(b))										(4,085	)		(4,085	)

	Total comprehensive income														130,855
Issuance of 11,105 shares of common stock—net						587									587
Treasury shares reissued						(190	)								(190	)
Dividends on common stock ($.45 per share)									(71,593	)					(71,593	)
Other						1,488			9						1,497

Ending balance at September 30, 2001			$	1,591	$	1,625,343		$	1,297,648		$	(14,543	)	$	2,910,039

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(in thousands)
	(unaudited)

Quarter Ended March 31, 2003

Balance at January 1, 2003 (168,663,115 shares)	$	1,687	$	1,918,136	$	1,403,453		$	(29,800	)	$	3,293,476
Comprehensive income:
Net income					166,085						166,085
Other comprehensive income (loss), net of tax effect of ($275)
Foreign currency translation adjustment								2,090			2,090
Unrealized gain (loss) on investment trusts								(851		)	(851		)
Cash flow hedges (Note 1(j)(iv))								(452		)	(452		)
Total comprehensive income											166,872

Issuance of common stock - net (7,213,804 shares)	72		193,896								193,968
Dividends on common stock ($.46 per share)					(77,685		)				(77,685		)
Other			4,190		8						4,198

Ending balance at March 31, 2003 (175,876,919 shares)	$	1,759	$	2,116,222	$	1,491,861		$	(29,013	)	$	3,580,829

Quarter Ended March 31, 2002

Balance at January 1, 2002 (159,402,839 shares)	$	1,594	$	1,619,659	$	1,337,135		$	(16,929	)	$	2,941,459
Comprehensive income:
Net income					84,829						84,829
Other comprehensive income (loss), net of tax effect of $1,084
Foreign currency translation adjustment								(1,584		)	(1,584		)
Unrealized gain (loss) on investment trusts								(1,051		)	(1,051		)
Minimum pension liability adjustment								136			136
Cash flow hedges (Note 1(j)(iv))								240			240
Total comprehensive income											82,570

Issuance of common stock - net (7,423,257 shares)	75		215,894								215,969
Dividends on common stock ($.45 per share)					(71,882		)				(71,882		)
Other			3,785		8						3,793

Ending balance at March 31, 2002 (166,826,096 shares)	$	1,669	$	1,839,338	$	1,350,090		$	(19,188	)	$	3,171,909

			Common Stock		Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
			(dollars in thousands) (unaudited)
Nine Months Ended September 30, 2002
Balance at January 1, 2002			$	1,594	$	1,619,659		$	1,337,135		$	(16,929	)	$	2,941,459
Comprehensive income:
	Net income								271,279						271,279
	Other comprehensive income (loss), net of tax effect of $7,879
		Foreign currency translation adjustment (Note 1(g))										20,123			20,123
		Unrealized gain (loss) on investment trusts										(4,637	)		(4,637	)
		Minimum pension liability adjustment										136			136
		Cash flow hedges (Note 1(b))										(20,417	)		(20,417	)

	Total comprehensive income														266,484
Issuance of 8,864,887 shares of common stock—net				89		258,300									258,389
Dividends on common stock ($1.35 per share)									(222,551	)					(222,551	)
Other						11,160			24						11,184

Ending balance at September 30, 2002			$	1,683	$	1,889,119		$	1,385,887		$	(21,724	)	$	3,254,965

Nine Months Ended September 30, 2001
Balance at January 1, 2001			$	1,590	$	1,619,153		$	1,179,113		$	(10,895	)	$	2,788,961
Comprehensive income:
	Net income								331,685						331,685
	Other comprehensive income (loss), net of tax effect of $490
		Foreign currency translation adjustment (Note 1(g))										4,959			4,959
		Unrealized gain (loss) on investment trusts										(1,334	)		(1,334	)
		Cumulative effect of change in accounting principle										(2,500	)		(2,500	)
		Minimum pension liability adjustment										64			64
		Cash flow hedges (Note 1(b))										(4,837	)		(4,837	)

	Total comprehensive income														328,037
Issuance of 131,497 shares of common stock—net				1		4,278									4,279
Treasury shares purchased						(10,015	)								(10,015	)
Treasury shares reissued						5,810									5,810
Dividends on common stock ($1.35 per share)									(214,689	)					(214,689	)
Other						6,117			1,539						7,656

Ending balance at September 30, 2001			$	1,591	$	1,625,343		$	1,297,648		$	(14,543	)	$	2,910,039

	Quarter Ended March 31
	2003			2002
	(in thousands)
	(unaudited)

Operating Activities
Net income	$	166,085		$	84,829
Items providing or (using) cash currently:
Depreciation	106,023			98,566
Loss (gain) on discontinued operations, net of tax	—			(478		)
Cumulative effect of a change in accounting principles, net of tax	(26,462		)	10,899
Change in net position of energy risk management activities	9,730			(50,005		)
Deferred income taxes and investment tax credits - net	18,013			2,594
Equity in (earnings) losses of unconsolidated subsidiaries	(592		)	(4,689		)
Allowance for equity funds used during construction	(3,579		)	(2,850		)
Regulatory assets deferrals	(20,588		)	(17,665		)
Regulatory assets amortization	27,966			29,976
Accrued pension and other postretirement benefit costs	15,954			(105		)
Deferred costs under gas recovery mechanism	(38,659		)	5,955
Changes in current assets and current liabilities:
Restricted deposits	(105		)	(728		)
Accounts and notes receivable	(51,845		)	76,442
Materials, supplies, and fuel	74,395			22,459
Prepayments	1,382			1,101
Accounts payable	133,402			(29,497		)
Accrued taxes and interest	(23,189		)	50,274
Other assets	3,489			13,449
Other liabilities	6,045			(6,918		)

Net cash provided by (used in) operating activities	397,465			283,609

Financing Activities
Change in short-term debt	(340,357		)	(205,918		)
Issuance of long-term debt	35,000			—
Redemption of long-term debt	(11,270		)	(30,722		)
Retirement of preferred stock of subsidiaries	—			(2		)
Issuance of common stock	193,968			215,969
Dividends on common stock	(77,685		)	(71,882		)

Net cash provided by (used in) financing activities	(200,344		)	(92,555		)

Investing Activities
Construction expenditures (less allowance for equity funds used during construction)	(151,187		)	(187,678		)
Acquisitions and other investments	(7,858		)	(18,125		)

Net cash provided by (used in) investing activities	(159,045		)	(205,803		)

Net increase (decrease) in cash and cash equivalents	38,076			(14,749		)

Cash and cash equivalents at beginning of period	221,083			111,067

Cash and cash equivalents at end of period	$	259,159		$	96,318

Supplemental Disclosure of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized)	$	67,259		$	48,373
Income taxes	$	66,477		$	19,242

			September 30 2002			December 31 2001
			(dollars in thousands) (unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
	Accounts payable		$	531,770		$	352,450
	Accounts payable to affiliated companies			65,802			30,419
	Accrued taxes			111,549			116,616
	Accrued interest			14,336			16,570
	Notes payable and other short-term obligations (Note 4)			196,100			196,100
	Notes payable to affiliated companies (Note 4)			2,915			444,801
	Long-term debt due within one year (Note 4)			—			100,000
	Energy risk management current liabilities (Note 1(c))			19,757			23,341
	Other			37,662			33,217

		Total Current Liabilities		979,891			1,313,514
Non-Current Liabilities
	Long-term debt (Note 3)			1,689,389			1,105,333
	Deferred income taxes			865,925			779,295
	Unamortized investment tax credits			86,709			91,246
	Accrued pension and other postretirement benefit costs			172,459			165,326
	Energy risk management non-current liabilities (Note 1(c))			23,063			41,773
	Other			138,966			105,681

		Total Non-Current Liabilities		2,976,511			2,288,654
Total Liabilities				3,956,402			3,602,168
Cumulative Preferred Stock
	Not subject to mandatory redemption			20,485			20,486
Common Stock Equity
	Common stock—$8.50 par value; authorized shares—120,000,000; outstanding shares—89,663,086 at September 30, 2002, and December 31, 2001			762,136			762,136
	Paid-in capital			571,926			571,926
	Retained earnings			471,384			408,706
	Accumulated other comprehensive income (loss)			(25,351	)		(5,678	)

		Total Common Stock Equity		1,780,095			1,737,090
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholder's Equity			$	5,756,982		$	5,359,744

	September 30, 2002
	Quarter Ended		Year to Date
	*(in millions)*
Cinergy(1)	$	1,098	$	2,986
CG&Eand subsidiaries		526		1,566
PSI		472		1,222

		Quarter Ended March 31
		(in millions, except per share amounts)
		2003		2002

Net income, as reported		$	166	$	85

Add:	Stock-based employee compensation expense included in reported net income, net of related tax effects.	4		3

Deduct:	Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects.	5		3

Pro-forma net income		$	165	$	85

EPS - as reported		$	0.96	$	0.52
EPS - pro-forma		$	0.95	$	0.52

EPS Assuming Dilution - as reported		$	0.95	$	0.52
EPS Assuming Dilution - pro-forma		$	0.94	$	0.52

	2003		2002
	(in millions)

Cinergy	$	119	$	123
CG&E and subsidiaries	67		68
PSI	52		55
ULH&P	12		11

	Cinergy(1)			CG&E and subsidiaries			PSI
	(in thousands)

Electric Operating Revenues as previously reported	$	1,283,424		$	635,886		$	629,844

Adjustment for effect of EITF 02-3 implementation	(492,921		)	(237,767		)	(263,443		)
Other(2)	(11,127		)	—			—

Electric Operating Revenues as adjusted	779,376			398,119			366,401

Gas Operating Revenues as previously reported	903,261			179,609			—

Adjustment for effect of EITF 02-3 implementation	(713,197		)	—			—

Gas Operating Revenues as adjusted	190,064			179,609			—

Fuel and purchased and exchanged power expense as previously reported	727,547			345,015			386,492

Adjustment for effect of EITF 02-3 implementation	(492,921		)	(237,767		)	(263,443		)
Other(2)	(5,336		)	—			—

Fuel and purchased and exchanged power expense as adjusted	229,290			107,248			123,049

Gas purchased expense as previously reported	823,077			107,968			—

Adjustment for effect of EITF 02-3 implementation	(713,197		)	—			—

Gas purchased expense as adjusted	109,880			107,968			—


(1)	The results of Cinergy also include amounts related to non-registrants and include the elimination of certain intercompany amounts.
(2)	Item represents amounts reclassified to Discontinued operations, net of tax.

Principal Amount	Interest Rate		Maturity Date
(in millions)

$2.0	8.37	%	11/08/2006
5.0	8.81		05/16/2022
3.0	8.80		05/18/2022
16.8	8.67		06/01/2022

Credit Facility	Expiration	Established Lines		Outstanding and Committed		Unused and Available
		(in millions)

364-day senior revolving	April 2003
Direct borrowing		$		$	—	$
Commercial paper support				193

Total 364-day facility		600		193		407

Three-year senior revolving	May 2004
Direct borrowing				—
Commercial paper support				—
Letter of Credit support				11

Total three-year facility		400		11		389

Total credit facilities		$	1,000	$	204	$	796