CINergy 8K Financial statements and exhibits | CIN 19 Feb 02

QuickLinks -- Click here to rapidly navigate through this document

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

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

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

INTRODUCTION

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

•: factors affecting current and future operations;
•: what our expenditures for construction and other commitments were during 2001, and what we expect them to be in 2002-2006;
•: potential sources of cash for future capital expenditures;
•: why revenues and expenses changed from period to period; and
•: how the above items affect our overall financial condition.

LIQUIDITY AND CAPITAL RESOURCES

Comparative Cash Flow Analysis

Cinergy

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

The Cincinnati Gas & Electric Company (CG&E)

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

PSI Energy, Inc. (PSI)

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

Operating Activities

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

Net Cash Provided by (Used in) Operating Activities

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

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

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

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

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

Financing Activities

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

Net Cash Provided by (Used in) Financing Activities

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

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

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

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

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

Investing Activities

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

Net Cash Used in Investing Activities

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

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

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

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

Capital Requirements

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

Actual Capital and Investment Expenditures and Future Projections

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

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

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

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

Environmental Commitment and Contingency Issues

EPA Agreement

On December 21, 2000,Cinergy,CG&E, andPSIreached an agreement in principle with the EPA, the U.S. Department of Justice, three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of Clean Air Act Amendments claims and other related matters brought against coal-fired power plants owned and operated byCinergy'soperating companies. The estimated cost for these capital expenditures is expected to be approximately $700 million. These capital expenditures are in addition to our previously announced commitment to install NO_X controls at an estimated cost of approximately $800 million (in nominal dollars) between 2001 and 2005. In 2001, we spent $260 million for NO_X and other environmental compliance projects. Forecasted expenditures for NO_X and other environmental compliance projects (in nominal dollars) are approximately $250 million for 2002 and $600 million for the 2002-2006 period. See Note 13 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the EPA Agreement and related environmental issues.

Manufactured Gas Plant (MGP) Sites

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

and compensatePSIfor its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. At the present time,PSIcannot predict the outcome of this litigation. See Note 13(g) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further information.

Ambient Air Standards

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

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

Regional Haze

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

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

Global Climate

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

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

•: implementing cost-effective greenhouse gas emission reduction and offsetting activities;
•: funding research of more efficient and alternative electric generating technologies;
•: funding research to better understand the causes and consequences of climate change;
•: encouraging a global discussion of the issues and how best to manage them; and
•: advocating comprehensive legislation for fossil-fired power plants.

Mercury

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

Other Investing Activities

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

1.: Exempt Wholesale Generators (EWG) and Foreign Utility Companies (FUCO)

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

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

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

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

2.: Qualifying Facilities and Energy-Related Non-utility Entities

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

Financing Obligations

The following table presentsCinergy's,PSI's,CG&E's, andULH&P'sfinancing obligations:

			Payments Due by Period
Financing Obligations			Payments Due by Period
Financing Obligations			2002		2003			2004		2005			2006		Thereafter			Total
			(in millions)
Cinergy(1)
	Notes payable and other short-term obligations		$	877	$	—		$	—	$	—		$	—	$	279	(2)	$	1,156
	Capital lease obligations			3		3			3		3			4		19			35
	Operating leases			45		36			26		21			18		61			207
	Long-term debt (including due within one year)			148		192	(3)		814		203	(4)(5)		334		2,065			3,756
	Preferred trust securities			—		—			—		—			—		316			316

		Total Cinergy	$	1,073	$	231		$	843	$	227		$	356	$	2,740		$	5,470

CG&Eand subsidiaries
	Notes payable and other short-term obligations(6)		$	445	$	—		$	—	$	—		$	—	$	196	(2)	$	641
	Capital lease obligations			1		2			2		2			2		11			20
	Operating leases			20		15			10		7			6		15			73
	Long-term debt (including due within one year)			100		120	(3)		110		150	(5)		—		728			1,208

		Total CG&Eand subsidiaries	$	566	$	137		$	122	$	159		$	8	$	950		$	1,942

PSI
	Notes payable and other short-term obligations(6)		$	43	$	—		$	—	$	—		$	—	$	83	(2)	$	126
	Capital lease obligations			2		1			1		1			2		8			15
	Operating leases			17		14			9		7			7		23			77
	Long-term debt (including due within one year)			23		58			1		51	(4)		328		895			1,356

		Total PSI	$	85	$	73		$	11	$	59		$	337	$	1,009		$	1,574

ULH&P
	Notes payable and other short-term obligations(6)		$	26	$	—		$	—	$	—		$	—	$	—		$	26
	Capital lease obligations			—		—			1		1			1		3			6
	Operating leases			1		1			—		—			—		—			2
	Long-term debt			—		20			—		—			—		55			75

		Total ULH&P	$	27	$	21		$	1	$	1		$	1	$	58		$	109

(1): Includes amounts for non-registrants.
(2): Includes Variable Rate Pollution Control Notes depicted according to scheduled maturities, which the holders have the right to redeem on any business day, with the remainder being redeemable annually. See Variable Rate Pollution Control Notes below.
(3): Includes 6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.
(4): Includes 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate resets on August 1, 2005.

(5): Includes 6.90% Debentures due June 1, 2025, reflected as maturing in 2005, as the debentures are putable toCG&Eat the option of the holders on June 1, 2005.
(6): Includes netNotes receivable from/Notes payable to affiliated companies.

Capital Resources

Notes Payable and Other Short-term Obligations

Short-term Borrowings

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

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

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

Uncommitted Lines

In addition to revolving credit facilities,Cinergy,CG&E, andPSIalso maintain uncommitted lines of credit. These facilities are not firm sources of capital and represent an informal agreement to lend money, subject to availability, with pricing to be determined at the time of advance. At December 31, 2001,Cinergy Corp.'s$40 million uncommitted line andCG&E's$15 million uncommitted line were unused.PSI'suncommitted line of $60 million was fully drawn at year-end.

Commercial Paper

In early 2001,Cinergy Corp.expanded the commercial paper program to a maximum outstanding principal amount of $800 million and reduced the established lines of credit atCG&EandPSI. The expansion of the commercial paper program at theCinergy Corp.level will, in part, support the short-term borrowing needs ofCG&EandPSIand will eliminate the need for separate commercial paper programs. As of December 31, 2001,Cinergy Corp.'scommercial paper program was supported by $1.2 billion in revolving credit facilities, of which it had $125 million in commercial paper outstanding.

Variable Rate Pollution Control Notes

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

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

Money Pool

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

Capital Leases

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

Operating Leases

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

Long-term Debt

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

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

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

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

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

Off-Balance Sheet Financing

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

(i) Power Sales

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

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

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

(ii) Leasing

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

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

(iii) Sales of Accounts Receivable

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

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

Securities Ratings

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

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

(1): Moody's Investors Service (Moody's)
(2): Standard & Poor's Ratings Services (S&P)

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

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

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

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

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

Equity Securities

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

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

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

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

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

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

Dividend Restrictions

Cinergy Corp.'sability to pay dividends to holders of its common stock is principally dependent on the ability ofCG&EandPSIto payCinergy Corp.common dividends.Cinergy Corp.,CG&E, andPSI

cannot pay dividends on their common stock if preferred stock dividends or preferred trust dividends are in arrears. The amount of common stock dividends that each company can pay is also limited by certain capitalization and earnings requirements underCG&E'sandPSI'scredit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock.

Guarantees

We are subject to an SEC order under the PUHCA, which limits the amountsCinergy Corp.can have outstanding under guarantees at any one time to $2 billion. As of December 31, 2001, we had $558 million outstanding under the guarantees issued, of which approximately 70% represents guarantees of obligations reflected onCinergy'sConsolidated Balance Sheet. The amount outstanding representsCinergy Corp.'sguarantees of liabilities and commitments of its consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. See Note 13(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a further discussion of guarantees.

Collateral Requirements

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

Other

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

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

2001 RESULTS OF OPERATIONS—HISTORICAL

SUMMARY OF RESULTS

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

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

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

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

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

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

ELECTRIC OPERATING REVENUES

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

	Total	$	8,181	$	5,384	52	$	4,097	$	2,739	50		$	4,075	$	2,684	52

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

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

GAS OPERATING REVENUES

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

	Total	$	4,663	$	2,942	58		$	596	$	491	21

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

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

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

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

OPERATING EXPENSES

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

	Total	$	11,981	$	7,560	58		$	4,082	$	2,702	51		$	3,745	$	2,387	57

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

Fuel

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

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

2001 fuel expense	$	771		$	307		$	453

(1): The results ofCinergyalso include amounts related to non-registrants.
(2): Includes fair value adjustments of contracted coal options. See Note 1(k) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further discussion.

Purchased and Exchanged Power

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

Gas Purchased

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

Operation and Maintenance

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

Depreciation

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

Taxes Other Than Income Taxes

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

MISCELLANEOUS—NET

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

INTEREST

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

INCOME TAXES

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

ULH&P

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

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

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

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

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

The Results of Operations discussions forCinergy,CG&E, andPSI are combined within this section.

2000 RESULTS OF OPERATIONS—HISTORICAL

SUMMARY OF RESULTS

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

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

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

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

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

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

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

ELECTRIC OPERATING REVENUES

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

	Total	$	5,384	$	4,313	25		$	2,739	$	2,175	26	$	2,684	$	2,136	26

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

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

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

GAS OPERATING REVENUES

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

	Total	$	2,942	$	1,596	84	$	491	$	376	31

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

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

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

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

OTHER REVENUES

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

OPERATING EXPENSES

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

	Total	$	7,560	$	5,245	44	$	2,702	$	2,071	30		$	2,387	$	1,864	28

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

Fuel

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

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

2000 fuel expense	$	773		$	344		$	407

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

Purchased and Exchanged Power

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

Gas Purchased

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

Operation and Maintenance

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

Depreciation

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

EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED SUBSIDIARIES

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

INTEREST

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

FUTURE EXPECTATIONS/TRENDS

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

ELECTRIC INDUSTRY

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

Wholesale Market Developments

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

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

Supply-side Actions

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

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

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

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

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

Demand-side Actions

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

FERC Notice of Proposed Rulemaking

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

Retail Market Developments

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

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

Federal Update

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

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

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

Ohio

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

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

•: Residential customer rates are frozen through December 31, 2005;
•: Residential customers received a five-percent reduction in the generation portion of their electric rates, effective January 1, 2001;
•: CG&Ewill provide four million dollars from 2001 to 2005 in support of energy efficiency and weatherization services for low income customers;
•: The creation of a Regulatory Transition Charge designed to recoverCG&E'sregulatory assets and other transition costs over a ten-year period;

•: Authority forCG&Eto transfer its generation assets to one or more, non-regulated affiliates to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;
•: Authority forCG&Eto apply the proceeds of transition cost recovery to costs incurred during the transition period including implementation costs and purchased power costs that may be incurred byCG&Eto maintain an operating reserve margin sufficient to provide reliable service to its customers;
•: CG&Ewill provide standard offer default supplier service (i.e.,CG&Ewill be the supplier of last resort, so that no customer will be without an electric supplier); and
•: CG&Ehas agreed to provide shopping credits to switching customers.

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

As indicated above, the August 31, 2000 order authorizesCG&Eto transfer its generation assets to a non-regulated affiliate. In addition to the regulatory approvals received from the PUCO, the IURC, and the KPSC, this transfer requires the approval of the FERC and the SEC under PUHCA. On October 29, 2001, Cinergy Power Investments, Inc., (Power Investments) filed an application with the FERC seeking EWG status.CG&Ealso filed an application seeking approval to transfer its generating assets to Power Investments. On December 21, 2001, the FERC issued an order certifying Power Investments' EWG status. As the transfer is contingent uponCG&Ereceiving FERC approval, SEC approval under PUHCA, and various third party consents, the timing and receipt of which are unknown, the completion date of the transfer of generation assets to Power Investments cannot be predicted.

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

Upon FERC authorization, Power Investments will enter into a power sale arrangement withCG&Efor the duration of the market development period, which is scheduled to terminate no later than December 31, 2005. Power Investments will supplyCG&Ewith sufficient power to meet the standard service obligations ofCG&E'scustomers that do not choose an alternate electric commodity supplier. In addition, Power Investments will enter into a second power sale agreement withCG&Eto provide sufficient power to fulfill the electric commodity obligations ofCG&E'swholesale customers. Power Investments will also replaceCG&Eas the electric commodity supplier in a power sale arrangement withULH&P. This new contract will replace the power sales agreement that is in place betweenCG&EandULH&P.

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

rates. The majority ofPSI'selectric commodity requirements will be provided byPSI'sgeneration. For more information refer to the "Termination of Operating Agreement" of this section.

Indiana

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

Kentucky

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

Other States

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

Other

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

Except with respect to the generation assets ofCG&E, as of December 31, 2001,CG&E,PSI, andULH&Pcontinue to meet each of the criteria required for the application of Statement 71. However, to the extent other states implement deregulation legislation, the application of Statement 71 will need to be reviewed. Based on our operating companies' current regulatory orders and the regulatory environment in which they currently operate, the future recovery of regulatory assets recognized in the accompanying Balance Sheets as of December 31, 2001, is probable. The effect of future discontinuance of Statement 71 on the results of operations, cash flows, or statements of position cannot be determined until deregulation legislation plans have been approved by each state in which we do business. See Note 1(c) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a further discussion of our regulatory assets.

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

Historical

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

FERC Orders

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

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

Operations Updates

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

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

State Regulatory Agencies Filings

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

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

Repeal of PUHCA

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

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

Significant Rate Developments

Purchased Power Tracker

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

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

In March 2001, the IURC held a hearing to reviewPSI's2000 purchases and rule on its associated request for recovery of costs. In May 2001, the IURC issued an order approving the recovery ofPSI'ssummer 2000 purchased power costs ($18.5 million) via the Tracker.

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

Purchased Power Agreement

ULH&Ppurchases energy fromCG&Epursuant to a new contract effective January 1, 2002, which was approved by the FERC and the KPSC. This five-year agreement is a negotiated fixed-rate contract withCG&Eand replaces the previous cost of service based contract, which expired on December 31, 2001.

Termination of Operating Agreement

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

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

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

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

PSI Fuel Adjustment Charge

PSIdefers fuel costs that are recoverable in future periods subject to IURC approval under a fuel recovery mechanism. In June 2001, the IURC issued an order in aPSIfuel recovery proceeding, disallowing approximately $14 million of deferred costs. On June 26, 2001,PSI formally requested that the IURC reconsider its disallowance decision. In August 2001, the IURC indicated that it will reconsider its decision.PSIbelieves it has strong legal and factual arguments in its favor and that it will ultimately be permitted to recover these costs. However,PSIcannot definitively predict the ultimate outcome of this matter.

In June 2001,PSIfiled a petition with the IURC requesting authority to recover $16 million in under billed deferred fuel costs incurred from March 2001 through May 2001. The IURC approved recovery of these costs subject to refund pending the findings of an investigative sub-docket. The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under billed deferred fuel costs. A hearing is scheduled for April 2002.

CWIP Ratemaking Treatment for NO_X Equipment

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

Transfer of Generating Assets to PSI

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

GAS INDUSTRY

ULH&P Gas Rate Case

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

CG&E Gas Rate Case

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

Gas Prices

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

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

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

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

MARKET RISK SENSITIVE INSTRUMENT AND POSITIONS

Energy Commodities Sensitivity

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

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

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

•: manage and economically hedge contractual commitments;
•: reduce exposure relative to the volatility of cash market prices;
•: take advantage of selected arbitrage opportunities; and
•: originate customized transactions with municipalities and end-use customers.

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

•: expected changes in future demand;
•: seasonal market pricing characteristics;
•: overall market sentiment; and
•: price relationships between different time periods and trading regions.

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

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

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

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

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

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

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

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

Fair value of contracts outstanding at the end of the period		$	18

(1): Represents net option premiums paid.

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

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

Total	$	20	$	(21	)	$	10	$	9	$	18

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

Concentrations of Credit Risk

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

Trade Receivables and Physical Power Portfolio

Our concentration of credit risk with respect to trade accounts receivable from electric and gas retail customers is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers significantly reduces our credit risk. Contracts within the physical portfolio of power marketing and trading operations are primarily with the traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 2001, we do not believe we had significant exposure to credit risk with our trade accounts receivable or our physical portfolio.

Energy Trading

Cinergy'sextension of credit for energy marketing and trading is governed by a Corporate Credit Policy. Written guidelines document the management approval levels for credit limits, evaluation of creditworthiness and credit risk mitigation procedures. Exposures to credit risks are monitored daily by the Corporate Credit Risk function. As of December 31, 2001, approximately 97% of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or higher. Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk is generally greater than with other commodity trading.

In December 2001, Enron filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of New York. We decreased our trading activities with Enron in the months prior to its bankruptcy filing. We intend to resolve any contract differences pursuant to the terms of those contracts, business practices and the applicable provisions of the Bankruptcy Code, as approved by the court. While we cannot predict the court's resolution of these matters, we do not believe that any exposure relating to those contracts would have a material impact on our financial position or results of operations. While most of our contracts with Enron were considered trading and thus recorded at fair value, a few contracts were accounted for utilizing the normal exemption under Statement of Financial Accounting Standards No. 133,Accounting for Derivatives Instruments and Hedging Activities(Statement 133) (see Note 1(k) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data"). These contracts were recognized at fair value when the contracts were terminated in the fourth quarter of 2001. Fair value for these contracts, and all terminated contracts with Enron, is governed by the provisions of each contract, but typically approximates fair value at contract termination. However, the effect of the loss of Enron's participation in the energy markets on long-term liquidity and price volatility, or on the creditworthiness of common counterparties cannot be determined. We continually review and monitor our credit exposure to all counterparties and adjust the fair value of our position, as appropriate.

Financial Derivatives

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

Risk Management

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

Exchange Rate Sensitivity

From time to time, we may utilize foreign exchange forward contracts and currency swaps to hedge foreign currency denominated purchase and sale commitments and certain of our net investments in

foreign operations. These contracts and swaps allow us to potentially hedge our position against currency exchange rate fluctuations and would qualify as derivatives.

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

Interest Rate Sensitivity

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

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

(1): London Inter-Bank Offered Rate (LIBOR)

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

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

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

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

		Expected Maturity Date
Liabilities		2002			2003			2004			2005			2006			Thereafter			Total			Fair Value
		(in millions)
Cinergy
Long-term Debt(1)		$	123		$	178	(4)	$	811		$	201	(5)(6)	$	328		$	1,823		$	3,464		$	3,520
	Weighted-average interest rate(2)		7.3	%		6.2	%		6.2	%		6.8	%		6.7	%		6.9	%		6.7	%
Other(3)		$	25		$	14		$	3		$	2		$	6		$	242		$	292		$	285
	Weighted-average interest rate(2)		6.8	%		6.7	%		6.6	%		5.5	%		5.0	%		6.4	%		6.4	%
Capital Leases
	Fixed-rate leases	$	2.8		$	3.0		$	3.1		$	3.3		$	3.6		$	19.1		$	34.9		$	34.9
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%

CG&Eand subsidiaries
Long-term Debt(1)		$	100		$	120	(4)	$	110		$	150	(6)	$	—		$	728		$	1,208		$	1,214
	Weighted-average interest rate(2)		7.3	%		6.3	%		6.5	%		6.9	%		—			7.0	%		6.9	%
Capital Leases
	Fixed-rate leases	$	1.5		$	1.6		$	1.7		$	1.9		$	2.0		$	10.8		$	19.5		$	19.5
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%

PSI
Long-term Debt(1)		$	23		$	58		$	1		$	51	(5)	$	328		$	895		$	1,356		$	1,379
	Weighted-average interest rate(2)		7.6	%		5.9	%		6.0	%		6.5	%		6.7	%		7.1	%		6.9	%
Capital Leases
	Fixed-rate leases	$	1.3		$	1.3		$	1.4		$	1.5		$	1.6		$	8.4		$	15.5		$	15.5
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%

ULH&P
Long-term Debt(1)		$	—		$	20		$	—		$	—		$	—		$	55		$	75		$	76
	Weighted-average interest rate(2)		—			6.1	%		—			—			—			7.3	%		7.0	%
Capital Leases
	Fixed-rate leases	$	0.5		$	0.5		$	0.5		$	0.5		$	0.6		$	3.2		$	5.8		$	5.8
	Interest rate		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%		6.2	%

(1): All long-term debt is fixed-rate and includes amounts reflected as long-term debt due within one year.
(2): The weighted-average interest rate is calculated as follows: (1) for long-term debt obligations, the weighted-average interest rate is based on the coupon rates of the debt that is maturing in the year reported; (2) for the fixed-rate capital leases, the interest rate is fixed at approximately 6.2% with an amortizing principal structure; and (3) for the Global Resources investments, the interest rate is based on a spread over 6- and 12-month LIBOR.
(3): Variable rate debt related to investments under Global Resources.
(4): Includes 6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.
(5): Includes 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate resets on August 1, 2005.
(6): Includes 6.90% Debentures due June 1, 2025, reflected as maturing in 2005, as the debentures are putable toCG&Eat the option of the holders on June 1, 2005.

Our current policy in managing exposure to fluctuations in interest rates is to maintain the total amount of outstanding debt in floating interest rate debt instruments of approximately 30%. In maintaining this level of exposure, we use interest rate swaps. Under these swaps, we agree with other parties to exchange, at specified intervals, the difference between fixed-rate and floating-rate interest amounts calculated on an agreed notional amount.CG&E has an outstanding interest rate swap agreement that decreased the percentage of floating-rate debt. Under the provisions of the swap, which has a notional amount of $100 million,CG&E pays a fixed-rate and receives a floating-rate through October 2007. This swap qualifies as a cash flow hedge under the provisions of Statement 133. As the terms of the swap agreement mirror the terms of the debt agreement that it is hedging, we anticipate

that this swap will continue to be effective as a hedge. Changes in fair value of this swap are recorded inAccumulated other comprehensive income (loss), beginning with our adoption of Statement 133 on January 1, 2001. In October 2001,Cinergy Corp. executed three interest rate swaps with a combined notional amount of $250 million. Under the provisions of the swaps,Cinergy Corp. will receive fixed-rate interest payments and pay floating-rate interest payments through September 2004. These swaps qualify as fair value hedges under the provisions of Statement 133. We anticipate that these swaps will continue to be effective as hedges. See Note 1(l) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for additional information on financial derivatives. In the future, we will continually monitor market conditions to evaluate whether to modify our level of exposure to fluctuations in interest rates.

INFLATION

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

ACCOUNTING MATTERS

Accounting Estimates

Fair Value Accounting for Energy Marketing and Trading

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

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

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

Retail Customer Revenue Recognition

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

Accounting Changes

Business Combinations and Intangible Assets

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141,Business Combinations(Statement 141), and No. 142,Goodwill and Other Intangible Assets (Statement 142). Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. With the adoption of Statement 142, goodwill and other intangibles with indefinite lives will no longer be subject to amortization. Goodwill will be initially assessed for impairment shortly after adoption and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under current accounting standards. This test must be applied at the "reporting unit" level, which is not permitted to be broader than the current business segments discussed in Note 16 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data". Under Statement 142, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer's intent to do so. We began applying Statement 141 in the third quarter of 2001 and we will adopt Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill beginning in the first quarter of 2002 will not be material to our results of operations. We have identified the reporting units forCinergy and are in the process of performing the initial impairment test. Preliminary estimates indicate that the effects of this test will not be material to our results of operations.

Asset Retirement Obligations

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

Derivatives

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

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

In October 2001, the FASB staff posted revised guidance on the normal purchases and sales exemption for these contracts. This revised guidance proposed changes in certain quantitative criteria that were critical to determining whether or not a contract with option characteristics qualified for the normal exemption. In December 2001, the FASB staff again revised this guidance to make the changes proposed by the October guidance more qualitative than quantitative. This new guidance uses several factors to distinguish between capacity contracts, which qualify for the normal purchases and sales exemption, and options, which do not. These factors include deal tenor, pricing structure, specification of the source of power, and various other factors. Based on a review of existing contracts, we do not believe this revised guidance, which will be effective in the third quarter of 2002, will have a material impact on our financial position or results of operations upon adoption. However, given our activity in energy trading, it could increase volatility in future results.

In October 2001, the FASB staff released final guidance on the applicability of the normal purchases and sales exemption to contracts that contain a minimum quantity (a forward component) and flexibility to take additional quantity (an option component). While this guidance was issued primarily to address optionality in fuel supply contracts, it is applicable to all derivatives (subject to certain exceptions for capacity contracts in electricity discussed in the previous paragraphs). This guidance concludes that such contracts are not eligible for the normal purchases and sales exemption due to the existence of optionality in the contract.Cinergy has certain contracts that contain optionality, primarily coal contracts, for which the accounting may be impacted by this new guidance. We will adopt this guidance in the second quarter of 2002, consistent with the transition provisions. We have begun analyzing contracts to determine the applicability of this guidance and to determine the interaction between this guidance and Statement 71. Due to a lack of liquidity with respect to coal purchased under certain contracts, some of our contracts may fail to meet the net settlement criteria of Statement 133, which would preclude such contracts from being considered derivatives. For other possibly affected contracts, we are evaluating the potential for contract restructuring prior to the adoption of this new guidance. To the extent this restructuring results in separate forwards and options, we would plan to apply the normal exemption to the forwards. The options would either be accounted for as cash flow hedges, to the extent all criteria were met, or marked to market similar to all other energy trading contracts. Given these evaluations are ongoing, we are unable to predict whether the implementation of this accounting standard will be material to our results of operations or financial position.

Asset Impairment

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

INSURANCE

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

QuickLinks

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net Cash Used in Investing Activities

CINergy (CIN) Inactive 8-KFinancial statements and exhibits