CINergy 10K 2000 Annual report

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INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year endedDecember 31, 2000
or

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commision File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-11377	CINERGY CORP. (A Delaware Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 287-1099	31-1385023
1-1232	THE CINCINNATI GAS & ELECTRIC COMPANY (An Ohio Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 287-1099	31-0240030
1-3543	PSI ENERGY, INC. (An Indiana Corporation) 1000 East Main Street Plainfield, Indiana 46168 (513) 287-1099	35-0594457
2-7793	THE UNION LIGHT, HEAT AND POWER COMPANY (A Kentucky Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 287-1099	31-0473080

Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange:

Registrant	Title of each class
Cinergy Corp.	Common Stock
The Cincinnati Gas & Electric Company	Cumulative Preferred Stock	4	%
	Junior Subordinated Debentures	8.28	%
PSI Energy, Inc.	Cumulative Preferred Stock	4.32	%
	Cumulative Preferred Stock	4.16	%
	Cumulative Preferred Stock	6-⁷/8	%

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that such registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/ No / /

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( )

Requirements pursuant to Item 405 of Regulation S-K are not applicable forThe Union Light,Heat and Power Company.

The Union Light,Heat and Power Company meets the conditions set forth in General Instruction I (1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I (2) of Form 10-K.

As of January 31, 2001, the aggregate market value of the common equity ofCinergy Corp. held by nonaffiliates (shareholders who are not directors or executive officers) was $4.8 billion. All of the common stock ofThe Cincinnati Gas & Electric Company andPSI Energy,Inc. is owned byCinergy Corp., and all of the common stock ofThe Union Light,Heat and Power Company is owned byThe Cincinnati Gas & Electric Company. As of January 31, 2001, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Cinergy Corp.	Par value $.01 per share	158,980,363
The Cincinnati Gas & Electric Company	Par value $8.50 per share	89,663,086
PSI Energy, Inc.	Without par value, stated value $.01 per share	53,913,701
The Union Light, Heat and Power Company	Par value $15.00 per share	585,333

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement ofCinergy Corp. and the Information Statement ofPSI Energy, Inc. filed, or to be filed, with the Securities and Exchange Commission are incorporated by reference into Part III of this report.

This combined Form 10-K is separately filed byCinergy Corp.,The Cincinnati Gas & Electric Company,PSI Energy,Inc., andThe Union Light,Heat and Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to registrants other than itself.

TABLE OF CONTENTS

Item Number
		Cautionary Statements Regarding Forward-Looking Information
		PART I
1		Business
		Organization
		Current Trends
		Business Units
		Other Developments
		Future Expectations/Trends
2		Properties
		Commodities
		Delivery
		Cinergy Investments
		International
		General Information
3		Legal Proceedings
		New Source Review and Notices of Violation
		Manufactured Gas Plant Sites
		M Metals Superfund Site
4		Submission of Matters to a Vote of Security Holders
		PART II
5		Market for Registrant's Common Equity and Related Stockholder Matters
6		Selected Financial Data
7		Management's Discussion and Analysis of Financial Condition and Results of Operations
		Introduction
		Organization
		Liquidity
		Capital Resources
		2000 Results of Operations-Historical
		1999 Results of Operations-Historical
		Results of Operations-Future
7A		Quantitative and Qualitative Disclosures About Market Risk
		Index to Financial Statements and Financial Statement Schedules
8		Financial Statements and Supplementary Data
9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
		PART III
10		Directors and Executive Officers of the Registrants
		Board of Directors
		Executive Officers
11		Executive Compensation
12		Security Ownership of Certain Beneficial Owners and Management
13		Certain Relationships and Related Transactions

		PART IV
14		Exhibits, Financial Statement Schedules, and Reports on Form 8-K
		Financial Statements and Schedules
		Reports on Form 8-K
		Exhibits
		Signatures

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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

In this report we discuss various matters that may make management's corporate vision of the future clearer for you. This report outlines management's goals and projections for the future. These goals and projections are considered forward-looking statements and are based on management's beliefs and assumptions.

Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with forward-looking statements. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These include:

•: Factors affecting operations, such as:
  (1)  unusual weather conditions;
  (2)  catastrophic weather-related damage;
  (3)  unscheduled generation outages;
  (4)  unusual maintenance or repairs;
  (5)  unanticipated changes in fossil fuel costs, gas supply costs, or availability constraints;
  (6)  environmental incidents; and
  (7)  electric transmission or gas pipeline system constraints.

•: Legislative and regulatory initiatives regarding deregulation of the industry, including potential deregulation legislation in Indiana, and potential national deregulation legislation.
•: The timing and extent of the entry of additional competition in electric or gas markets and the effects of continued industry consolidation through the pursuit of mergers, acquisitions, and strategic alliances.
•: Regulatory factors such as changes in the policies or procedures that set rates; changes in our ability to recover capital expenditures for environmental compliance, purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases.
•: Financial or regulatory accounting principles or policies imposed by governing bodies.
•: Political, legal, and economic conditions and developments in the United States (U.S.) and the foreign countries in which we have a presence. This would include inflation rates and monetary fluctuations.
•: Changing market conditions and other factors related to physical energy and financial trading activities. These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.
•: The performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities.
•: Availability of, or cost of, capital.
•: Employee workforce factors, including changes in key executives, collective bargaining agreements with union employees, and work stoppages.
•: Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
•: Costs and effects of legal and administrative proceedings, settlements, investigations, and claims. Examples can be found in Note 12 of the "Notes to Financial Statements" in "Part I. Financial Information".
•: Changes in international, federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.

Unless we otherwise have a duty to do so, the Securities and Exchange Commission's (SEC) rules do not require forward-looking statements to be revised or updated (whether as a result of changes in actual results, changes in assumptions, or other factors affecting the statements). Our forward-looking statements reflect our best beliefs as of the time they are made and may not be updated for subsequent developments.

PART I.

ITEM 1. BUSINESS

ORGANIZATION

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

        •    Cinergy Services, Inc. (Services);
        •    Cinergy Investments, Inc. (Investments);
        •    Cinergy Global Resources, Inc. (Global Resources);
        •    Cinergy Technologies, Inc. (Technologies); and
        •    Cinergy Wholesale Energy, Inc. (CWE).

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

PSI, an Indiana corporation, is an electric utility that provides service in north central, central, and southern Indiana. The following table presents further information related to the operations of our domestic utility companies (our operating companies):

	Principal Line(s) of Business	Major Cities Served	Approximate Population Served
CG&E and subsidiaries	• Generation, transmission, distribution, and sale of electricity • Sale and/or transportation of natural gas	Cincinnati, OH Middletown, OH Covington, KY Florence, KY Newport, KY Lawrenceburg, IN	2,017,000
PSI	• Generation, transmission, distribution, and sale of electricity	Bloomington, IN Columbus, IN Kokomo, IN Lafayette, IN New Albany, IN Terre Haute, IN	2,202,000
ULH&P	• Transmission, distribution, and sale of electricity • Sale and transportation of natural gas	Covington, KY Florence, KY Newport, KY	330,000

November 2000, CWE was formed to act as a holding company forCinergy's energy commodity businesses, including production, as the generation assets eventually become unbundled from the utility subsidiaries. See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion on Ohio deregulation.

We have collective bargaining agreements with the International Brotherhood of Electrical Workers (IBEW), the United Steelworkers of America (USWA), the Independent Utilities Union (IUU), and various international union organizations.

The following table indicates the number of employees by classification at December 31, 2000:

	Regulated				Non-Regulated
Classification	CG&E(4)	PSI	ULH&P	Total Regulated	Domestic(5)	International	Total Non- Regulated	Cinergy Total(6)
IBEW(1)	1,098	1,319	61	2,478	315	—	315	2,793
USWA(2)	297	—	87	384	—	—	—	384
IUU(3)	464	—	63	527	393	—	393	920
Various Union Organizations	—	—	—	—	17	492	509	509
Non-Bargaining	376	600	20	996	2,341	419	2,760	3,756

	2,235	1,919	231	4,385	3,066	911	3,977	8,362

(1)   IBEW #1347 contract will expire on April 1, 2006, and IBEW #1393 will expire on April 30, 2002.
(2)   Contract will expire May 15, 2002.
(3)   Contract will expire April 1, 2002.
(4)   CG&E and subsidiaries excludingULH&P.
(5)   Includes Services' employees who provide services to both regulated and non-regulated operations.
(6)   On January 1, 2001, 1,448 of our employees were transferred to a non-regulated domestic subsidiary of CWE. For
        more information on "Ohio deregulation" see Note 18 of the "Notes to Financial Statements" in "Item 8. Financial
        Statements and Supplementary Data".

CURRENT TRENDS

The structure of the electric industry in our service territory and throughout the U.S. has been relatively stable for many years. In recent years, however, there have been both federal and state developments aimed at industry restructuring and increasing competition. This process is leading to an industry model whereby the generating assets become deregulated and the transmission and distribution systems remain under some type of regulation. The underlying belief, which we share, is that over the long-term, deregulation of wholesale generation markets will, through increased competition, result in lower commodity prices than would otherwise be achieved. However, in recent months, unprecedented high prices, extreme price volatility, a lack of market liquidity, and inadequate generation supply led to customer blackouts in California, demonstrating the necessity for a constructive approach to deregulation. Within our service territory, Ohio is the first state to implement electric deregulation legislation. See the "Retail Market Developments" section in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of key elements of Ohio deregulation, which became effective January 1, 2001. Ohio's situation is different than California's in many respects, including the following:

•

In California, demand for electricity has risen sharply over the last decade, with no new increased generating capacity; however, within Ohio, demand has risen more steadily, with increased capacity being added. For example, according to statistics reported by the Public Utilities Commission of Ohio (PUCO), 1,230 megawatts (MW, the basic unit of electric energy equal to one million watts) of generating capacity was added during this past year in Ohio;

another 1,330 MW is planned for service during 2001. By comparison, California, which is estimated at about three times Ohio's population, has added minimal capacity over the last several years.

•: California's restructuring plan required utilities to divest their generation assets and prohibited the utilities from entering into long term contracts for supply; this forced the utilities to rely on the spot market to meet demand. Ohio's restructuring plan does not require utilities to divest their generation assets and allows for utilities to negotiate long-term commodity supply contracts at fixed prices for commodity purchases.
•: Existing transmission constraints limit the amount of electricity California can access from outside its borders. Ohio, however, shares interconnections with such states as Indiana, Kentucky, Michigan, Pennsylvania, and West Virginia.
•: California's generation is largely dependent on natural gas, the cost of which has increased dramatically in recent months, and also on hydroelectric production, which has been reduced due to drought conditions. Generation in Ohio, however, is largely fueled by coal, which has been more stable in price.

Twenty-four states and the District of Columbia have adopted deregulation plans. In response to the situation in California, some of these states, while not having similar experiences as California, are considering delaying or altering terms of implementation. A number of the remaining states are reconsidering their deregulation timetables. While we believe the situation in Ohio, as described above, and generally within the Midwest are different than California, we cannot predict the consequences, if any, on efforts to deregulate the remaining markets within our service territory. Indiana and Kentucky have not yet approved legislation.

BUSINESS UNITS

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

        •    Energy Commodities Business Unit (Commodities);
        •    Energy Delivery Business Unit (Delivery);
        •    Cinergy Investments Business Unit (Cinergy Investments); and
        •    International Business Unit (International).

The following section describes the activities of our business units as of December 31, 2000. As the utility industry continues to evolve,Cinergy will continue to analyze its operating structure and make modifications as appropriate. In early 2001, we announced certain organizational changes, which further aligned the business units consistent withCinergy's strategic vision. The revised structure reflects three business units, as follows:

•: Energy Merchant—will operate power plants, both domestically and abroad, and conduct all wholesale energy marketing, trading, origination, and risk management services;
•: Regulated Businesses—will operate all gas and electric transmission and distribution services, both domestically and abroad, and will be responsible for all regulatory planning for the regulated utility businesses ofCG&E,PSI, andULH&P; and
•: Power Technology and Infrastructure Services—will originate and manage a portfolio of emerging energy businesses.

See Note 15 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for financial information by business segment.

Commodities

Commodities operates and maintains our domestic regulated and non-regulated electric generating plants and some of our jointly-owned plants. As of December 31, 2000, the total winter electric capability (including our portion of the total capacity for the jointly-owned plants) of these generating plants was 11,889 MW. These plants are mostly coal-fired. In December 2000,Cinergy announced its intent to acquire an additional 998 MW of natural-gas fired generation. See "Item 2. Properties" for a further discussion of the generating facilities. Commodities also conducts the following activities:

        •    wholesale energy marketing and trading;
        •    energy risk management;
        •    financial restructuring services; and
        •    proprietary arbitrage activities.

See the "Market Risk Sensitive Instruments and Positions" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information on risks associated with these activities.

Fuel Supply Each year, throughCG&E andPSI, we purchase approximately 27 million tons of coal to generate electricity. The majority of this coal is obtained through long-term coal supply agreements. The remaining coal is purchased either on the spot market or through short-term supply agreements. We receive our coal supply primarily from mines located in Indiana, West Virginia, Ohio, Kentucky, Pennsylvania, and Illinois.

Commodities monitors alternative sources of coal to assure a continuing availability of economical fuel supplies. As such, it will maintain its practice of purchasing a portion of coal requirements on the spot market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements.

BothCG&E andPSI believe that they can continue to obtain enough coal to meet future needs. However, future environmental requirements may significantly impact the availability and price of coal.

Purchased Power At times we purchase power to meet the energy needs of our wholesale customers and to meet the requirements of our retail native load customers (end-use customers within our operating companies' franchise territory). Factors that could causeCinergy to purchase power for retail native load customers include generating plant outages, extreme weather conditions, growth, and other factors associated with supplying full requirements electricity. We believe we can obtain enough purchased power to meet future needs. However, during periods of excessive demand, such as those which occurred in the summers of 1998 and 1999, the price and availability of these purchases may be significantly impacted. See the "Significant Rate Developments" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information onPSI's Purchased Power Tracker.

Environmental Matters In December 2000,Cinergy reached an agreement in principle with the U.S. Environmental Protection Agency (EPA) and various parties, that may serve as the basis for a negotiated resolution of the Clean Air Act (CAA) claims and other related matters brought against coal-fired power plants owned and operated byCinergy's operating companies. The estimated cost for these capital expenditures is expected to be approximately $700 million. These capital expenditures are in addition to our previously announced commitment to install nitrogen oxide (NO_X) controls over the next five years at an estimated cost of approximately $700 million. In 2000, we spent $75 million for NO_X and other environmental compliance as compared to $16 million in 1999. Forecasted expenditures for NO_X and other environmental compliance (in nominal dollars) are $210 million for 2001 and $789 million for 2001-2005. See the "Environmental Issues" and "Construction and Other Commitments" sections of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information.

Delivery

Delivery plans, constructs, operates, and maintains our operating companies' transmission and distribution systems and provides gas and electric energy to customers. Delivery operated approximately 45,800 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to 1.5 million customers as of December 31, 2000. Delivery operated approximately 7,550 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and service lines to provide regulated transmission and distribution service to approximately 489,000 customers as of December 31, 2000. See "Item 2. Properties" for a further discussion of the transmission and distribution lines owned by our operating companies.

Electric Operations Delivery (through our operating companies) and other non-affiliated utilities in an eight-state region participate in the East Central Area Reliability Coordination Agreement (ECAR Agreement). The ECAR Agreement coordinates the planning and operation of generation and transmission facilities, which provides for maximum reliability of regional bulk power supply.

Midwest ISO As part of the effort to create a competitive wholesale power marketplace, the Federal Energy Regulatory Commission (FERC) approved the formation of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) during 1998. In that same year,Cinergy agreed to join the Midwest ISO in preparation for meeting anticipated changes in the FERC regulations and future deregulation requirements. The Midwest ISO was established as a non-profit organization to maintain functional control over the combined transmission systems of its members. The organization was expected to begin operations in November 2001.

In the fall of 2000, three transmission owners announced their intent to leave the Midwest ISO and join the proposed Alliance Regional Transmission Organization (Alliance RTO) by the end of 2001. 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.

On December 13, 2000, six additional transmission owners, includingCinergy, announced a plan for conditional withdrawal from the Midwest ISO if the other three withdrawing members left the organization.

On January 24, 2001, the FERC issued an order providing 30 days of confidential settlement talks between the Alliance RTO and the Midwest ISO and its stakeholders, in an effort to resolve issues related to such withdrawals.Cinergy actively participated in the settlement process. On February 23, 2001, the settlement judge reported to the FERC that settlement talks produced a unanimous comprehensive settlement between all related parties. Specific details of this settlement are yet to be finalized and will need approval by the FERC. The definitive settlement agreement language is to be filed with the FERC on March 19, 2001. If approved, the settlement agreement is not expected to present any material adverse impacts to the company.

The following map illustrates the interconnections between our electric systems and other electric systems.

Electricity Supply Delivery currently receives all of its electricity from Commodities at a transfer price based upon current regulatory ratemaking methodology. With the implementation of electric deregulation in Ohio, effective January 1, 2001, Delivery continues to acquire its electricity requirements through Commodities for those retail customers who do not switch suppliers. For further details on electricity supply ofCG&E refer to Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

ULH&P purchases its energy fromCG&E pursuant to a FERC-approved contract that is due to expire on December 31, 2001. Currently the contract is under negotiation with the involvement of the Kentucky Public Service Commission. The Ultimate supplier(s) ofULH&P's energy and the pricing of electric commodity requirements contained in any new arrangement could reflect a market-based approach. At the current time we are unable to predict the outcome of this matter.

Gas Supply Delivery is responsible for the purchase and the subsequent delivery of natural gas to native load customers. Delivery's procurement strategy is to buy firm gas supplies and firm interstate pipeline capacity during the winter season (November through March) and buy spot supply and capacity during the non-heating season (April through October). This strategy allows Delivery to assure reliable gas supply for its high priority (non-curtailable) customers during peak winter conditions and provides Delivery the flexibility to reduce its contract commitments if customers choose alternate gas suppliers. In 2000, firm supply (gas intended to be available at all times) purchase commitment agreements provided approximately 55% of the natural gas supply. The remaining gas was purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) base load, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand. Delivery pays reservation charges for base load and swing load supplies. These charges secure delivery from the supplier during periods of extreme weather or high demand. See the "Gas Industry" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information.

Interstate pipelines either (1) transport gas purchased directly to the distribution systems or (2) inject gas purchased into pipeline storage facilities for future withdrawal and delivery. The majority of the gas supply comes from the Gulf of Mexico coastal areas of Texas and Louisiana. In addition, a limited supply comes from the mid-continent (Arkansas-Oklahoma) basin. Also, industrial transportation customers behindCinergy's city gate (point where the distribution system connects to an interstate gas pipeline) are obtaining methane gas recovered locally from an Ohio landfill. Delivery expects the natural gas market will remain competitive in future years. However, short-term price fluctuations could occur as a result of weather conditions, availability of supply, changes in demand, and storage inventories. The market price of natural gas has increased significantly in 2000, which has causedCG&E andULH&P to pay more for the gas they deliver to customers. Under the gas cost recovery mechanism that is mandated under state law, gas commodity cost is passed through directly to the customer dollar-for-dollar. It is expected that gas commodity prices will remain at these historically high levels well into 2001.

Revenue Data and Customer Base The percent of operating revenues derived from electricity sales and from the sale and/or transportation of natural gas for the years ended December 31 were as follows:

	Operating Revenues
	2000		1999		1998
Registrant	Electric %	Gas %	Electric %	Gas %	Electric %	Gas %
Cinergy(1)	64	36	73	27	81	19
CG&Eand subsidiaries	85	15	85	15	86	14
PSI	100	—	100	—	100	—
ULH&P	71	29	75	25	75	25

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

Electric and gas sales are seasonal. Electricity usage in our service territory peaks during the summer and gas usage peaks during the winter. Air conditioning increases electricity demand and heating increases the demand for electricity and gas.

The service territory ofCG&E and its utility subsidiaries, includingULH&P, is heavily populated and is characterized by a stable residential customer base and a diverse mix of industrial customers. The territory served byPSI is composed of residential, agricultural, and widely diversified industrial customers. No single customer provides more than ten percent of operating revenues (electric or gas) for any of our operating companies.

Cinergy Investments

Cinergy Investments manages the development, marketing, and sales of our domestic non-regulated, and non-wholesale energy and energy-related products and services. This is accomplished through various subsidiaries and joint ventures. These products and services include the following:

•: providing energy management-consulting services and infrastructure solutions to government, industrial, and commercial customers that operate retail facilities;
•: providing various utility services to utilities (for example, providing underground locating and construction services for utilities);
•: providing telecommunication services including dark fiber, high capacity service, internet service, local phone service, and long distance service;
•: leasing of space on wireless telecommunication towers and the purchase and construction of such towers;
•: providing various engineering, procurement, construction, operation, and maintenance functions such as designing and constructing turnkey gas pipelines, electric transmission and distribution lines, substations for industrial and large commercial customers, and fiber optic telecommunication cables;
•: providing information, systems, and services to multi-site national chains in retail industries to optimize their energy, telecommunications, and other facility-wide costs;
•: building, owning, operating, and maintaining combined heat and power facilities; and
•: pursuing technology equity investments and running technology pilots.

International

In 1999, we sold our 50% ownership interest in Midlands Electricity plc (Midlands). Prior to the sale, Midlands had provided the majority of International's earnings. See Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further information on the sale of our ownership interest in Midlands.

During the fourth quarter of 2000, a joint venture between a subsidiary ofCinergy and a subsidiary of Royal Dutch Petroleum (Shell) was awarded a 49% interest and operational control of the gas distribution business in Athens, Greece. We expect this transaction to close during the first half of 2001. International's plans for 2001 include development of the Greek gas business itself and other opportunities which may arise in the Greek market. In addition, International expects to continue its development of, and investment in, renewable energy projects in both the U.S. and Europe. The timing of International's investments depends on changing market conditions and regulatory approvals. Our international investments present certain risks, including foreign exchange risk. See the "Market Risk Sensitive Instruments and Positions" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information on these risks and how we address our exposure to them. See Note 15 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for further information on revenues from foreign operations and long-lived assets.

OTHER DEVELOPMENTS

Our ability to invest in growth initiatives, such as Exempt Wholesale Generators (EWG) and Foreign Utility Companies (FUCO) is limited by certain legal and regulatory requirements, including the PUHCA. An EWG is a special-purpose entity that owns or operates domestic or foreign electric generating facilities whose power is sold entirely at wholesale. FUCOs are companies whose utility assets and operations are located entirely outside the U.S. and which are used for the generation, transmission, or distribution of electric energy for sale, or the distribution of gas at retail. In late 1999, we filed a request with the SEC under the PUHCA for an additional $5 billion in authority to invest in EWGs and FUCOs. On June 23, 2000, the SEC issued an interim order granting us authority to invest a total of $1.7 billion in EWGs and FUCOs, replacing an earlier order capping our investment authority under PUHCA at an amount equal toCinergy's average retained earnings from time to time. As of December 31, 2000, we had invested or committed to invest $1.4 billion of the $1.7 billion available.

In January 2001,Cinergy modified its request to the SEC for additional investment authority, proposing a new investment limitation capped at $4 billion, subject to various terms and conditions. This request is pending before the SEC. While we currently cannot predict the outcome of this request, the existing limits could restrict our ability to invest in future transactions.

FUTURE EXPECTATIONS/TRENDS

See the information appearing under the same caption in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for discussion of "Future Expectations/Trends."

ITEM 2. PROPERTIES

COMMODITIES

Regulated

Our operating companies' total winter electric capabilities reflected in MW as of December 31, 2000, are shown in the table that follows. Our electric generating plants are located in Ohio, Kentucky, and Indiana and are wholly-owned and jointly-owned facilities.

Registrant(1)	Stations	Coal MW	Natural Gas MW	Oil MW	Hydro MW	Total MW
CG&E	9	4,186	736	323	—	5,245
PSI	8	5,578	120	261	45	6,004

Total	17	9,764	856	584	45	11,249

(1): This table includes only our portion of the total capacity for the jointly-owned plants. Refer to Note 13 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the jointly-owned plants.

During 2000, our electric generating plants operated reliably, as evidenced by our annual capacity factor of 73% (excluding natural gas peaking stations), and a utilization factor of greater than 86%. A capacity factor is a percentage that indicates how much of a power plant's capacity is used over time.

During August, we experienced peak loads of 4,731 MW forCG&E and 5,410 MW forPSI. At times we purchase power to meet the energy needs of our wholesale customers and to meet the requirements of our retail native load customers. Factors that could causeCinergy to purchase power for retail native load customers include outages, extreme weather conditions, growth, and other factors associated with supplying full requirements electricity. We believe we can obtain enough purchased power to meet future needs.

Promptly after receipt of all required regulatory approvals and third-party consents,CG&E anticipates transferring its generating stations and their related assets and obligations to one or more non-regulated corporate subsidiary(ies). Subsequent to this transferCG&E will continue operations as a transmission and distribution company. To facilitate this transfer, the generation assets ofCG&E as of August 2000, were released from the first mortgage indenture lien allowing them to move un-encumbered to the non-regulated subsidiary. Generating assets added after August 2000, remain subject to the lien ofCG&E's first mortgage bond indenture and will require release at some future date prior to being transferred. For a further discussion on Ohio deregulation see Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

Non-Regulated

During 1999, one of our non-regulated subsidiaries formed a partnership (each party having a 50% ownership) with Duke Energy North America LLC (Duke). The partnership was formed for the purpose of jointly constructing and owning three wholesale generating facilities located in southwestern Ohio, and east central and western Indiana. Two of these properties became fully operational in June 2000. The total capacity of these plants is 1,280 MW. Construction of the third facility, with a capacity of 129 MW, has been suspended by order of the Indiana Utility Regulatory Commission (IURC). For further information on the IURC's order, see the "Wholesale Market Developments" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations".

In December 2000,Cinergy announced that one of its non-regulated subsidiaries entered into a definitive agreement to acquire two natural gas-fired merchant electric generating facilities from Enron. The facilities are located in Tennessee and Mississippi and have a total combined capacity of 998 MW. It is anticipated that this transaction will close in the second quarter of 2001.

DELIVERY

Electric

Metrics for our operating companies' electric transmission and distribution systems (excluding our proportionate share of jointly-owned facilities) are estimated as follows:

Registrant		Electric Transmission Systems	Electric Distribution Systems	Substation Combined Capacity
		(circuit miles)	(circuit miles)	(kilovolt-amperes)(1)
CG&E		1,641	15,315	20,518,621
	ULH&P	105	2,646	1,115,298
	Other subsidiaries	40	10	—

CG&E and subsidiaries		1,786	17,971	21,633,919
PSI		5,515	20,557	28,946,637

Total		7,301	38,528	50,580,556

(1): Kilovolt-amperes (1,000 volt-amperes) are a broad measure of our substation transformer capacity.

At the end of 1999 our operating companies' electric systems were interconnected with thirteen other utilities. An additional interconnection was completed in 2000 betweenCinergy and a new generation-only area established by Enron bringing the total number of interconnections to fourteen.

Our electric transmission and distribution systems are designed and constructed to further the goal of providing reliable service to our customers. Every effort is made to ensure that sufficient facilities are in service to meet this goal without installing facilities beyond what is required to operate reliably and within design or designed parameters. Through our ongoing review of these systems, enhancements are developed and constructed to meet our planning, loading, and reliability guidelines. This process allows us to prudently invest in capacity additions only when and where they are required.

Gas

As of December 31, 2000, the natural gas transmission and distribution systems ofCG&E and its subsidiaries had approximately 7,500 miles of mains and service lines located in southwestern Ohio, southeastern Indiana, and northern Kentucky.CG&E and its subsidiaries also own three underground caverns with a total storage capacity of 23 million gallons of liquid propane. As of December 31, 2000, we had 17 million gallons of liquid propane in storage. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. These plants convert liquid propane into natural gas to be used only during peak demand periods and emergencies. During 2000,CG&E and its subsidiaries' natural gas transmission and distribution systems operated reliably, at a load factor of 34%, and at satisfactory levels of utilization. Load factor is used to indicate the percentage of capacity of an energy facility, such as gas distribution, that is utilized at a given period of time.

CINERGY INVESTMENTS

In 1997,Cinergy and Trigen Energy Corporation formed a joint venture company, Trigen-Cinergy Solutions LLC, to build, own, operate, and maintain combined heat and power facilities for large

industrial customers. As of December 31, 2000, we have an ownership interest and/or operating control in nine domestic cogeneration (simultaneous production of two or more forms of useable energy from a single fuel source) plants producing 294 MW of electricity through our various joint ventures. During 2001-2002, we anticipate completing construction of three new cogeneration plants, which will produce an additional 40 MW of electricity.

In 2000,Cinergy formed a new wholly-owned subsidiary, Cinergy Solutions, Inc. (Cinergy Solutions), to develop, acquire, own, and operate energy-related projects. In October 2000, Cinergy Solutions agreed to form a partnership with British Petroleum to construct, own, and operate two new cogeneration plants located in Texas that, with existing facilities to be acquired by the partnership, will produce more than 800 MW of electricity. The operation of these two new cogeneration projects will coincide with the decommissioning of older, less efficient energy facilities. This agreement was finalized in late January 2001.

INTERNATIONAL

As of December 31, 2000, International had ownership interests in generating plants located in 11 countries, including the U.S., producing a total of 1,626 MW of electricity. Five of these plants are district heating plants in the Czech Republic, of which we own four and have a minority interest in the fifth, that in total provide 1,094 MW of thermal steam capacity, which may be used to produce 149 MW of electricity. We also own interests in 1,975 miles of gas and electric transmission and distribution systems through jointly-owned investments. International serves 51,140 transmission and distribution customers, 518 retail district heating and district electric customers, and 106 wholesale heating and electric customers.

During 2000,Cinergy invested or acquired the right to invest in two gas distribution businesses, both of which are located in major international markets and both of which will require development over the next several years in order to add customers. Specifically, in August 2000, together with a South African minority partner (5%),Cinergy acquired Egoli Gas, which has the right to develop and operate the gas distribution business in the Greater Johannesburg, South Africa market. Also, during the fourth quarter of 2000, a joint venture between a subsidiary ofCinergy and a subsidiary of Shell was awarded a 49% interest and operational control of a gas distribution business in Athens, Greece. We expect this transaction to close during the first half of 2001.

GENERAL INFORMATION

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

ITEM 3. LEGAL PROCEEDINGS

NEW SOURCE REVIEW AND NOTICES OF VIOLATION

See Notes 12(c) and (d) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the lawsuit and notices of violation filed by the EPA againstCinergy,CG&E, andPSI.

MANUFACTURED GAS PLANT SITES

See Note 12(f) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of manufactured gas plant sites as they relate to our operating companies.

M METALS SUPERFUND SITE

On July 6, 2000, the EPA identifiedPSI and Indianapolis Power and Light Company (IPL) as Potentially Responsible Parties for the release of hazardous substances at the M Metals Superfund Site (Site) located in Indianapolis, Indiana. The EPA advised that it had taken response actions relating to the Site and had incurred costs of approximately $500,000. The EPA has demanded reimbursement of these costs incurred related to the Site and has encouragedPSI and IPL to work out an allocation between themselves for the payment of the costs. However,PSI and IPL will be held jointly and severally liable for the costs.PSI is communicating with the EPA and is in the process of reviewing EPA documentation of the cleanup in preparation of entering into settlement discussions. Resolution of this matter is not expected to materially impact our results of operations or financial condition.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders forCinergy,CG&E, orPSI during the fourth quarter of 2000.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS

Cinergy Corp.'s common stock is listed on the New York Stock Exchange. The high and low stock prices for each quarter for the past two years are indicated below:

	High		Low
2000
First Quarter	$	25.88	$	20.00
Second Quarter		28.13		21.19
Third Quarter		33.25		25.56
Fourth Quarter		35.25		28.50
1999
First Quarter	$	34.88	$	27.38
Second Quarter		34.63		27.44
Third Quarter		33.00		27.31
Fourth Quarter		29.63		23.44

Cinergy Corp. holds all outstandingCG&E andPSI common stock, andCG&E holds allULH&P common stock. Therefore, no public trading market exists for the common stock ofCG&E,PSI, andULH&P.

As of January 29, 2001, the most recent dividend record date, we had 61,049 common stockholders of record.

Cinergy Corp. declared dividends on common stock of $.45 per share for each quarter of 1999 and 2000. The dividends
paid toCinergy Corp. byCG&E andPSI and toCG&E byULH&P for the past two years were as follows:

Registrant	Quarter	2000		1999
		(in thousands)
CG&E	First	$	53,600	$	71,400
	Second		53,600		71,500
	Third		53,600		53,600
	Fourth		71,534		53,600
PSI	First	$	18,000	$	—
	Second		18,000		—
	Third		18,000		17,900
	Fourth		—		18,000
ULH&P	First	$	—	$	—
	Second		4,974		4,976
	Third		—		—
	Fourth		4,683		4,683

See Note 2(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a brief description of the registrants' common stock dividend restrictions.

ITEM 6. SELECTED FINANCIAL DATA

			2000(1)		1999(1)		1998(2)		1997			1996
			(in millions, except per share amounts)
Cinergy
Operating revenues			$	8,422	$	5,938	$	5,911	$	4,387		$	3,276
Net income before extraordinary item				399		404		261		363			335
Net income				399		404		261		253	(3)		335
Common stock
	Earnings per share (EPS)
		Net income before extraordinary item		2.51		2.54		1.65		2.30			2.00
		Net income		2.51		2.54		1.65		1.61	(3)		2.00
	EPS—assuming dilution
		Net income before extraordinary item		2.50		2.53		1.65		2.28			1.99
		Net income		2.50		2.53		1.65		1.59	(3)		1.99
	Dividends declared per share			1.80		1.80		1.80		1.80			1.74
Total assets				12,330		9,617		9,687		8,858			8,725
Long-term debt				2,876		2,989		2,604		2,151			2,326
Long-term debt due within one year				41		31		136		85			140
CG&E
Operating revenues			$	3,230	$	2,551	$	2,856	$	2,452		$	1,976
Net income				267		234		216		239			227
Total assets				5,987		4,917		5,154		4,914			4,844
Long-term debt				1,205		1,206		1,220		1,324			1,381
Long-term debt due within one year				1		—		130		—			130
PSI
Operating revenues			$	2,684	$	2,136	$	2,403	$	1,960		$	1,332
Net income				135		117		52		132			126
Total assets				4,630		3,835		3,584		3,406			3,295
Long-term debt				1,074		1,212		1,026		826			945
Long-term debt due within one year				38		31		6		85			10

(1): See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", and the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for factors affecting earnings and discussion of material uncertainties forCinergy,CG&E, andPSI.
(2): See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations".
(3): Included in net income for 1997 was a one-time extraordinary charge of $110 million ($.69 per share basic and diluted) for the windfall profits tax levied against our 50% ownership interest in Midlands. In the third quarter of 1999, we sold our ownership interest in Midlands.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

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

INTRODUCTION

In Management's Discussion and Analysis (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;
•: why revenues and expenses changed from period to period;
•: how the above items affect our overall financial condition;
•: what our expenditures for construction and other commitments were during 2000, and what we expect them to be in 2001-2005; and
•: potential sources of cash for future capital expenditures.

ORGANIZATION

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

•: Cinergy Services, Inc. (Services);
•: Cinergy Investments, Inc. (Investments);
•: Cinergy Global Resources, Inc. (Global Resources);
•: Cinergy Technologies, Inc. (Technologies); and
•: Cinergy Wholesale Energy, Inc. (CWE).

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

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

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

Services is a service company that provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated, energy-related businesses and investments. Global Resources holds our international businesses and investments and directs our renewable energy investing activities (for example, wind farms). Technologies primarily holds our portfolio of technology-related investments. In November 2000, CWE was formed to act as a holding company forCinergy's energy commodity businesses, including production, as the generation assets eventually become unbundled from the utility subsidiaries. See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion on Ohio deregulation.

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

We conduct operations through our subsidiaries, and we manage through the following four business units:

•: Energy Commodities Business Unit (Commodities);
•: Energy Delivery Business Unit (Delivery);
•: Cinergy Investments Business Unit; and
•: International Business Unit.

As the utility industry continues to evolve,Cinergy will continue to analyze its operating structure and make modifications as appropriate. In early 2001, we announced certain organizational changes which further aligned the business units to reflectCinergy's strategic vision. The revised structure reflects three business units, as follows:

•: Energy Merchant—will operate power plants, both domestically and abroad, and conduct all wholesale energy marketing, trading, origination and risk management services;
•: Regulated Businesses—will operate all gas and electric transmission and distribution services, both domestically and abroad, and will be responsible for all regulatory planning for the regulated utility businesses ofCG&E,PSI, andULH&P; and
•: Power Technology and Infrastructure Services—will originate and manage a portfolio of emerging energy businesses.

See Note 15 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for financial information by business unit.

LIQUIDITY

In the "Liquidity" section, we discuss 2000 cash flows, environmental issues, construction, and other investing activities as they relate to our current and future cash needs. In the "Capital Resources" section we discuss how we intend to meet these capital requirements.

2000 Cash Flows

Operating Activities

For the year ended December 31, 2000,Cinergy's andPSI's cash from operating activities increased $229 million and $331 million, respectively, compared to 1999, primarily due to the cash requirement for the purchase of the remainder of Dynegy, Inc.'s 25 year contract for coal gasification services in 1999.CG&E's cash provided from operating activities during 2000 decreased $111 million for the year ended December 31, 2000, as compared to last year, due primarily to a net increase in receivables less payables pertaining to customer accounts and power marketing and trading activities.ULH&P's cash from operating activities increased $17 million primarily due to changes in working capital and deferred income taxes.

Financing Activities

Cinergy's net cash provided by financing activities increased $514 million in 2000, as compared to the prior year. This change is primarily attributable to an increase in short-term borrowings which is partially offset by a decrease in the issuance of long-term debt.CG&E's net cash used in financing activities decreased $206 million compared to 1999. This comparative decrease is primarily a result of the redemption of $164 million in long-term debt that occurred during 1999.PSI's net cash provided by financing activities decreased $258 million over the prior year due to a decrease in the net issuance of long-term debt. This decrease was partially offset by an increase in short-term borrowings.ULH&P reduced its short-term borrowings during 2000, as compared to 1999, which accounts for the decrease in net cash provided by financing activities of $14 million.

Investing Activities

For the year ended December 31, 2000,Cinergy's net cash used in investing activities increased $714 million as compared to the prior year. This change primarily reflects the proceeds of $690 million received in 1999 from the sale of our 50% ownership interest in Midlands Electricity plc (Midlands).CG&E's andPSI's net cash used in investing activities increased $66 million and $70 million, respectively, as compared to 1999, as a result of an increase in construction expenditures.

For further detail regarding the classification of these items, see our Consolidated Statements of Cash Flows in "Item 8. Financial Statements and Supplementary Data".

Environmental Issues

In the "Environmental Issues" section, we discuss the ozone transport rulemaking, ambient air standards, regional haze, global climate change, mercury, new source review, W.C. Beckjord Generating Station (Beckjord Station) Notices of Violations (NOV), United States (U.S.) Environmental Protection Agency (EPA) Agreement, and manufactured gas plants sites as they relate to us and our operating companies.

Ozone Transport Rulemaking In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the EPA to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant with ozone standards) in the Northeast, Midwest, and South. Ozone transport refers to wind-blown movement of ozone and ozone-causing materials across city and state boundaries. In late 1997, the EPA published a proposed call for revisions to State Implementation Plans (SIPs). SIP is an acronym for a state's implementation plan for achieving emissions reductions to address air quality concerns. The EPA must approve all SIPs.

Nitrogen Oxide (NO_X ) SIP Call In October 1998, the EPA finalized its ozone transport rule, also known as the NO_X SIP Call. It applied to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate, and also proposed a model NO_X emission allowance trading program. This rule recommended states reduce NO_X emissions primarily from industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999, to incorporate NO_X reductions and, at the discretion of the state, a NO_X trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NO_X reductions by May 2003, if states failed to revise their SIPs.

Ohio, Indiana, a number of other states, and various industry groups (some of which we are a member), filed legal challenges to the NO_X SIP Call in late 1998. On May 25, 1999, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) granted a request for a deferral of the rule and indefinitely suspended the September 30 filing deadline, pending further review by the Court of Appeals.

In March 2000, the Court of Appeals substantially upheld the EPA's rule. On April 11, 2000, the EPA asked the Court of Appeals to remove its May 25, 1999 suspension of the rule and also directed states to submit SIP revisions by September 1, 2000. On April 17, 2000, various states and industry groups (some of which we are a member) filed a request with the Court of Appeals for a rehearing of the NO_X SIP Call decisions. On April 24, 2000, the same group filed a request with the Court of Appeals to require a rulemaking and a comment period to determine a new compliance date. The states also filed a request to obtain more time to file their SIPs. On June 23, 2000, the Court of Appeals denied both requests and directed the states to submit their SIP revisions by October 30, 2000. The states of Indiana, Kentucky, and Ohio subsequently submitted letters stating their intent to revise their SIPs in response to the NO_X SIP Call.

In August 2000, the Court of Appeals extended the May 1, 2003 deadline for NO_X reductions to May 31, 2004. The states and other groups appealed the Court of Appeals ruling to the U.S. Supreme Court (Supreme Court).

On September 25, 2000,Cinergy announced a plan to invest approximately $700 million in pollution control equipment and other methods to reduce NO_X emissions. This expected investment includes the following:

•: install up to 11 selective catalytic reduction units (SCRs) at several different generating stations;
•: install other pollution control technologies, including new computer software, at all generating stations;
•: make combustion improvements; and
•: utilize market opportunities to buy and sell NO_X allowances.

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

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

In December 1999, the EPA granted four Section 126 petitions relating to NO_X emissions. This ruling affected all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and requires us to reduce our NO_X emissions to a certain level by May 2003. The EPA's action granting the Section 126 petitions was appealed to the Court of Appeals. Oral arguments were held in this case on December 15, 2000. A final decision is expected some time within the next few months.

State Ozone Plans On November 15, 1999, the State of Indiana and the Commonwealth of Kentucky (along with Jefferson County, Kentucky) jointly filed an amendment to their attainment demonstration on how they intend to bring the greater Louisville area, including Floyd and Clark Counties in Indiana, into attainment with the one-hour ozone standard. The SIP amendments call for, among other things, statewide NO_X reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA's NO_X SIP Call. Indiana and Kentucky committed to adopt utility NO_X control rules by December 2000 that would require controls be installed by May 2003. However, Indiana halted the rulemaking for NO_X controls at this level, but continues to develop NO_X SIP Call level reduction regulations. Kentucky did complete their rulemaking, but has issued a notice of intent to revise the rules to change the compliance deadline to mirror the NO_X SIP Call (May 31, 2004).

See "EPA Agreement" below for a discussion of the tentative EPA settlement, which relates to matters discussed herein.

Ambient Air Standards During 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. It was anticipated that utility NO_X reductions called for in the EPA's final NO_X SIP Call would address both the pre-existing one-hour ozone standard and the new eight-hour ozone standard. With the recent challenges to the NO_X SIP Call and the eight-hour ozone standard (discussed below), it is unclear to what extent additional NO_X reductions will be required of utilities to address eight-hour ozone non-attainment issues.

The EPA estimates it will take up to five years to collect sufficient ambient air monitoring data to determine fine particulate matter non-attainment areas. The states will then determine the sources of the particulates and determine a regional emission reduction plan. We currently cannot predict the exact amount and timing of required reductions.

On May 14, 1999, the Court of Appeals ruled that both the new eight-hour ozone standard and the fine particulate matter standard were questionable and were determined to be unenforceable by the EPA. In June 1999, the EPA appealed the decision. On October 29, 1999, the full Court of Appeals rejected the EPA's request for reconsideration. In January 2000, the EPA appealed to the Supreme Court and oral arguments were held on November 17, 2000, with a ruling expected any time, but no later than July 2001. We currently cannot determine the outcome of the appeals process 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. In addition, several industry groups (some of which we are a member) have petitioned the new 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.

Global Climate Change 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 November 2000, another Conference of the Parties was held to negotiate the details of administrating the Kyoto Protocol. On November 25, 2000, the delegation failed to reach an agreement and suspended any further discussion until 2001.

Because of a lack of 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 air toxics provisions of the CAA delayed possible air toxics regulation of fossil-fueled steam utility plants until the EPA completed a study. The final report, issued in February 1998, confirmed that utility air toxic emissions pose little risk to public health. It stated that mercury is the pollutant of the greatest concern and requires further study. A Mercury Study Report, issued in December 1997, stated 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. U.S. utilities are a large domestic source, but they are insignificant when compared to global mercury emissions. The EPA was unable to show a feasible mercury control technology for coal-fired utility plants.

In November 1998, the EPA finalized its mercury Information Collection Request (ICR). The ICR required all generating units to provide detailed information about coal use and mercury content during 1999. The EPA also selected about 100 generating units for one-time stack sampling. We completed testing at the Gibson Generating Station Unit No. 3 and the Wabash River Repowering Project in October 1999.

On December 14, 2000, the EPA made its regulatory determination on the need for additional regulation of mercury emissions from coal-fired power plants. 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 effects of the EPA's determination and subsequent regulation.

New Source Review (NSR) The CAA's NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major change to an existing facility unless the changes are exempt. In July 1998, the EPA requested comments on proposed revisions to the NSR rules that would change NSR applicability by eliminating exemptions contained in the current regulation.

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

On September 15, 1999, November 3, 1999, and February 2, 2001, the Attorney General's of New York, Connecticut, and New Jersey, respectively, issued letters notifyingCinergy andCG&E of their

intent to sue under the citizens' suit provisions of the CAA. These states allege violations of the CAA by constructing and continuing to operate a major change toCG&E's Beckjord Station without obtaining the required NSR pre-construction permits.

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

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

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

On March 1, 2000, the EPA also filed an amended complaint in a separate lawsuit alleging violations of the CAA relating to NSR, Prevention of Significant Deterioration (PSD), and Ohio SIP requirements regarding a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, the Dayton Power and Light Company (DP&L), andCG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP.

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

See "EPA Agreement" below for a discussion of the tentative EPA settlement, which relates to matters discussed herein.

Beckjord Station NOV On November 30, 1999, the EPA filed an NOV againstCinergy andCG &E alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit. The NOV indicated that the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. The allegations contained in this NOV were incorporated within the March 1, 2000 amended complaint, as discussed in the "New Source Review" section. On June 22, 2000, the EPA issued an NOV and a Finding of Violation (FOV) alleging additional particulate emission violations at Beckjord Station and offered us an opportunity to meet and discuss the allegations and corrective measures. The NOV/FOV indicated the EPA may issue an administrative compliance order, issue an administrative penalty order, or bring a civil or criminal action.

See "EPA Agreement" below for a discussion of the tentative EPA settlement, which relates to matters discussed herein.

EPA Agreement On December 21, 2000,Cinergy,CG&E, andPSI reached an agreement in principle with the EPA, the U.S. Department of Justice, three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated byCinergy's operating subsidiaries. The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties. If a final agreement is reached with these parties, this would resolve past claims of the NSR as well as the Beckjord Station NOVs/FOV discussed above.

Under the terms of the tentative agreement, the EPA and the other plaintiffs have agreed to drop all challenges of past maintenance and repair activities at our coal-fired generation plants. In addition, the intent of the tentative agreement is that we would be allowed to continue on-going activities to maintain reliability and availability without subjecting the plants to future litigation regarding federal permitting requirements.

In return for resolution of past claims, future operational certainty, and protection of system wide demand growth, we have tentatively agreed to:

•: shut down or repower with natural gas nine small coal-fired boilers at three power plants beginning in 2004;
•: build four additional SO₂ scrubbers, the first of which must be operational by December 31, 2007;
•: upgrade existing pollution control systems;
•: phase in the operation of NO_X reduction technology year-round starting in 2004;
•: retire 50,000 tons of SO₂ allowances between 2001 and 2005 and reduce our SO₂ cap by 35% in 2013;
•: pay a civil penalty of $8.5 million to the U.S. government; and
•: implement $21.5 million in environmental mitigation projects.

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

In reaching the tentative agreement, we did not admit any wrongdoing and remain free to continue our current maintenance practices, as well as implement future projects for improved reliability. If the settlement is not completed, we believe the allegations contained in the amended complaint are without merit, and we would defend the suit vigorously in court. In such an event, it is not possible at this time to determine the likelihood that the plaintiffs would prevail on their claims or whether resolution of this matter would have a material effect on our financial condition or results of operations.

Manufactured Gas Plant (MGP) Sites PSI received claims from Indiana Gas Company, Inc. (IGC) in 1994, and from Northern Indiana Public Service Company (NIPSCO) in 1995, as more fully discussed in Note 12(f)(ii) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data". The basis of these claims was thatPSI is a Potentially Responsible Party with respect to certain MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted thatPSI is legally responsible for the costs of investigating and remediating the sites. In August 1997, NIPSCO filed suit againstPSI in federal court claiming recovery (pursuant to CERCLA) of NIPSCO's past and future costs of investigating and remediating MGP-related contamination at the Goshen MGP site.

remediation activities at each of the sites to one of the parties. Similar agreements were reached between IGC andPSI that allocate CERCLA liability at 14 MGP sites with which NIPSCO was not involved. These agreements conclude all CERCLA and similar claims between the three companies related to MGP sites. The parties continue to investigate and remediate the sites, as appropriate under the agreements and applicable laws. The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of some of the sites.

PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and the IDEM. In April 1998,PSI filed suit in Hendricks County Circuit Court in the State of Indiana (Court) against its general liability insurance carriers. Among other matters,PSI requested a declaratory judgment that would obligate its insurance carriers to (1) defend MGP claims againstPSI, or (2) payPSI's costs of defense and compensatePSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. Recently, the trial date for the case was moved from May 2001 to January 2002. In addition, the Court has ordered the parties to submit the case to mediation. The parties have selected a mediator and scheduled mediation sessions in early 2001.PSI cannot predict the outcome of this litigation. Recently,PSI has been involved in settlement discussions with some of the insurance carriers. At the present time,PSI cannot predict either the progress or outcome of these discussions.

PSI has accrued costs for the sites related to investigation, remediation, and groundwater monitoring to the extent such costs are probable and can be reasonably estimated.PSI does not believe it can provide an estimate of the reasonably possible total remediation costs for any site before a remedial investigation/feasibility study has been completed. To the extent remediation is necessary, the timing of the remediation activities impacts the cost of remediation. Therefore,PSI currently cannot determine the total costs that may be incurred in connection with the remediation of all sites, to the extent that remediation is required. According to current information, these future costs at the 21 Indiana MGP sites are not material to our financial condition or results of operations. As further investigation and remediation activities are performed at these sites, the potential liability for the 21 Indiana MGP sites could be material to our financial position or results of operations.

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

Construction and Other Commitments

Actual construction and other committed expenditures for 2000 and forecasted construction and other committed expenditures for the year 2001 and for the five-year period 2001-2005 (in nominal dollars) are presented in the table below:

	Actual Expenditures		Forecasted Expenditures
	2000		2001		2001-2005
	(in millions)
Cinergy(1)	$	778	$	1,467	$	4,635
CG&E and subsidiaries		265		423		1,676
PSI		261		406		2,264
ULH&P		28		37		178

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

This forecast includes an estimate of expenditures in accordance with the companies' plans regarding NO_X emission control standards and other environmental compliance (excluding

implementation of the tentative EPA Agreement), as discussed in the "Environmental Issues" section. Approximately $210 million is estimated to be spent in 2001 and approximately $789 million is estimated to be spent between 2001 and 2005. This forecast also includes expenditures for the pending purchase of two natural gas-fired merchant electric generating facilities from Enron North America (Enron) with a total combined capacity of 998 megawatts (MW), the acquisition of an interest in a gas distribution business in Athens, Greece, and other committed investments.

All forecasted amounts reflect the following assumptions relating to the factors below, which may change significantly:

•: the general economy;
•: capital markets;
•: construction programs;
•: legislative and regulatory actions;
•: frequency and timing of rate proceedings; and
•: other related factors.

Other Investing Activities

Our goal is to pursue a market leadership position in our regional Midwest market and at the same time extend that market leadership position to neighboring areas. In pursuit of this goal, we have entered into various growth initiatives including:

•: "new market" energy merchant businesses;
•: industrial infrastructure cogeneration and combined heat and power businesses; and
•: power technology and infrastructure businesses.

We are consistently working towards maximizing the value of existing assets and operations. We will continue to explore and implement the use of mergers, acquisitions, strategic combinations, and internal expansions if they enhance our ability to achieve our goal of creating a competitive advantage.

Our ability to invest in growth initiatives is limited by certain legal and regulatory requirements, including the PUHCA. The PUHCA restricts the amount which can be invested in 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 regulations, 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 a special purpose entity that owns or operates domestic or foreign electric generating facilities whose power is sold entirely at wholesale. 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, or the distribution of gas at retail.

In late 1999, we filed a request with the SEC under the PUHCA for an additional $5 billion in authority to invest in EWGs and FUCOs. On June 23, 2000, the SEC issued an interim order granting us authority to invest a total of $1.7 billion in EWGs and FUCOs, replacing an earlier order capping our investment authority under PUHCA at an amount equal toCinergy's average retained earnings from time to time. As of December 31, 2000, we had invested or committed to invest $1.4 billion of the $1.7 billion available.

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

SEC regulations under the PUHCA permitCinergy 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),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, 2000, 15% ofCinergy's consolidated capitalization was approximately $1 billion, and we had invested approximately $.7 billion, leaving $.3 billion available for additional investing.

CAPITAL RESOURCES

During 2000, we met our capital requirements through a combination of internally generated funds and debt issuances. We expect to meet our future capital needs through a combination of internally and externally generated funds, including the issuance of debt and/or equity securities.

In early 2000,Cinergy Corp. filed a request with the SEC under the PUHCA for an amendment to its certificate of incorporation authorizing the issuance of preferred securities in addition to common stock. We also requested SEC authority to solicit proxies for shareholder approval of this amendment. In June 2000, we received the authorization from the SEC. At this time, it is not known whether shareholder approval will be granted or, if granted, whether or when any preferred stock will be issued.

Internally Generated Funds

As of December 31, 2000, a significant portion of our revenues and corresponding cash flows were derived from our regulated subsidiaries. With the passage of customer choice legislation in several states, we believe it is likely the generation component of the electric utility industry will ultimately be deregulated. (Within our own utility jurisdictions, only Ohio is currently in the process of transitioning to a deregulated environment. Refer to the "Retail Market Developments" section.) As a low cost provider of energy service, we believe we will be successful in this competitive environment. However, as the industry becomes more competitive, future cash flows from operations could be subject to a higher degree of volatility than under our present regulatory structure. In 2001, we believe revenues provided by our regulated operations will continue as a major source of funds.

Debt

We are required to secure authority to issue 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 debt forCinergy Corp. Our three state utility commissions regulate the issuance of debt for our operating companies. On June 23, 2000, the SEC issued an order under the PUHCA authorizingCinergy Corp. to increase its total capitalization at December 31, 1999, (excluding retained earnings and accumulated other comprehensive income) by an additional $5 billion, through 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.'s consolidated capital structure and thatCinergy Corp., under certain circumstances, maintains an investment grade rating on its senior debt obligations. This increased authority is intended to provideCinergy Corp. flexibility to respond quickly and efficiently to financing needs and available conditions in capital markets.

Short-term Debt In connection with the current SEC authorization,Cinergy Corp. has $795 million established lines of credit. As of December 31, 2000,Cinergy Corp. had $157 million unused and available on its established lines. In early 2001,Cinergy Corp. successfully placed a new $400 million, 364-day revolving credit facility. This new facility will support an expansion of our commercial paper program and is not included in the lines of credit discussed above.

Our operating companies have regulatory authority to borrow up to a total of $853 million in short-term debt ($453 million forCG&E and its subsidiaries including $50 million forULH&P, and $400 million forPSI). In connection with this authority, we have established lines of credit forCG&E andPSI, $120 million and $185 million, respectively, of which, $40 million and $80 million, respectively, remained unused and available at December 31, 2000.

Also, certain of our non-regulated subsidiaries have established lines of credit. As of December 31, 2000, $1.9 million was unused and available on these established lines. Our non-regulated subsidiaries have the availability of funds fromCinergy Corp. if the need arises.

As of December 31, 2000, the commercial paper (debt instruments exchanged between companies) program is limited to a maximum outstanding principal amount of $400 million forCinergy Corp. As of December 31, 2000,Cinergy Corp. had issued $216 million in commercial paper. Additionally,CG&E andPSI have the capacity to issue commercial paper, which must be supported by available committed lines of the respective company. The maximum outstanding principal amount forCG&E is $200 million and forPSI is $100 million. NeitherCG&E norPSI issued commercial paper in 2000 or 1999.

In early 2001,Cinergy Corp. expanded the commercial paper program to a maximum outstanding principal amount of $800 million and reduced the established lines of credit atCG&E andPSI. The expansion of the commercial paper program at theCinergy Corp. level will, in part, support the short-term borrowing needs ofCG&E andPSI and will eliminate the need for commercial paper programs atCG&E andPSI. TheCinergy Corp. commercial paper program expansion is supported by the new $400 million, 364-day revolving credit facility as discussed above.

For a detailed discussion of the registrants' short-term indebtedness, refer to Note 5 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

Long-term Debt Under the PUHCA authorization mentioned above, we are able to issue and sell long-term debt at the parent holding company level. As of December 31, 2000,Cinergy Corp. had $400 million of long-term debt outstanding.

Currently, our operating companies have outstanding long-term debt in the form of First Mortgage Bonds and Other Secured Notes, and Senior and Junior Unsecured Debt. Under our existing authority, the remaining authorized but unissued debt, as of December 31, 2000, is reflected in the following table:

Authorizing Agency		CG&E			PSI			ULH&P
		(in millions)
Applicable State Utility Commission (Secured or Unsecured Debt)		$	200		$	346		$	30

We may, at any time, request additional long-term debt authorization. This request is subject to regulatory approval, which may or may not be granted.

As of December 31, 2000, through shelf registrations filed with the SEC under the Securities Act of 1933, we could issue the following amounts of debt securities:

	CG&E		PSI		ULH&P
	(in millions)
First Mortgage Bonds and Other Secured Notes	$	300	$	265	$	20
Senior or Junior Unsecured Debt		50		400		30

Capital Leases We are able to enter into capital leases subject to the authorization limitations of the applicable state utility commissions. We may, at any time, request the applicable state utility commission to increase our limits. Any request may or may not be granted. As of December 31, 2000, unused capital lease authority is $80 million forCG&E, $88 million forPSI, and $25 million forULH&P.

Common Stock

In addition to the authority to issue common stock pursuant to the SEC's June 23, 2000 order permittingCinergy Corp. to increase its total capitalization by $5 billion (as previously discussed),Cinergy Corp. has SEC authority to issue an additional 50 million shares of common stock for our various stock-based plans. 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.

The following table reflects the number of shares purchased and issued for our various stock-based plans:

	2000	1999	1998
	(in thousands)
Purchased Shares	2,299	748	861
Issued Shares	77	291	194

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

Dividend Restrictions

For a discussion of dividend restrictions, refer to Note 2(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

Securities Ratings

As of January 31, 2001, the major credit rating agencies rated our securities as follows:

		Fitch(1)	Moody's(2)	S&P(3)
Cinergy Corp.
	Corporate Credit	BBB+	Baa2	BBB+/A-2
	Senior Unsecured Debt	BBB+	Baa2	BBB+
	Commercial Paper	F-2	P-2	A-2
CG&E
	Senior Secured Debt	A-	A3	A-
	Senior Unsecured Debt	BBB+	Baa1	BBB+
	Junior Unsecured Debt	BBB	Baa2	BBB
	Preferred Stock	BBB	baa1	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	baa1	BBB
	Commercial Paper	F-2	P-2	Not Rated
ULH&P
	Senior Unsecured Debt	Not Rated	Baa1	BBB+

(1): During 2000, Fitch IBCA, Inc. and Duff & Phelps Credit Rating Co. merged, and are now known as Fitch, thereby combining their ratings ofCinergy Corp. and its affiliates.
(2): Moody's Investors Service (Moody's)
(3): Standard & Poor's Ratings Services (S&P)

On December 12, 2000, S&P placed its ratings ofCinergy Corp. and its operating affiliates,CG&E andPSI, 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 are primarily in response toCinergy's announcement regarding one of its

non-regulated subsidiaries entering into a definitive agreement to acquire two natural gas-fired merchant electric generating facilities from Enron (as further discussed in the "Wholesale Market Developments" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"). Other items of concern include (1) the announcement thatCinergy Corp.,CG&E, andPSI have reached an agreement in principle with the EPA; (2) the continuing uncertainty surroundingCG&E's post-deregulation corporate and financial structure; (3) the absence of restructuring legislation and stranded investment resolution in Indiana; and (4) Cinergy's emphasis on higher-risk non-regulated activities.

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

Guarantees

We are subject to a SEC order under the PUHCA, which limits the amountsCinergy Corp. can have outstanding under guarantees (promises to pay by one party in the event of default by another party) at any one time to $2 billion. As of December 31, 2000, we had $1.4 billion outstanding under the guarantees issued. This amount representsCinergy Corp.'s guarantees of liabilities and commitments of our consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures.

Sale of Accounts Receivable

For the detailed discussion of our sales of accounts receivable, refer to Note 6 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

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

2000 RESULTS OF OPERATIONS

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				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 ofCinergy also include amounts related to non-registrants.

Our diluted earnings per share (EPS) for the year ended December 31, 2000, were $2.50 per share, as compared to $2.53 per share 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 last year, 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 10 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 compared with 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 milder 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 a limited early retirement program 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					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			2,464		1,455	69			1,226		687	78		1,443		840	72
Other			228		133	71			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 ofCinergy also 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 megawatt hour (MWh) realized on non-firm wholesale transactions related to the commodities supply business. Non-firm power is power without a guaranteed commitment for physical delivery.

The increase in other electric operating revenues forCinergy primarily reflects marketing activities of Cinergy Capital and Trading, Inc., aCinergy non-regulated affiliate.

GAS OPERATING REVENUES

	Cinergy(1)					CG&E and subsidiaries
	2000		1999		% Change	2000		1999		% Change
	(in millions)
Non-regulated	$	2,452	$	1,221	101	$	—	$	—	—
Retail		429		320	34		429		320	34
Transportation		56		51	10		56		51	10
Other		5		4	25		6		5	20

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

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

Gas operating revenues forCinergy increased in 2000, when compared to 1999, primarily as a result of a higher price realized per thousand cubic feet (mcf) sold by our commodity supply business.

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 has increased significantly in 2000, which has causedCG&E to pay more for the gas they deliver 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 under state law.

OTHER REVENUES

Other operating revenues forCinergy increased $67 million for 2000, when 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		1999		% Change
	(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		1,089		981	11		463		416	11			462		461	—
Depreciation and amortization		374		354	6		210		204	3			143		136	5
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 ofCinergy also include amounts related to non-registrants.

Fuel

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

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

Purchased and Exchanged Power

Purchased and exchanged power expense increased forCinergy,CG&E, andPSI for 2000, when 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 our commodity supply business.

Gas Purchased

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

Operation and Maintenance

Cinergy'sOperation and maintenance expenses increased in 2000, in comparison 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 a limited early retirement plan offered as part of a corporate restructuring initiative.

Depreciation and Amortization

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

EQUITY IN EARNINGS OF UNCONSOLIDATED SUBSIDIARIES

Cinergy'sEquity in earnings of unconsolidated subsidiaries decreased $53 million in 2000, as compared to 1999. This decrease is 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 10 of the "Notes to the 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 is 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.

ULH&P

The Results of Operations discussion forULH&P is presented only for the year ended December 31, 2000, in accordance with General Instructions I(2)(a).

Electric and gas margins and net income forULH&P for the years ended December 31, 2000, and 1999 were as follows:

	ULH&P
	2000		1999
	(in thousands)
Electric gross margin	$	65,686	$	51,678
Gas gross margin		40,359		36,038
Net income		24,632		12,274

The increase in electric gross margin is primarily due to the effects of a Federal Energy Regulatory Commission (FERC) wholesale rate case that became effective during 2000. For further information see Note 12 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data". Gas gross margin increased primarily as a result of an increase in volumes sold.

The increase inOperation and maintenance costs for the year ended December 31, 2000, as compared to 1999, was primarily the result of expenses related to a water main break in Newport, Kentucky, on October 5, 2000, that resulted in damage to our gas main.

The increase inDepreciation for the year ended December 31, 2000, as compared to 1999, was due to additions to depreciable plant.

1999 RESULTS OF OPERATIONS

SUMMARY OF RESULTS

Electric and gas margins and net income forCinergy,CG&E, andPSI for the years ended December 31, 1999, and 1998, were as follows:

	Cinergy(1)				CG&E				PSI
	1999		1998		1999		1998		1999		1998
	(in thousands)
Electric gross margin	$	2,052,602	$	1,909,423	$	1,108,371	$	1,045,556	$	922,053	$	855,527
Gas gross margin		212,153		204,684		204,016		203,748		—		—
Net income		403,641		260,968		233,576		215,812		117,199		52,038

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

Our 1999 diluted EPS increased to $2.53 from $1.65 per share for 1998.

The overall increase in EPS for 1999 was mainly due to our international operations and our regulated electric operations. The contribution to earnings of our international operations increased $.36 per share for the year ended December 31, 1999, compared with 1998, primarily the result of the sale of our 50% ownership interest in Midlands. Earnings from regulated operations had a net increase of $.55 per share for the year ended December 31, 1999, compared with a year earlier. The increase was primarily due to an overall return to more normal weather in 1999 and growth in retail electric revenues. This retail revenue growth reflected an increase in residential and commercial customers and growth in the industrial market. Included in this overall increase was a $.36 per share reduction related to energy marketing and trading losses experienced in July 1999. Our electric margins were positively impacted $12 million or $.07 per share (net of fuel and income taxes) as a result of a change in estimate ofPSI's utility services delivered but unbilled at month end which occurred during the third quarter of 1999.

The 1999 increase in earnings from regulated operations was also impacted by the following 1998 charges:

•: a reduction of $.14 per share for the effects of milder than normal weather;
•: a charge of $.32 per share related to a settlement with Wabash Valley Power Association, Inc. (WVPA). See Note 17 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the WVPA settlement; and
•: total charges of $.54 per share due to losses related to our energy marketing and trading activity.

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						PSI
	1999		1998		% Change		1999		1998		% Change		1999		1998		% Change
	(in millions)
Retail	$	2,725	$	2,553	7		$	1,468	$	1,392	5		$	1,258	$	1,161	8
Wholesale		1,455		2,140	(32	)		687		1,046	(34	)		840		1,206	(30	)
Other		133		70	90			20		15	33			38		36	6

Total	$	4,313	$	4,763	(9	)	$	2,175	$	2,453	(11	)	$	2,136	$	2,403	(11	)

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

Electric operating revenues forCinergy,CG&E, andPSI decreased for 1999, as compared to 1998, due to a decrease in volumes on non-firm wholesale transactions related to energy marketing and trading activity. Partially offsetting the decline was an increase in the average price per MWh realized for non-firm power transactions and higher firm wholesale MWh sales. Non-firm power is power without a guaranteed commitment for physical delivery. Retail MWh sales also increased as a result of new residential and commercial customers, growth in the industrial market, and an overall return to more normal weather. Our electric margins were positively impacted $12 million or $.07 per share (net of fuel and income taxes) as a result of a change in estimate ofPSI's utility services delivered but unbilled at month end which occurred during the third quarter of 1999.

GAS OPERATING REVENUES

	Cinergy(1)						CG&E and subsidiaries
	1999		1998		% Change		1999		1998		% Change
	(in millions)
Non-regulated	$	1,221	$	698	75		$	—	$	—	—
Retail		320		357	(10	)		320		357	(10	)
Transportation		51		41	24			51		41	24
Other		4		4	—			5		5	—

Total	$	1,596	$	1,100	45		$	376	$	403	(7	)

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

Gas operating revenues forCinergy increased in 1999, when compared to 1998. This increase reflected a full year's realization of the gas operating revenues of Cinergy Marketing and Trading, LLC (Marketing & Trading), an indirect subsidiary ofCinergy that was acquired in June 1998. Based on the actual results of Marketing & Trading for 1998, if we had owned it for all of 1998, our 1999 revenues, as compared to 1998, would have increased due to a higher price received per mcf sold.

CG&E's retail gas revenues decreased due to a decline in mcf sales. This resulted primarily from milder weather experienced during the first quarter of 1999. This decline was partially offset by an increase in transportation revenues due to the continued progression of full-service customers (customers who purchase gas and utilize the transportation services ofCG&E) purchasing gas directly from suppliers and using transportation services provided byCG&E.

OPERATING EXPENSES

	Cinergy(1)						CG&E and subsidiaries						PSI
	1999		1998		% Change		1999		1998		% Change		1999		1998		% Change
	(in millions)
Fuel	$	761	$	730	4		$	341	$	339	1		$	397	$	382	4
Purchased and exchanged power		1,499		2,124	(29	)		726		1,068	(32	)		817		1,166	(30	)
Gas purchased		1,384		895	55			172		200	(14	)		—		—	—
Operation and maintenance		981		976	—			416		393	6			461		509	(9	)
Depreciation and amortization		354		326	9			204		191	7			136		131	4
Taxes other than income taxes		266		275	(3	)		212		217	(2	)		53		54	(2	)

Total	$	5,245	$	5,326	(2	)	$	2,071	$	2,408	(14	)	$	1,864	$	2,242	(17	)

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

Fuel

Fuel represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from 1998 to 1999:

	Cinergy(1)			CG&E and subsidiaries			PSI
				(in millions)
1998 fuel expense	$	730		$	339		$	382
Increase (Decrease) due to changes in:
Price of fuel		—			4			(5	)
Deferred fuel cost		(10	)		(15	)		5
MWh generation		28			13			15
Other		13			—			—

1999 fuel expense	$	761		$	341		$	397

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

Purchased and Exchanged Power

�� Purchased and exchanged power is the electricity that is bought to be sold through our energy marketing and trading activities.Purchased and exchanged power is also occasionally purchased forPSI's andCG&E's retail customers. This expense decreased forCinergy,CG&E, andPSI in 1999. This decrease was primarily due to a reduction in purchases of non-firm wholesale power as a result of a decline in sales volume in the energy marketing and trading operations.

Included in purchased and exchanged power are additional costs related to energy marketing and trading losses experienced in July 1999, as previously indicated above in "Summary of Results", as well as losses related to our 1998 energy marketing and trading activity.

Gas Purchased

Gas purchased expense increased forCinergy in 1999, when compared to 1998. This increase primarily reflected a full year'sGas purchased volumes for Marketing & Trading in 1999, as previously indicated above in "Gas Operating Revenues".

CG&E'sGas purchased expense decreased for 1999, as compared to 1998. This decline was mainly due to decreased sales volumes as previously indicated above in "Gas Operating Revenues".

Operation and Maintenance

PSI'sOperation costs decreased in 1999, in comparison to 1998. This decrease was the result of a one-time charge of $80 million in 1998 for the implementation of the 1989 settlement with WVPA. See Note 17 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" for a discussion of the WVPA settlement.

Cinergy's,CG&E's, andPSI'sMaintenance costs increased in 1999, as compared to 1998, primarily as a result of planned outages and repairs at certain production facilities. These activities represented a return to a more normal level of maintenance expenditures.

Depreciation and Amortization

Cinergy's,CG&E's, andPSI'sDepreciation and amortization costs increased in 1999, as compared to 1998. These increases were the result of additions to depreciable plant. Additionally,Cinergy's andCG&E's increases also included the amortization of phase-in deferrals reflecting the Public Utilities Commission of Ohio (PUCO)-approved phase-in plan forCG&E's William H. Zimmer Station.

EQUITY IN EARNINGS OF UNCONSOLIDATED SUBSIDIARIES

Cinergy'sEquity in earnings of unconsolidated subsidiaries increased $7 million in 1999, as compared to 1998. This increase was primarily driven by the earnings of our non-regulated domestic and international subsidiaries. Included inEquity in earnings of unconsolidated subsidiaries was $58 million for 1999, and $57 million for 1998, related to our 50% ownership interest in Midlands. For further information see Note 10 of the "Notes to the Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

GAIN ON SALE OF INVESTMENT IN UNCONSOLIDATED SUBSIDIARY

On July 15, 1999, we sold our 50% ownership interest in Midlands, as previously indicated above in "Summary of Results." The sale resulted in a net contribution to earnings of approximately $.43 per share (basic and diluted). For a further discussion of this transaction, see Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

PREFERRED DIVIDEND REQUIREMENTS

Cinergy'sPreferred dividend requirements of subsidiaries andPSI'sPreferred dividend requirement each decreased $1 million for 1999, as compared to 1998. These decreases were attributable toPSI's redemption of all outstanding shares of its 7.44% Series Cumulative Preferred Stock on March 1, 1998.

FUTURE EXPECTATIONS/TRENDS

In the "Future Expectations/Trends" section, we discuss electric and gas industry developments, market risk sensitive instruments and positions, accounting changes, and the shareholder rights plan. 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 exempt wholesale generators, independent power producers, and power marketers. We are involved in wholesale power marketing and trading through Commodities.

In late June 1998, and again in late July 1999, 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 customers and supply.

Supply-side Actions On September 30, 1999, one of our non-regulated subsidiaries formed a partnership (each party having a 50 percent 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.

On March 9, 2000, the Indiana Utility Regulatory Commission (IURC) issued an order, requiring the partnership to immediately suspend all construction activities at the site located near Cadiz, (Henry County) Indiana (a peaking plant with a total capacity of 129 MW, of which we own 65 MW). In making this decision the IURC found that it needed additional information related to the project before issuing a final decision. The IURC requested the Henry County Planning Commission and/or the Henry County Commissioners to supply additional information, which was provided on June 1, 2000. The issues raised were air quality, water supply, noise control, landscaping, plant abandonment, and emergency services training. During the third quarter of 2000, the partnership filed responses to the issues indicating how it would address these concerns. The IURC held a hearing on this matter on November 17, 2000, and a ruling is expected in the first half of 2001. Although we expect a favorable ruling from the IURC, at this timeCinergy cannot predict the outcome of this matter.

The remaining two facilities became fully operational in June 2000. The total capacity of these operational plants is approximately 1,280 MW.

On December 12, 2000,Cinergy announced that one of its non-regulated affiliates entered into a definitive agreement with Enron to acquire two natural gas-fired merchant electric generating facilities. The acquisition will consist of a 494 MW facility in Tennessee and a 504 MW facility in Mississippi.

Cinergy's portfolio of natural gas-fired peaking stations has increased due to the partnership with Duke and the pending consummation of the acquisition of the Enron units.CG&E andPSI also have an additional 856 MW of capacity that are natural gas-fired. These units are used to meet the demand for electric commodity in periods of high electric use by our customers. In the latter part of 2000 natural gas was selling at record prices. If it is necessary forCinergy to call upon the use of our natural gas-fired peakers, the cost of natural gas will directly affectCinergy's cost to supply the electric commodity to our customers.

Demand-side Actions Demand (the amount of electric power that can be used at a point in time) on our system is expected to be reduced in future years as a result of the expiration of existing wholesale contractual obligations and peak load management initiatives which we have recently developed. Also, Ohio's recently enacted customer choice legislation contemplates that 20% ofCG&E's retail load will switch to alternative suppliers by December 2003. In its approved transition plan,CG&E indicated that it currently has no plans to replace these customers by acquiring new retail customers, althoughCG&E reserved the flexibility to replace load in the wholesale market to the extent it chooses. For a further discussion on Ohio deregulation, see Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data".

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, we will continue to transmit and distribute electricity; however, the customer can purchase electricity from any available supplier and we will be compensated by a charge to use our transmission assets. The following sections further discuss the current status of deregulation legislation in the states of Ohio, Indiana, and Kentucky, each of which includes a portion of our service territory.

Federal Update The Clinton Administration and Congress made attempts to legislate comprehensive electric industry restructuring during the past four years. After attempting to reach a consensus on comprehensive electric restructuring legislation, the U.S. Senate, on June 30, 2000, approved S. 2071, the Electric Reliability 2000 Act. The S. 2071 would have authorized the establishment of a North American Electric Reliability Organization and did not legislate on additional issues surrounding the restructuring of the electric industry. President Bush has indicated that legislation addressing the energy security needs of America, deserves prompt consideration. The start of a new congressional session and presidential administration makes comprehensive electric industry deregulation uncertain in the near future.

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. Ohio electric utilities have an opportunity to recover PUCO-approved transition costs during a transition period. The legislation also froze retail electric rates during the market development period, at the rates in effect on October 4, 1999, except for a five-percent reduction in the generation component of residential rates. Furthermore, the legislation contemplated that 20% of the current electric retail customers will switch suppliers no later than December 31, 2003.

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

•: Residential customer rates will be frozen through December 31, 2005;
•: Residential customers will receive a five-percent reduction in the generation portion of their electric rates, effective January 1, 2001;
•: CG&E has agreed to provide four million dollars over the next five years in support of energy efficiency and weatherization services for low income customers;
•: The creation of a Regulatory Transition Charge, designed to recoverCG&E's regulatory assets and other transition costs over a ten-year period;
•: Authority forCG&E to transfer its generation assets to one or more separate, non-regulated corporate subsidiary(ies) to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;
•: Authority forCG&E to apply the proceeds of transition cost recovery to costs incurred during the transition period including implementation costs and purchased power costs that may be incurred byCG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;
•: CG&E will provide standard offer default supplier service (i.e.,CG&E will be the supplier of last resort, so that no customer will be without an electric supplier); and
•: CG &E has agreed to provide shopping credits to switching customers.

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

As previously discussed, the August 31, 2000 order authorizesCG&E to transfer its generation assets to one or more non-regulated corporate subsidiary(ies). This transfer may require the approval or consent of one or more of the following: the IURC, the Kentucky Public Service Commission (KPSC), the FERC, the SEC under the PUHCA, and various third parties. As the transfer is contingent upon the company receiving various consents and approvals, the timing and receipt of which are unknown, the completion date of the transfer of generation assets to a non-regulated subsidiary is uncertain. See Note 1(c) of the "Notes to the Financial Statements" in "Item 8. Financial Statements and Supplementary Data" regarding the effects of the transition order.

In connection with its approved stipulation agreement,CG&E discontinued the application of Statement of Financial Accounting Standards No. 71,Accounting for the Effects of Certain Types of Regulation (Statement 71), for the generation portion of its business and adopted Statement of Financial Accounting Standards No. 101, Regulated Enterprises—Accounting for Discontinuation of Application of FASB Statement No. 71,with no material financial statement impact. Pursuant to Statement of Financial Accounting Standards No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, our analysis indicates future revenues will be sufficient to recover the costs of our generating assets over their estimated remaining lives.

Indiana Due to a "short session" in 2000, the Indiana General Assembly did not consider any electric deregulation initiatives. Electric industry deregulation is not expected to be addressed by the 2001 Indiana General Assembly. We will continue to work with the other Indiana investor-owned utilities in an effort to draft acceptable customer choice legislation. The outcome of this effort remains uncertain.

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 legislation that would open the state's electric industry to competition.

Other States Twenty-four states and the District of Columbia have adopted deregulation plans. In response to the situation in California, some of these states, while not having similar experiences as California, are considering delaying or altering terms of implementation. A number of the remaining states are reconsidering their deregulation timetables. While we believe the situation in Ohio, as

described above, and generally within the Midwest are different than California, we cannot predict the consequences, if any, to efforts to deregulate the remaining markets within our service territory. Indiana and Kentucky have not yet approved legislation.

Other

Under generally accepted accounting principles,PSI,CG&E, andULH&P apply the provisions of Statement 71 to the applicable rate-regulated portions of their businesses. The provisions of Statement 71 allowPSI,CG&E, andULH&P to capitalize (record as a deferred asset) costs that would normally be charged to expense. These costs are classified as regulatory assets in the accompanying financial statements and the majority have been approved by regulators for future recovery from customers through our rates. As of December 31, 2000,PSI,CG&E, andULH&P, have $977 million of net regulatory assets, of which $938 million have been approved for recovery.

Except with respect to the generation assets ofCG&E, as of December 31, 2000,PSI,CG&E, andULH&P continue to meet each of the criteria required for the use of Statement 71. However, as other states implement deregulation legislation, the application of Statement 71 will need to be reviewed. Based on our operating companies' current regulatory orders and the regulatory environment in which they currently operate, the future recovery of regulatory assets recognized in the accompanying Balance Sheets as of December 31, 2000, 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 ISO

As part of the effort to create a competitive wholesale power marketplace, the FERC approved the formation of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) during 1998. In that same year,Cinergy agreed to join the Midwest ISO in preparation for meeting anticipated changes in the FERC regulations and future deregulation requirements. The Midwest ISO was established as a non-profit organization to maintain functional control over the combined transmission systems of its members. The organization was expected to begin operations in November 2001.

On December 13, 2000, six additional transmission owners, includingCinergy, announced a plan for conditional withdrawal from the Midwest ISO, if the other three withdrawing members left the organization.

Repeal of PUHCA

Early in 2001, the 107th Congress introduced S.206, a bill to repeal the PUHCA, in the U.S. Senate. It has been referred to the Senate Banking, Housing and Urban Affairs Committee for action. Various proposals to repeal or amend the PUHCA were considered by the previous Congress. In February 1999, the Senate Banking, Housing and Urban Affairs Committee reported out of committee S.313, a bill to repeal the PUHCA. In June 1999, H.R.2363, a bill to repeal the PUHCA, was introduced in the U.S. House of Representatives as a companion to S.313. At the end of the 106th Congress, no action was taken on passage of either of these bills.

During the Clinton Administration, legislation was introduced which would have repealed the PUHCA as part of a broader restructuring of the electricity industry. At the end of the Clinton Administration, no action was taken on this legislation. President Bush has identified the need for the repeal of the PUHCA as a priority of the federal energy legislation. We support the repeal of the PUHCA either as part of broader restructuring of the electricity industry or as separate legislation.

Significant Rate Developments

Purchased Power Tracker On May 28, 1999,PSI filed a petition with the IURC seeking approval of a purchased power tracking mechanism (Tracker). This request was designed to provide for the recovery of costs related to purchases of power necessary to meet native load requirements to the extent such costs are not sought through the existing fuel adjustment clause. The Tracker applies to a limited number of purchases made for the purpose of ensuring adequate power reserves to meet peak retail native load requirements, which in recent years, have coincided with periods of extreme price volatility. The Tracker only applies to capacity purchases, which are presented for review and approval by the IURC as reasonable under the circumstances. On May 31, 2000, the IURC approved the Tracker for the summer of 2000, subject to a review of the summer of 2000 purchases. The IURC subsequently established a procedural schedule. In the first quarter of 2001, a hearing is scheduled to reviewPSI's 2000 purchases and rule on its associated request for recovery of costs. The IURC will also determine whether it is appropriate forPSI to continue the tracking mechanism for future periods. Amounts relating to PSI's 2000 purchases (approximately $20 million) have been deferred for subsequent recovery.

Purchased Power Agreement ULH&P purchases its energy fromCG&E pursuant to a FERC-approved contract that is due to expire on December 31, 2001. Currently the contract is under negotiation with the involvement of the KPSC. The ultimate supplier(s) ofULH&P's energy and the pricing of electric commodity requirements contained in any new arrangement could reflect a market-based approach. At the current time, we are unable to predict the outcome of this matter.

MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS

Energy Commodities Sensitivity

The transactions associated with Commodities' 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 the market price of electricity or other energy commodities. As Commodities 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 Commodities principally consist ofCG&E's andPSI's power 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. The power marketing and trading operation consists of both physical and trading activities. Transactions are designated as a physical activity when there is intent and ability to physically deliver the power from company-owned generation. All other transactions are considered trading activities. Substantially all of the contracts in both the physical and trading portfolios commit us to purchase or sell electricity at fixed prices in the future. Commodities also markets and trades over-the-counter option contracts. Substantially all of the contracts in the physical portfolio require settlement by physical delivery of electricity. Contracts within the trading portfolio generally require settlement by physical delivery or are netted out in accordance with industry trading standards. The use of these types of physical commodity instruments is designed to allow Commodities to:

•: manage and economically hedge contractual commitments;
•: reduce exposure relative to the volatility of cash market prices; and
•: take advantage of selected arbitrage opportunities.

Commodities 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 Commodities 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.

Commodities measures the market risk inherent in the trading portfolio employing value-at-risk 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. Value-at-risk 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 value-at-risk analysis.

Our value-at-risk 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 value-at-risk for power activities as a percent of consolidated operating income for 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, 2000, the value-at-risk for the power trading activity was less than 1% of 2000 consolidated operating income and as of December 31, 1999, was less than 1% of 1999 consolidated operating income. On a one-day basis at the end of each quarter, the value-at-risk for the power trading activity was less than 1% of consolidated operating income in 2000, and less than 1% in 1999. The daily value-at-risk for the power trading portfolio as of December 31, 1999, was less than 1% of 2000 consolidated operating income and as of December 31, 1998, was also less than 1% of 1999 consolidated operating income. The value-at-risk 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 value-at-risk 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.

Commodities, 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 value-at-risk amounts associated with these other trading and hedging activities were less than one million dollars as of December 31, 2000, and less than two million dollars at December 31, 1999. The market risk exposures of these non-regulated trading activities is not considered significant to our financial condition or results of operations.

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 Delivery's 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 Commodities' power marketing and trading operations are primarily with the traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 2000, we do not believe we had significant exposure to credit risk with our trade accounts receivable within Delivery or our physical portfolio within Commodities.

Power-Trading Contracts within the trading portfolio of the power marketing and trading operations are primarily with power marketers and other investor-owned utilities. As of December 31, 2000, approximately 60% of the activity within the total trading portfolio was with ten counterparties. The majority of these contracts are for terms of one year or less. Electric power 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, especially when dealing with new market entrants. Credit discounts are included in the determination of fair value for all open positions in the power-trading portfolio.

the Western U.S. have been adjusted to reflect a higher level of credit discount. We have also been actively pursuing other forms of credit enhancement including, but not limited to, parent company guarantees and letters of credit from counterparties. In determining fair value for all derivative instruments, we consider the credit quality of each counterparty, contractual netting arrangements for longs and shorts with the same counterparty, and any security obtained. A significant portion of ourEnergy risk management assets andEnergy risk management liabilities —current are with counterparties in the Western U.S. Nonperformance by any of the Western U.S. counterparties could have a material effect on the operating results ofCinergy,CG&E, andPSI.

Gas Trading As of December 31, 2000, approximately 50% of the activity within the physical gas marketing and trading portfolio represented commitments with 20 counterparties. Credit risk losses related to gas and other physical commodity and trading operations have not been significant. At December 31, 2000, the credit risk within the gas and commodity trading portfolios was not believed to be significant because of the characteristics of counterparties and customers with which transactions are executed.

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 risk management and credit functions to ensure compliance with stated risk management policies and procedures. The risk management and credit functions operate independently from the business units and other corporate functions, which originate and actively manage the market and credit risk exposures. The 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. Some of the policies and procedures 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 against currency exchange rate fluctuations.

Cinergy has exposure to fluctuations in exchange rates between the U.S. dollar and the currencies of foreign countries where we have investments. When it is appropriate we will hedge our exposure to cash flow transactions, such as a dividend payment by one of our foreign subsidiaries. As of December 31, 2000, we do not believe we had a material exposure to the currency risk attributable to these investments.

Interest Rate Sensitivity

Our exposure to changes in interest rates consists of short-term debt instruments, pollution control debt, sales of accounts receivable, and capital leases. The following table reflects the different instruments used and the method of benchmarking interest rates, as of December 31, 2000, and 1999:

			Interest Benchmark		2000		1999
					(in millions)
Short-term Bank Loans/Commercial Paper		•	Short-term Money Market	Cinergy	$	862	$	283
		•	LIBOR(1)	CG&E		80		51
				PSI		105		150
Pollution Control Debt		•	Daily Market	Cinergy		267		267
	��			CG&E		184		184
				PSI		83		83
Sales of Accounts Receivable		•	Short-term Money Market	Cinergy		257		257
				CG&E		156		157
				ULH&P		26		21
				PSI		101		100
Variable Rate Capital Leases		•	LIBOR(1)	Cinergy		31		22
				CG&E		31		22

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

The weighted-average interest rates on the above instruments at December 31, 2000, and 1999, were as follows:

	2000		1999
Short-term Bank Loans/Commercial Paper	7.0	%	6.2	%
Pollution Control Debt	4.5	%	4.1	%
Sales of Accounts Receivable	6.6	%	6.1	%
Variable Rate Capital Leases	7.5	%	5.3	%

At December 31, 2000, forward yield curves project a decrease 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, 2000:

		Expected Maturity Date
Liabilities		2001			2002			2003			2004			2005			There- after			Total			Fair Value
		(in millions)
Cinergy
Long-term Debt(1)		$	90	(4)	$	124		$	177	(5)	$	311		$	51	(6)	$	2,126		$	2,879		$	2,901
	Weighted-average interest rate(2)		5.2	%		7.3	%		6.2	%		6.2	%		6.5	%		7.0	%		6.8	%
Other(3)		$	1.0		$	21.0		$	8.2		$	1.8		$	1.6		$	15.0		$	48.6		$	49.2
	Weighted-average interest rate(2)		7.2	%		7.4	%		7.4	%		7.2	%		7.2	%		7.2	%		7.3	%
Capital Leases
	Fixed rate leases	$	1.8		$	1.9		$	2.1		$	2.2		$	2.4		$	14.5		$	24.9		$	24.9
	Interest rate		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%
	Variable rate leases	$	22.9		$	0.9		$	0.9		$	0.9		$	0.9		$	4.6		$	31.1		$	31.1
	Weighted-average interest rate(2)		7.5	%		8.3	%		8.3	%		8.3	%		8.3	%		8.3	%		7.5	%
CG&E and subsidiaries
Long-term Debt(1)		$	1		$	100		$	120	(5)	$	110		$	—		$	878		$	1,209		$	1,203
	Weighted-average interest rate(2)		9.8	%		7.3	%		6.3	%		6.5	%		—			6.9	%		6.8	%
Capital Leases
	Fixed rate leases	$	1.0		$	1.0		$	1.1		$	1.2		$	1.3		$	7.9		$	13.5		$	13.5
	Interest rate		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%
	Variable rate leases	$	22.9		$	0.9		$	0.9		$	0.9		$	0.9		$	4.6		$	31.1		$	31.1
	Weighted-average interest rate(2)		7.5	%		8.3	%		8.3	%		8.3	%		8.3	%		8.3	%		7.5	%
PSI
Long-term Debt(1)		$	89	(4)	$	24		$	57		$	1		$	51	(6)	$	898		$	1,120		$	1,136
	Weighted-average interest rate(2)		5.2	%		7.6	%		5.9	%		6.0	%		6.5	%		7.3	%		7.0	%
Capital Lease
	Fixed rate leases	$	0.8		$	0.9		$	1.0		$	1.0		$	1.1		$	6.5		$	11.3		$	11.3
	Interest rate		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%

ULH&P
Long-term Debt(1)			—			—		$	20			—			—		$	55		$	75		$	76
	Weighted-average interest rate(2)		—			—			6.1	%		—			—			7.3	%		7.0	%
Capital Lease
	Fixed rate leases	$	0.3		$	0.4		$	0.4		$	0.4		$	0.4		$	2.8		$	4.7		$	4.7
	Interest rate		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%		6.5	%

(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 variable rate capital leases, the interest rate is based on a spread over 3-month LIBOR, and averaged to be approximately 7.5% in 2000; (3) for the fixed rate capital leases, the interest rate is fixed at approximately 6.50% with an amortizing principal structure; and (4) for the Global Resources investment, the interest rate is based on a spread over 6- and 12-month LIBOR.
(3): Variable rate debt related to an investment under Global Resources.
(4): 6.00% Debentures due December 14, 2016, reflected as maturing in 2001, as the interest rate resets on December 14, 2001.
(5): 6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.
(6): 6.50% Debentures due in 2026, reflected as maturing in 2005, as the interest rate resets on August 1, 2005.

Our current policy in managing exposure to fluctuations in interest rates is to maintain approximately 25% of the total amount outstanding debt in floating interest rate debt instruments. To help maintain this level of exposure, we have previously, and will consider in the future, entering into 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.PSI had an interest rate swap agreement that expired on November 15, 2000, which had a notional amount of $100 million.CG&E has an outstanding interest rate swap agreement that decreased the percentage of floating rate debt. Under the seven year agreement, which has a notional amount of $100 million,CG&E pays a fixed rate and receives a floating rate. This swap qualifies as a cash flow hedge under the provisions of Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (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 be effective as a hedge. Future changes in fair value of this swap will be recorded inAccumulated other comprehensive income (loss), beginning with our adoption of Statement 133 effective January 1, 2001. In the future, we will continually monitor market conditions to evaluate whether to increase, or decrease, our level of exposure to fluctuations in interest rates.

GAS INDUSTRY

Customer Choice In 1997, the state of Ohio commenced a customer choice program for the gas utility industry. This voluntary program gives residential and small commercial customers the opportunity to select their own gas supplier. Approximately two-thirds of the gas customers in the state of Ohio are eligible to participate. This program excludes large industrial, commercial, and educational institution customers because they already have the ability to select their own gas supplier.

Although the gas supplier may vary by customer,CG&E continues to provide gas transportation services for substantially all customers within its franchise territory.

In early 2001, an alternative gas supplier withinCG&E's franchise territory was removed from participating in the Ohio Gas Customer Choice program as a result of numerous violations of the terms and conditions of the program.CG&E has filed a complaint with the PUCO requesting a finding that it complied with the terms and conditions of the Ohio Gas Customer Choice program in terminating the supplier from the program.CG&E is also requesting reimbursement of its costs incurred to date in connection with this matter.CG&E estimates that the financial statement exposure is immaterial.

In early 2001,Cinergy,CG&E, and Cinergy Resources, Inc. (a former subsidiary of Investments which was sold in January 2000) were named as defendants in two class action lawsuits. These lawsuits are in connection with the above referenced alternative gas supplier's removal from the Ohio Gas Customer Choice program and its failure to deliver gas supply to its customers. At the present time,Cinergy andCG&E cannot predict the outcome of this litigation.

Gas Prices The market price of natural gas has increased significantly in 2000, which has causedCG&E andULH&P to pay more for the gas they deliver to customers. NeitherCG&E norULH&P profit from changes in the cost of gas. This cost is passed directly through to the customer—dollar-for-dollar—under the gas cost recovery mechanisms that are applicable in Ohio and Kentucky. In addition to regularly scheduled filings, bothCG&E andULH&P made several interim filings during 2000 for increased gas cost recovery rates with the PUCO and the KPSC, respectively, in order to keep the rates passed through to customers as current as possible. In January 2001, the KPSC ordered all gas distribution companies in Kentucky, includingULH&P, to begin filing and revising their gas cost recovery rate every month until further notice. We believe that the commissions will continue to allow recovery of prudently incurred gas costs.

INFLATION

We believe that the recent inflation rates do not materially impact our financial condition. However, under existing regulatory practice for all ofPSI, andULH&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 CHANGES

During 1998, the Financial Accounting Standards Board (FASB) issued Statement 133. This standard is effective for fiscal years beginning after June 15, 2000, and requires companies to record derivative instruments as assets or liabilities, measured at fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivatives that qualify as hedges can offset related fair value changes on the hedged item in the income statement for fair value hedges or be recorded in other comprehensive income for cash flow hedges.

We will reflect the adoption of this standard in financial statements issued beginning in the first quarter of 2001. Since many of the existing relevant contracts and financial instruments are currently required to use mark-to-market accounting, we anticipate the effects of implementation to be immaterial. These effects do not reflect the potential effects of applying mark-to-market accounting to selected call options and forwards we use to hedge peak period exposure to electricity demand. We have not historically marked these instruments to market because they are intended as hedges of peak period exposure and are not considered trading instruments. Our intent is to classify these types of instruments as normal purchases under Statement 133. However, the FASB-sponsored Derivatives Implementation Group has yet to issue its final guidance on these types of instruments. There are currently viewpoints that range from allowing them as normal purchases to not allowing hedge accounting under Statement 133. Given these issues, there is the possibility that these instruments will require mark-to-market accounting. This could create additional volatility in future earnings. At December 31, 2000, the fair value of these instruments was not material.

SHAREHOLDER RIGHTS PLAN

On July 19, 2000,Cinergy Corp.'s board of directors approved a Shareholder Rights Plan, (the Plan) which subsequently received SEC authorization under the PUHCA on October 6, 2000.

Under the Plan, each shareholder of record on October 30, 2000, received, as a dividend, a right to purchase fromCinergy Corp. one share of common stock at a price of $100. Initially, the rights will not be represented by separate certificates and will not trade separately fromCinergy Corp. shares of common stock. The rights would separate from the common stock ten days after either of the following occurred:

•: the public announcement of an acquisition of ten percent or more of the company's common stock, or
•: the commencement of a tender offer or exchange offer by which a person or group would acquire ten percent or more of the common stock ofCinergy Corp.

The rights become exercisable if one of these events occurs and the rights are no longer redeemable by the board of directors. If the rights become exercisable after someone has acquired ten percent or more of the company's common stock, holders of the rights will have the right to purchase the common stock ofCinergy Corp. at a 50% discount. However, any rights held by the acquirer would not be exercisable.

In addition, if the rights become exercisable andCinergy Corp. engages in a merger or consolidation in which it is not the surviving corporation or in which all or part of its common stock is changed or exchanged, or if 50% or more of the company's assets are sold, each holder of a right would have the right to acquire common stock of the acquirer at a 50% discount.

The board of directors may directCinergy Corp. to redeem the rights at $.01 per right at any time before the tenth day following the acquisition of ten percent or more ofCinergy Corp.'s common stock. The rights will expire in October of 2010 unless earlier redeemed or extended by the company.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

Reference is made to the "Market Risk Sensitive Instruments and Positions" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations".

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES


FINANCIAL STATEMENTS
Report of Independent Public Accountants
Cinergy Corp. and Subsidiaries
	Consolidated Statements of Income for the three years ended December 31, 2000
	Consolidated Balance Sheets at December 31, 2000, and 1999
	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2000
	Consolidated Statements of Cash Flows for the three years ended December 31, 2000
The Cincinnati Gas & Electric Company and Subsidiaries
	Consolidated Statements of Income for the three years ended December 31, 2000
	Consolidated Balance Sheets at December 31, 2000, and 1999
	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2000
	Consolidated Statements of Cash Flows for the three years ended December 31, 2000
	Consolidated Statements of Capitalization at December 31, 2000, and 1999
PSI Energy, Inc. and Subsidiary
	Consolidated Statements of Income for the three years ended December 31, 2000
	Consolidated Balance Sheets at December 31, 2000, and 1999
	Consolidated Statements of Changes in Common Stock Equity for the three years ended December 31, 2000
	Consolidated Statements of Cash Flows for the three years ended December 31, 2000
	Consolidated Statements of Capitalization at December 31, 2000, and 1999
The Union Light, Heat and Power Company
	Statements of Income for the three years ended December 31, 2000
	Balance Sheets at December 31, 2000, and 1999
	Statements of Changes in Common Stock Equity for the three years ended December 31, 2000
	Statements of Cash Flows for the three years ended December 31, 2000
	Statements of Capitalization at December 31, 2000, and 1999
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
	Schedule II—Valuation and Qualifying Accounts
		Cinergy
		CG&E
		PSI
		ULH&P

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the financial statements of Cinergy Corp. (a Delaware Corporation), The Cincinnati Gas & Electric Company (an Ohio Corporation), PSI Energy, Inc. (an Indiana Corporation) and The Union Light, Heat and Power Company (a Kentucky Corporation), as of December 31, 2000 and 1999, and for each of the three years in the period ended December 31, 2000, as listed on the index. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index pursuant to Item 14, are presented for purposes of complying with the Securities and Exchange Commission's Rules of 1934 and are not part of the basic financial statements. The schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

Arthur Andersen LLP
Cincinnati, Ohio
January 23, 2001

CINERGY CORP.
AND SUBSIDIARY COMPANIES

CINERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

			2000		1999		1998
			(dollars in thousands, except per share amounts)
Operating Revenues
	Electric		$	5,384,082	$	4,312,899	$	4,763,289
	Gas			2,941,753		1,596,146		1,099,629
	Other			96,129		28,843		48,373

		Total Operating Revenues		8,421,964		5,937,888		5,911,291
Operating Expenses
	Fuel and purchased and exchanged power			3,154,213		2,260,297		2,853,866
	Gas purchased			2,674,449		1,383,993		894,945
	Operation and maintenance			1,089,363		981,054		976,289
	Depreciation and amortization			373,965		353,820		326,492
	Taxes other than income taxes			268,346		265,501		274,635

		Total Operating Expenses		7,560,336		5,244,665		5,326,227
Operating Income				861,628		693,223		585,064
Equity in Earnings of Unconsolidated Subsidiaries				5,048		58,021		51,484
Gain on Sale of Investment in Unconsolidated Subsidiary (Note 10)				—		99,272		—
Miscellaneous—Net				13,391		2,031		(8,289	)
Interest				224,459		234,778		243,587

Income Before Taxes				655,608		617,769		384,672
Income Taxes(Note 11)				251,557		208,671		117,187
Preferred Dividend Requirements of Subsidiaries				4,585		5,457		6,517

Net Income			$	399,466	$	403,641	$	260,968

Average Common Shares Outstanding				158,938		158,863		158,238
Earnings Per Common Share(Note 16)
	Net Income		$	2.51	$	2.54	$	1.65
Earnings Per Common Share—Assuming Dilution(Note 16)
	Net Income		$	2.50	$	2.53	$	1.65
Dividends Declared Per Common Share			$	1.80	$	1.80	$	1.80

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

CINERGY CORP.

CONSOLIDATED BALANCE SHEETS

					December 31
ASSETS					2000		1999
					(dollars in thousands)
Current Assets
	Cash and cash equivalents				$	93,054	$	81,919
	Restricted deposits					4,195		628
	Notes receivable					35,945		481
	Accounts receivable less accumulated provision for doubtful accounts of $29,951 at December 31, 2000, and $26,811 at December��31, 1999 (Note 6)					1,623,402		706,068
	Materials, supplies, and fuel—at average cost					159,340		205,749
	Prepayments and other					129,666		77,701
	Energy risk management current assets (Note 1(j))					1,413,281		131,145

				Total Current Assets		3,458,883		1,203,691
Utility Plant—Original Cost
	In service
		Electric				9,698,128		9,414,744
		Gas				865,303		824,427
		Common				211,424		189,124

			Total			10,774,855		10,428,295
	Accumulated depreciation					4,555,614		4,259,877

			Total			6,219,241		6,168,418
	Construction work in progress					411,183		249,054

				Total Utility Plant		6,630,424		6,417,472
Other Assets
	Regulatory assets (Note 1(c))					976,614		1,055,012
	Investments in unconsolidated subsidiaries					538,322		358,853
	Energy risk management non-current assets (Note 1(j))					37,228		26,624
	Other					688,257		555,296

				Total Other Assets		2,240,421		1,995,785
Total Assets					$	12,329,728	$	9,616,948

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

CINERGY CORP.

CONSOLIDATED BALANCE SHEETS

			December 31
LIABILITIES AND SHAREHOLDERS' EQUITY			2000			1999
			(dollars in thousands)
Current Liabilities
	Accounts payable		$	1,496,494		$	734,937
	Accrued taxes			247,006			219,266
	Accrued interest			47,351			49,354
	Notes payable and other short-term obligations (Note 5)			1,128,657			550,194
	Long-term debt due within one year (Note 4)			40,545			31,000
	Energy risk management current liabilities (Note 1(j))			1,456,375			126,682
	Other			106,679			76,774

		Total Current Liabilities		4,523,107			1,788,207
Non-Current Liabilities
	Long-term debt (Notes 4 and 17)			2,876,367			2,989,242
	Deferred income taxes (Note 11)			1,185,968			1,174,818
	Unamortized investment tax credits			137,965			147,550
	Accrued pension and other postretirement benefit costs (Note 9)			411,361			355,917
	Energy risk management non-current liabilities (Note 1(j))			97,507			132,041
	Other			245,658			282,855

		Total Non-Current Liabilities		4,954,826			5,082,423
Total Liabilities				9,477,933			6,870,630
Cumulative Preferred Stock of Subsidiaries(Note 3)
	Not subject to mandatory redemption			62,834			92,597
Common Stock Equity(Note 2)
	Common Stock—$.01 par value; authorized shares—600,000,000; outstanding shares—158,967,661 at December 31, 2000, and 158,923,399 at December 31, 1999			1,590			1,589
	Paid-in capital			1,619,153			1,597,554
	Retained earnings			1,179,113			1,064,319
	Accumulated other comprehensive income (loss)			(10,895	)		(9,741	)

		Total Common Stock Equity		2,788,961			2,653,721
Commitments and Contingencies(Note 12)
Total Liabilities and Shareholders' Equity			$	12,329,728		$	9,616,948

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

CINERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

			Common Stock			Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
			(dollars in thousands)
1998
Beginning balance			$	1,577		$	1,573,064		$	967,420		$	(2,861	)	$	2,539,200
Comprehensive income:
	Net income			—			—			260,968			—			260,968
	Other comprehensive income (loss), net of tax effect of $(1,815)
		Foreign currency translation adjustment		—			—			—			2,160			2,160
		Minimum pension liability adjustment		—			—			—			(106	)		(106	)

	Total comprehensive income			—			—			—			—			263,022
Issuance of 919,874 shares of common stock—net				10			30,225			—			—			30,235
Treasury shares purchased				(3	)		(8,205	)		—			—			(8,208	)
Treasury shares reissued				3			12,455			—			—			12,458
Dividends on common stock				—			—			(284,703	)		—			(284,703	)
Other				—			(12,302	)		1,529			—			(10,773	)

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

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

Ending balance			$	1,589		$	1,597,554		$	1,064,319		$	(9,741	)	$	2,653,721
2000
Comprehensive income:
	Net income			—			—			399,466			—			399,466
	Other comprehensive income (loss), net of tax effect of $2,755
		Foreign currency translation adjustment		—			—			—			2,074			2,074
		Minimum pension liability adjustment		—			—			—			(1,099	)		(1,099	)
		Unrealized gain (loss) on grantor and rabbi trusts		—			—			—			(2,129	)		(2,129	)

	Total comprehensive income			—			—			—			—			398,312
Issuance of 44,262 shares of common stock—net				1			1,769			—			—			1,770
Treasury shares purchased				—			(3,969	)		—			—			(3,969	)
Treasury shares reissued				—			16,264			—			—			16,264
Dividends on common stock				—			—			(285,242	)		—			(285,242	)
Other				—			7,535			570			—			8,105

Ending balance			$	1,590		$	1,619,153		$	1,179,113		$	(10,895	)	$	2,788,961

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

CINERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

					2000			1999			1998
					(dollars in thousands)
Operating Activities
	Net income				$	399,466		$	403,641		$	260,968
	Items providing or (using) cash currently:
		Depreciation and amortization				373,965			353,820			326,492
		Wabash Valley Power Association, Inc. settlement				—			—			80,000
		Deferred income taxes and investment tax credits—net				47,404			96,067			(107,835	)
		Gain on sale of investment in unconsolidated subsidiary				—			(99,272	)		—
		Unrealized (gain) loss from energy risk management activities				2,419			(47,192	)		135,000
		Equity in earnings of unconsolidated subsidiaries				(5,048	)		(44,904	)		(45,374	)
		Allowance for equity funds used during construction				(5,813	)		(3,633	)		(1,668	)
		Regulatory assets — net				(6,805	)		(203,224	)		46,856
		Changes in current assets and current liabilities:
			Restricted deposits			(3,567	)		2,959			(1,268	)
			Accounts and notes receivable, net of reserves on receivables sold			(963,309	)		(118,561	)		(45,811	)
			Materials, supplies, and fuel			46,409			(3,002	)		(33,484	)
			Accounts payable			761,557			61,590			44,535
			Accrued taxes and interest			25,737			(11,406	)		46,371
		Other items—net				(51,811	)		4,543			(7,876	)

				Net cash provided by operating activities		620,604			391,426			696,906
Financing Activities
	Change in short-term debt					578,463			(353,506	)		(245,413	)
	Issuance of long-term debt					126,420			829,948			785,554
	Redemption of long-term debt					(234,247	)		(553,191	)		(384,520	)
	Retirement of preferred stock of subsidiaries					(29,393	)		(34	)		(85,299	)
	Issuance of common stock					1,770			6,722			3,724
	Dividends on common stock					(285,242	)		(285,925	)		(283,884	)

				Net cash provided by (used in) financing activities		157,771			(355,986	)		(209,838	)
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)					(519,574	)		(386,293	)		(368,609	)
	Acquisition of businesses (net of cash acquired)					—			(24,500	)		(63,412	)
	Investments in unconsolidated subsidiaries					(171,298	)		(284,343	)		(35,305	)
	Miscellaneous investments					(76,368	)		(48,808	)		27,102
	Sale of investment in unconsolidated subsidiary					—			690,269			—

				Net cash used in investing activities		(767,240	)		(53,675	)		(440,224	)
Net increase (decrease) in cash and cash equivalents						11,135			(18,235	)		46,844
Cash and cash equivalents at beginning of period						81,919			100,154			53,310

Cash and cash equivalents at end of period					$	93,054		$	81,919		$	100,154

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)			$	223,666		$	232,019		$	236,982
		Income taxes			$	216,556		$	130,179		$	179,677

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

THE CINCINNATI GAS &
ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

			2000			1999			1998
			(dollars in thousands)
Operating Revenues
	Electric		$	2,738,775		$	2,174,861		$	2,452,692
	Gas			490,972			376,013			403,431

		Total Operating Revenues		3,229,747			2,550,874			2,856,123
Operating Expenses
	Fuel and purchased and exchanged power			1,554,959			1,066,490			1,407,136
	Gas purchased			266,339			171,997			199,683
	Operation and maintenance			462,601			416,257			392,841
	Depreciation and amortization			209,922			204,468			191,109
	Taxes other than income taxes			208,385			212,193			217,691

		Total Operating Expenses		2,702,206			2,071,405			2,408,460
Operating Income				527,541			479,469			447,663
Miscellaneous—Net				(2,119	)		(2,480	)		(1,291	)
Interest				99,204			99,737			102,238

Income Before Taxes				426,218			377,252			344,134
Income Taxes (Note 11)				159,398			143,676			128,322

Net Income			$	266,820		$	233,576		$	215,812
Preferred Dividend Requirement				847			856			858

Net Income Applicable to Common Stock			$	265,973		$	232,720		$	214,954

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

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

					December 31
ASSETS					2000		1999
					(dollars in thousands)
Current Assets
	Cash and cash equivalents				$	20,637	$	9,554
	Restricted deposits					160		132
	Notes receivable from affiliated companies					91,732		—
	Accounts receivable less accumulated provision for doubtful accounts of $19,044 at December 31, 2000, and $16,740 at December 31, 1999 (Note 6)					494,501		279,591
	Accounts receivable from affiliated companies					26,743		12,718
	Materials, supplies, and fuel—at average cost					99,061		98,999
	Prepayments and other					39,320		35,527
	Energy risk management current assets (Note 1(j))					697,488		63,926

				Total Current Assets		1,469,642		500,447
Utility Plant—Original Cost
	In service
		Electric				4,999,038		4,875,633
		Gas				865,303		824,427
		Common				211,424		189,124

			Total			6,075,765		5,889,184
	Accumulated depreciation					2,444,867		2,279,587

			Total			3,630,898		3,609,597
	Construction work in progress					220,410		153,229

				Total Utility Plant		3,851,308		3,762,826
Other Assets
	Regulatory assets (Note 1(c))					502,328		536,224
	Energy risk management non-current assets (Note 1(j))					7,000		7,368
	Other					156,692		109,753

				Total Other Assets		666,020		653,345
Total Assets					$	5,986,970	$	4,916,618

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

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

			December 31
LIABILITIES AND SHAREHOLDER'S EQUITY			2000			1999
			(dollars in thousands)
Current Liabilities
	Accounts payable		$	543,006		$	253,115
	Accounts payable to affiliated companies			23,927			65,256
	Accrued taxes			152,750			136,118
	Accrued interest			17,645			17,375
	Notes payable and other short-term obligations (Note 5)			264,000			234,702
	Notes payable to affiliated companies			163,478			60,360
	Long-term debt due within one year (Note 4)			1,200			—
	Energy risk management current liabilities (Note 1(j))			717,902			60,478
	Other			37,603			25,468

		Total Current Liabilities		1,921,511			852,872
Non-Current Liabilities
	Long-term debt (Note 4)			1,205,061			1,205,916
	Deferred income taxes (Note 11)			735,799			720,168
	Unamortized investment tax credits			98,624			104,655
	Accrued pension and other postretirement benefit costs (Note 9)			164,901			154,718
	Energy risk management non-current liabilities (Note 1(j))			26,337			57,644
	Other			118,421			140,794

		Total Non-Current Liabilities		2,349,143			2,383,895
Total Liabilities				4,270,654			3,236,767
Cumulative Preferred Stock (Note 3)
	Not subject to mandatory redemption			20,486			20,686
Common Stock Equity (Note 2)
	Common Stock—$8.50 par value; authorized shares—120,000,000; outstanding shares—89,663,086 at December 31, 2000, and December 31, 1999			762,136			762,136
	Paid-in capital			565,777			562,851
	Retained earnings			368,911			335,144
	Accumulated other comprehensive income (loss)			(994	)		(966	)

		Total Common Stock Equity		1,695,830			1,659,165
Commitments and Contingencies (Note 12)
Total Liabilities and Shareholder's Equity			$	5,986,970		$	4,916,618

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

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

			Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
			(dollars in thousands)
1998
Beginning balance			$	762,136	$	534,649	$	314,553		$	(750	)	$	1,610,588
Comprehensive income:
	Net income			—		—		215,812			—			215,812
	Other comprehensive income (loss), net of tax effect of $201
		Minimum pension liability adjustment		—		—		—			(374	)		(374	)

	Total comprehensive income			—		—		—			—			215,438
Dividends on preferred stock				—		—		(859	)		—			(859	)
Dividends on common stock				—		—		(178,000	)		—			(178,000	)
Contribution from parent company for reallocation of taxes				—		19,253		—			—			19,253
Other				—		24		(1	)		—			23

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

	Total comprehensive income			—		—		—			—			233,734

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

Ending balance			$	762,136	$	562,851	$	335,144		$	(966	)	$	1,659,165
2000
Comprehensive income:
	Net income			—		—		266,820			—			266,820
	Other comprehensive income (loss), net of tax effect of $15
		Minimum pension liability adjustment		—		—		—			(28	)		(28	)

	Total comprehensive income			—		—		—			—			266,792
Dividends on preferred stock				—		—		(847	)		—			(847	)
Dividends on common stock				—		—		(232,334	)		—			(232,334	)
Contribution from parent company for reallocation of taxes				—		2,894		—			—			2,894
Other				—		32		128			—			160

Ending balance			$	762,136	$	565,777	$	368,911		$	(994	)	$	1,695,830

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

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

					2000			1999			1998
					(dollars in thousands)
Operating Activities
	Net income				$	266,820		$	233,576		$	215,812
	Items providing or (using) cash currently:
		Depreciation and amortization				209,922			204,468			191,109
		Deferred income taxes and investment tax credits—net				36,238			2,366			(27,045	)
		Unrealized (gain) loss from energy risk management activities				(7,077	)		(27,245	)		73,000
		Allowance for equity funds used during construction				(4,459	)		(2,565	)		(1,647	)
		Regulatory assets—net				(17,623	)		14,325			4,606
		Changes in current assets and current liabilities:
			Restricted deposits			(28	)		1,040			—
			Accounts and notes receivable, net of reserves on receivables sold			(326,826	)		17,676			(55,788	)
			Materials, supplies, and fuel			(62	)		16,295			(7,327	)
			Accounts payable			248,562			22,462			35,550
			Accrued taxes and interest			16,902			(18,533	)		(2,533	)
		Other items—net				(50,226	)		19,501			35,423

				Net cash provided by operating activities		372,143			483,366			461,160
Financing Activities
	Change in short-term debt					132,416			88,759			(94,950	)
	Issuance of long-term debt					—			19,818			243,186
	Redemption of long-term debt					—			(164,264	)		(220,409	)
	Retirement of preferred stock					(168	)		(26	)		(52	)
	Dividends on preferred stock					(847	)		(856	)		(859	)
	Dividends on common stock					(232,334	)		(250,100	)		(178,000	)

				Net cash used in financing activities		(100,933	)		(306,669	)		(251,084	)
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)					(260,127	)		(194,132	)		(185,436	)

				Net cash used in investing activities		(260,127	)		(194,132	)		(185,436	)

Net increase (decrease) in cash and cash equivalents						11,083			(17,435	)		24,640
Cash and cash equivalents at beginning of period						9,554			26,989			2,349

Cash and cash equivalents at end of period					$	20,637		$	9,554		$	26,989

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)			$	99,009		$	101,264		$	107,419
		Income taxes			$	121,158		$	159,241		$	125,704

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

THE CINCINNATI GAS & ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31
					2000			1999
					(dollars in thousands)
Long-term Debt(excludes current portion)
	CG&E
		First Mortgage Bonds:
			7¹/4 % Series due September 1, 2002		$	100,000		$	100,000
			6.45% Series due February 15, 2004			110,000			110,000
			7.20% Series due October 1, 2023			265,500			265,500
			5.45% Series due January 1, 2024 (Pollution Control)			46,700			46,700
			5¹/2 % Series due January 1, 2024 (Pollution Control)			48,000			48,000

				Total first mortgage bonds		570,200			570,200
		Pollution Control Notes:
			6.50% due November 15, 2022			12,721			12,721
		Other Long-term Debt:
			Liquid Asset Notes with Coupon Exchange (LANCE) due October 1, 2007 (Executed interest rate swap set at 6.87% through maturity commencing at October 2, 2000)			100,000			100,000
			6.40% Debentures due April 1, 2008			100,000			100,000
			6.90% Debentures due June 1, 2025 (Redeemable at the option of the holders on June 1, 2005)			150,000			150,000
			8.28% Junior Subordinated Debentures due July 1, 2025			100,000			100,000
			6.35% Debentures due June 15, 2038 (Interest rate resets June 15, 2003)			100,000			100,000

				Total other long-term debt		550,000			550,000
		Unamortized Premium and Discount—Net				(2,449	)		(2,762	)

		Total long-term debt				1,130,472			1,130,159
	ULH&P
		Other Long-term Debt:
			6.11% Debentures due December 8, 2003			20,000			20,000
			6.50% Debentures due April 30, 2008			20,000			20,000
			7.65% Debentures due July 15, 2025			15,000			15,000
			7.875% Debentures due September 15, 2009			20,000			20,000

				Total other long-term debt		75,000			75,000
		Unamortized Premium and Discount—Net				(411	)		(443	)

		Total long-term debt				74,589			74,557
	Lawrenceburg Gas Company
		First Mortgage Bonds:
			9³/4% Series due October 1, 2001			—			1,200

		Total CG&E Consolidated long-term debt			$	1,205,061		$	1,205,916

Cumulative Preferred Stock

Par/Stated Value			Authorized Shares		Shares Outstanding at December 31, 2000		Series		Mandatory Redemption
$	100		6,000,000		204,859		4% - 4³/4%		No		$	20,486		$	20,686

Common Stock Equity
	Common Stock—$8.50 par value; authorized shares—120,000,000; outstanding shares—89,663,086 at December 31, 2000, and December 31, 1999			$	762,136		$	762,136
	Paid-in capital				565,777			562,851
	Retained earnings				368,911			335,144
	Accumulated other comprehensive income (loss)				(994	)		(966	)

		Total common stock equity			1,695,830			1,659,165
			Total Capitalization	$	2,921,377		$	2,885,767

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

PSI ENERGY, INC.
AND SUBSIDIARY COMPANY

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

			2000		1999		1998
			(dollars in thousands)
Operating Revenues
	Electric		$	2,684,197	$	2,135,706	$	2,403,038
Operating Expenses
	Fuel and purchased and exchanged power			1,724,656		1,213,653		1,547,511
	Operation and maintenance			462,577		460,707		509,138
	Depreciation and amortization			142,584		136,402		130,604
	Taxes other than income taxes			56,908		52,920		54,541

		Total Operating Expenses		2,386,725		1,863,682		2,241,794
Operating Income				297,472		272,024		161,244
Miscellaneous—Net				4,723		655		3,300
Interest				78,250		86,265		89,359

Income Before Taxes				223,945		186,414		75,185
Income Taxes(Note 11)				88,547		69,215		23,147

Net Income			$	135,398	$	117,199	$	52,038
Preferred Dividend Requirement				3,738		4,601		5,659

Net Income Applicable to Common Stock			$	131,660	$	112,598	$	46,379

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

PSI ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

				December 31
ASSETS				2000		1999
				(dollars in thousands)
Current Assets
	Cash and cash equivalents			$	1,311	$	8,842
	Restricted deposits				341		—
	Notes receivable				3		481
	Notes receivable from affiliated companies				12,798		60,360
	Accounts receivable less accumulated provision for doubtful accounts of $9,317 at December 31, 2000, and $9,934 at December 31, 1999 (Note 6)				464,930		253,022
	Accounts receivable from affiliated companies				5,385		42,715
	Materials, supplies, and fuel—at average cost				53,838		103,490
	Prepayments and other				49,049		36,173
	Energy risk management current assets (Note 1(j))				697,488		63,927

			Total Current Assets		1,285,143		569,010
Electric Utility Plant—Original Cost
	In service				4,699,090		4,539,111
	Accumulated depreciation				2,110,747		1,980,290

		Total			2,588,343		2,558,821
	Construction work in progress				190,773		95,825

			Total Electric Utility Plant		2,779,116		2,654,646
Other Assets
	Regulatory assets (Note 1(c))				474,286		518,788
	Energy risk management non-current assets (Note 1(j))				7,000		7,368
	Other				84,230		85,024

			Total Other Assets		565,516		611,180
Total Assets				$	4,629,775	$	3,834,836

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

PSI ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

			December 31
LIABILITIES AND SHAREHOLDER'S EQUITY			2000			1999
			(dollars in thousands)
Current Liabilities
	Accounts payable		$	392,206		$	241,072
	Accounts payable to affiliated companies			32,448			6,762
	Accrued taxes			80,995			93,056
	Accrued interest			23,708			26,989
	Notes payable and other short-term obligations (Note 5)			188,391			232,597
	Notes payable to affiliated companies			146,381			6,707
	Long-term debt due within one year (Note 4)			38,325			31,000
	Energy risk management current liabilities (Note 1(j))			717,902			60,478
	Other			12,748			1,986

		Total Current Liabilities		1,633,104			700,647
Non-Current Liabilities
	Long-term debt (Notes 4 and 17)			1,074,255			1,211,552
	Deferred income taxes (Note 11)			458,593			460,748
	Unamortized investment tax credits			39,341			42,895
	Accrued pension and other postretirement benefit costs (Note 9)			150,135			129,103
	Energy risk management non-current liabilities (Note 1(j))			26,337			57,645
	Other			71,967			104,638

		Total Non-Current Liabilities		1,820,628			2,006,581
		Total Liabilities		3,453,732			2,707,228
Cumulative Preferred Stock(Note 3)
	Not subject to mandatory redemption			42,348			71,911
Common Stock Equity(Note 2)
	Common Stock—without par value; $.01 stated value; authorized shares—60,000,000; outstanding shares—53,913,701 at December 31, 2000, and December 31, 1999			539			539
	Paid-in capital			413,523			411,198
	Retained earnings			720,153			642,569
	Accumulated other comprehensive income (loss)			(520	)		1,391

		Total Common Stock Equity		1,133,695			1,055,697
Commitments and Contingencies(Note 12)
Total Liabilities and Shareholder's Equity			$	4,629,775		$	3,834,836

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

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

			Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
			(dollars in thousands)
1998
Beginning balance			$	539	$	400,893	$	637,814		$	(1,586	)	$	1,037,660
Comprehensive income:
	Net income			—		—		52,038			—			52,038
	Other comprehensive income (loss), net of tax effect of $(666)
		Minimum pension liability adjustment		—		—		—			1,091			1,091

	Total comprehensive income			—		—		—			—			53,129
Dividends on preferred stock				—		—		(6,187	)		—			(6,187	)
Dividends on common stock				—		—		(106,800	)		—			(106,800	)
Non-cash dividend on common stock				—		—		(11,999	)		—			(11,999	)
Contribution from parent company for reallocation of taxes				—		9,823		—			—			9,823
Other				—		23		(1	)		—			22

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

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

Ending balance			$	539	$	411,198	$	642,569		$	1,391		$	1,055,697
2000
Comprehensive income:
	Net income			—		—		135,398			—			135,398
	Other comprehensive income (loss), net of tax effect of $584
		Minimum pension liability adjustment		—		—		—			(47	)		(47	)
		Unrealized gain (loss) on grantor trust		—		—		—			(1,864	)		(1,864	)

	Total comprehensive income			—		—		—			—			133,487
Dividends on preferred stock				—		—		(3,738	)		—			(3,738	)
Dividends on common stock				—		—		(54,000	)		—			(54,000	)
Contribution from parent company for reallocation of taxes				—		1,989		—			—			1,989
Other				—		336		(76	)		—			260

Ending balance			$	539	$	413,523	$	720,153		$	(520	)	$	1,133,695

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

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				2000			1999			1998
				(dollars in thousands)
Operating Activities
	Net income			$	135,398		$	117,199		$	52,038
	Items providing or (using) cash currently:
		Depreciation and amortization			142,584			136,402			130,604
		Wabash Valley Power Association, Inc. settlement			—			—			80,000
		Deferred income taxes and investment tax credits—net			(6,582	)		102,878			(57,130	)
		Unrealized (gain) loss from energy risk management activities			(7,077	)		(27,245	)		62,000
		Allowance for equity funds used during construction			(1,354	)		(1,068	)		(21	)
		Regulatory assets—net			10,818			(217,549	)		42,250
		Changes in current assets and current liabilities:
			Restricted deposits		(341	)		2,414			(1,268	)
			Accounts and notes receivable, net of reserves on receivables sold		(130,891	)		(118,183	)		(16,850	)
			Materials, supplies, and fuel		49,652			(23,045	)		(25,256	)
			Accounts payable		176,820			(270	)		(7,086	)
			Accrued taxes and interest		(15,342	)		32,809			(3,437	)
		Other items—net			23,695			42,491			1,044

			Net cash provided by operating activities		377,380			46,833			256,888
Financing Activities
	Change in short-term debt				95,468			(36,804	)		69,073
	Issuance of long-term debt				53,075			589,225			200,228
	Redemption of long-term debt				(187,097	)		(379,484	)		(164,111	)
	Retirement of preferred stock				(29,225	)		(8	)		(85,247	)
	Dividends on preferred stock				(3,738	)		(4,601	)		(6,187	)
	Dividends on common stock				(54,000	)		(35,900	)		(106,800	)

		Net cash provided by (used in) financing activities			(125,517	)		132,428			(93,044	)
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)				(259,394	)		(189,207	)		(163,225	)

		Net cash used in investing activities			(259,394	)		(189,207	)		(163,225	)
Net increase (decrease) in cash and cash equivalents					(7,531	)		(9,946	)		619
Cash and cash equivalents at beginning of period					8,842			18,788			18,169

Cash and cash equivalents at end of period				$	1,311		$	8,842		$	18,788

Supplemental Disclosure of Cash Flow Information
	Cash paid (received) during the year for:
		Interest (net of amount capitalized)		$	80,854		$	86,256		$	80,712
		Income taxes		$	112,210		$	(54,099	)	$	63,957

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

PSI ENERGY, INC.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

					December 31
					2000			1999
					(dollars in thousands)
Long-term Debt (excludes current portion)
	First Mortgage Bonds:
		Series TT, 7³/8%, due March 15, 2012 (Pollution Control)			$	—		$	10,000
		Series UU, 7¹/2%, due March 15, 2015 (Pollution Control)				—			14,250
		Series YY, 5.60%, due February 15, 2023 (Pollution Control)				—			29,945
		Series ZZ, 5³/4%, due February 15, 2028 (Pollution Control)				50,000			50,000
		Series AAA, 7¹/8%, due February 1, 2024				30,000			30,000
		Series BBB, 8.0%, due July 15, 2009				124,665			124,665
		Series CCC, 8.85%, due January 15, 2022				53,055			53,055
		Series DDD, 8.31%, due September 1, 2032				38,000			38,000

			Total first mortgage bonds			295,720			349,915
	Secured Medium-term Notes:
		Series A, 7.61% to 8.81%, due January 2, 2002 to June 1, 2022				57,300			75,800
		Series B, 5.93% to 8.24%, due September 17, 2003 to August 22, 2022				126,000			126,000

			(Series A and B, 7.105% weighted average interest rate and 9 year weighted average remaining life)
				Total secured medium-term notes		183,300			201,800
	Other Long-term Debt:
		Series 2000A, Pollution Control Revenue Refunding Bond, due May 1, 2035				44,025			—
		Series 2000B, Pollution Control Revenue Refunding Bond, due April 1, 2022				10,000			—
		Series 1994A Promissory Note, non-interest bearing, due January 3, 2001				—			19,825
		6.35% Debentures due November 15, 2006				50			100,000
		6.00% Debentures due December 14, 2016 (The interest rate resets on December 14, 2001)				50,000			50,000
		6.50% Synthetic Putable Yield Securities due August 1, 2026				50,000			50,000
		7.25% Junior Maturing Principal Securities due March 15, 2028				2,658			2,658
		6.00% Rural Utilities Service (RUS) Obligation payable in annual installments (Note 17)				83,927			84,798
		6.52% Senior Notes due March 15, 2009				97,342			97,342
		7.85% Debentures due October 15, 2007				265,000			265,000

			Total other long-term debt			603,002			669,623
	Unamortized Premium and Discount—Net					(7,767	)		(9,786	)

	Total long-term debt					1,074,255			1,211,552

Par/Stated Value		Authorized Shares	Shares Outstanding at December 31, 2000	Series	Mandatory Redemption
	Cumulative Preferred Stock
$	100	5,000,000	347,592	3¹/2%—6.875%	No	$	34,759	$	63,963
$	25	5,000,000	303,544	4.16%—4.32%	No		7,589		7,948

Total preferred stock			42,348			71,911
Common Stock Equity
	Common Stock—without par value; $0.01 stated value; authorized shares—60,000,000; outstanding shares—53,913,701 at December 31, 2000, and December 31, 1999	$	539		$	539
	Paid-in capital		413,523			411,198
	Retained earnings		720,153			642,569
	Accumulated other comprehensive income (loss)		(520	)		1,391

	Total common stock equity		1,133,695			1,055,697
	Total Capitalization	$	2,250,298		$	2,339,160

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

THE UNION LIGHT, HEAT
AND POWER COMPANY

THE UNION LIGHT, HEAT AND POWER COMPANY

STATEMENTS OF INCOME

			2000			1999			1998
			(dollars in thousands)
Operating Revenues
	Electric		$	225,601		$	210,234		$	191,359
	Gas			91,950			70,728			65,454

		Total Operating Revenues		317,551			280,962			256,813
Operating Expenses
	Electricity purchased from parent company for resale			159,915			158,556			142,567
	Gas purchased			51,591			34,690			32,804
	Operation and maintenance			40,699			38,611			37,131
	Depreciation and amortization			15,685			14,830			13,148
	Taxes other than income taxes			3,938			4,136			3,993

		Total Operating Expenses		271,828			250,823			229,643
Operating Income				45,723			30,139			27,170
Miscellaneous—Net				(982	)		(1,567	)		(1,242	)
Interest				6,308			6,114			4,604

Income Before Taxes				38,433			22,458			21,324
Income Taxes(Note 11)				13,801			10,184			7,774

Net Income			$	24,632		$	12,274		$	13,550

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

THE UNION LIGHT, HEAT AND POWER COMPANY

BALANCE SHEETS

					December 31
ASSETS					2000		1999
					(dollars in thousands)
Current Assets
	Cash and cash equivalents				$	6,460	$	3,641
	Accounts receivable less accumulated provision for doubtful accounts of $1,492 at December 31, 2000, and $1,513 at December 31, 1999 (Note 6)					28,518		17,786
	Accounts receivable from affiliated companies					2,279		775
	Materials, supplies, and fuel—at average cost					6,300		7,654
	Prepayments and other					274		219

				Total Current Assets		43,831		30,075
Utility Plant—Original Cost
	In service
		Electric				234,482		222,035
		Gas				184,878		173,011
		Common				44,603		42,351

			Total			463,963		437,397
	Accumulated depreciation					169,403		154,607

			Total			294,560		282,790
	Construction work in progress					15,069		13,761

				Total Utility Plant		309,629		296,551
Other Assets
	Regulatory assets (Note 1(c))					10,177		10,639
	Other					5,110		5,000

				Total Other Assets		15,287		15,639
Total Assets					$	368,747	$	342,265

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

THE UNION LIGHT, HEAT AND POWER COMPANY

BALANCE SHEETS

			December 31
LIABILITIES AND SHAREHOLDER'S EQUITY			2000			1999
			(dollars in thousands)
Current Liabilities
	Accounts payable		$	24,249		$	8,487
	Accounts payable to affiliated companies			20,192			20,122
	Accrued taxes			(5,760	)		739
	Accrued interest			1,215			1,298
	Notes payable to affiliated companies			29,403			37,752
	Other			11,669			4,062

		Total Current Liabilities		80,968			72,460
Non-Current Liabilities
	Long-term debt (Note 4)			74,589			74,557
	Deferred income taxes (Note 11)			35,822			23,000
	Unamortized investment tax credits			3,684			3,961
	Accrued pension and other postretirement benefit costs (Note 9)			13,041			12,333
	Amounts due to customers—income taxes			7,439			11,308
	Other			6,016			12,596

		Total Non-Current Liabilities		140,591			137,755
Total Liabilities				221,559			210,215
Common Stock Equity(Note 2)
	Common Stock—$15.00 par value; authorized shares—1,000,000; outstanding shares—585,333 at December 31, 2000, and December 31, 1999			8,780			8,780
	Paid-in capital			20,305			20,142
	Retained earnings			118,103			103,128

		Total Common Stock Equity		147,188			132,050
Commitments and Contingencies(Note 12)
Total Liabilities and Shareholder's Equity			$	368,747		$	342,265

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

THE UNION LIGHT, HEAT AND POWER COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

	Common Stock		Paid-in Capital			Retained Earnings			Total Common Stock Equity
	(dollars in thousands)
1998
Beginning balance	$	8,780	$	18,683		$	95,450		$	122,913
Net income		—		—			13,550			13,550
Dividends on common stock		—		—			(8,487	)		(8,487	)
Contribution from parent for reallocation of taxes		—		843			—			843
Other		—		(1	)		—			(1	)

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

Ending balance	$	8,780	$	20,142		$	103,128		$	132,050
2000
Net income		—		—			24,632			24,632
Dividends on common stock		—		—			(9,657	)		(9,657	)
Contribution from parent for reallocation of taxes		—		163			—			163

Ending balance	$	8,780	$	20,305		$	118,103		$	147,188

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

THE UNION LIGHT, HEAT AND POWER COMPANY

STATEMENTS OF CASH FLOWS

					2000			1999			1998
					(dollars in thousands)
Operating Activities
	Net income				$	24,632		$	12,274		$	13,550
	Items providing or (using) cash currently:
		Depreciation and amortization				15,685			14,830			13,148
		Deferred income taxes and investment tax credits—net				8,926			(738	)		(261	)
		Allowance for equity funds used during construction				(61	)		(36	)		(142	)
		Regulatory assets—net				259			138			3
		Changes in current assets and current liabilities:
			Accounts and notes receivable, net of reserves on receivables sold			(14,269	)		(5,099	)		(4,820	)
			Materials, supplies, and fuel			1,354			615			(2,175	)
			Accounts payable			15,832			7,720			(9,920	)
			Accrued taxes and interest			(6,582	)		(3,138	)		(2,443	)
		Other items—net				3,482			5,971			3,228

				Net cash provided by operating activities		49,258			32,537			10,168
Financing Activities
	Change in short-term debt					(8,349	)		5,935			8,330
	Issuance of long-term debt					—			19,818			40,066
	Redemption of long-term debt					—			(20,000	)		(10,118	)
	Dividends on common stock					(9,657	)		(9,659	)		(8,487	)

				Net cash provided by (used in) financing activities		(18,006	)		(3,906	)		29,791
Investing Activities
	Construction expenditures (less allowance for equity funds used during construction)					(28,433	)		(28,234	)		(37,261	)

				Net cash used in investing activities		(28,433	)		(28,234	)		(37,261	)
Net increase in cash and cash equivalents						2,819			397			2,698
Cash and cash equivalents at beginning of period						3,641			3,244			546

Cash and cash equivalents at end of period					$	6,460		$	3,641		$	3,244

Supplemental Disclosure of Cash Flow Information
	Cash paid during the year for:
		Interest (net of amount capitalized)			$	6,534		$	6,691		$	4,257
		Income taxes			$	11,760		$	12,794		$	11,305

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

THE UNION LIGHT, HEAT AND POWER COMPANY

STATEMENTS OF CAPITALIZATION

					December 31
					2000			1999
					(dollars in thousands)
Long-term Debt (excludes current portion)
	Other Long-term Debt:
		6.11% Debentures due December 8, 2003			$	20,000		$	20,000
		6.50% Debentures due April 30, 2008				20,000			20,000
		7.65% Debentures due July 15, 2025				15,000			15,000
		7.875% Senior Unsecured Debentures due September 15, 2009				20,000			20,000

			Total other long-term debt			75,000			75,000
	Unamortized Premium and Discount—Net					(411	)		(443	)

	Total long-term debt					74,589			74,557
Common Stock Equity
	Common Stock—$15.00 par value; authorized shares—1,000,000; outstanding shares—585,333 at December 31, 2000, and December 31, 1999				$	8,780		$	8,780
	Paid-in capital					20,305			20,142
	Retained earnings					118,103			103,128

			Total common stock equity			147,188			132,050
				Total Capitalization	$	221,777		$	206,607

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

NOTES TO FINANCIAL STATEMENTS

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

1. Summary of Significant Accounting Policies

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

•: Cinergy Services, Inc. (Services);
•: Cinergy Investments, Inc. (Investments);
•: Cinergy Global Resources, Inc. (Global Resources);
•: Cinergy Technologies, Inc. (Technologies); and
•: Cinergy Wholesale Energy, Inc. (CWE).

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

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

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

Services is a service company that provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated, energy-related businesses and investments. Global Resources holds our international businesses and investments and directs our renewable energy investing activities (for example, wind farms). Technologies primarily holds our portfolio of technology-related investments. In November 2000, CWE was formed to act as a holding company forCinergy's energy commodity businesses, including production, as the generation assets eventually become unbundled from utility subsidiaries. See Note 18 for a discussion on Ohio deregulation.

We conduct operations through our subsidiaries, and we manage through the following four business units:

•: Energy Commodities Business Unit (Commodities);
•: Energy Delivery Business Unit (Delivery);
•: Cinergy Investments Business Unit (Cinergy Investments); and
•: International Business Unit (International).

As the utility industry continues to evolve,Cinergy will continue to analyze its operating structure and make modifications as appropriate. In early 2001, we announced certain organizational changes which further aligned the business units consistent withCinergy's strategic vision. The revised structure reflects three business units, as follows:

•: Energy Merchant—will operate power plants, both domestically and abroad, and conduct all wholesale energy marketing, trading, origination and risk management services;
•: Regulated Businesses—will operate all gas and electric transmission and distribution services, both domestically and abroad, and will be responsible for all regulatory planning for the regulated utility businesses ofCG&E,PSI, andULH&P; and
•: Power Technology and Infrastructure Services—will originate and manage a portfolio of emerging energy businesses.

See Note 15 for financial information by business unit.

(b) Presentation We use two different methods to report investments in subsidiaries or other companies: the consolidation method and the equity method. Additionally, we use estimates and have reclassified certain amounts in the preparation of the financial statements.

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

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

•: our investment in the entity asInvestments in unconsolidated subsidiaries in our Consolidated Balance Sheets; and
•: our percentage share of the earnings from the entity asEquity in earnings of unconsolidated subsidiaries in our Consolidated Statements of Income.

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

•: the reported amounts of assets and liabilities in our Balance Sheets at the dates of the financial statements;
•: the disclosure of contingent assets and liabilities at the dates of the financial statements; and
•: the reported amounts of revenues and expenses in our Statements of Income during the reporting periods.

Reclassifications We have reclassified certain prior-year amounts in the financial statements ofCinergy,CG&E,PSI, andULH&P to conform to current presentation.

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

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

Comprehensive electric deregulation legislation was passed in Ohio on July 6, 1999. As required by the legislation,
CG&E filed its Proposed Transition Plan for approval by the Public Utilities Commission of Ohio (PUCO) on December 28,
1999. On August 31, 2000, the PUCO approved a stipulation agreement relating toCG&E's transition plan. This plan creates
a Regulatory Transition Charge (RTC), designed to recoverCG&E's generation-related regulatory assets and transition costs
over a ten year period. Accordingly, Statement 71 was discontinued for the generation portion ofCG&E's business and
Statement of Financial Accounting Standards No. 101,Regulated Enterprises—Accounting for Discontinuation of
Application of FASB Statement No. 71 (Statement 101) was applied. The effect of this change to the financial statements was
immaterial. Except with respect to the generation assets ofCG&E, as of December 31, 2000,PSI,CG&E, and
ULH&P continue to meet each of the criteria required for the use of Statement 71. However, as other states implement deregulation legislation, the application of Statement 71 will need to be reviewed. Based on our operating companies' current regulatory orders and the regulatory environment in which they currently operate, the future recovery of regulatory assets recognized in the accompanying Balance Sheets as of December 31, 2000, is probable. The effect of future discontinuance of Statement 71 on results of operations, cash flows, or statement of position cannot be determined until deregulation legislation plans have been approved by each state in which we do business. For a further discussion of Ohio Deregulation see Note 18.

Our regulatory assets and amounts authorized for recovery through regulatory orders at December 31, 2000, and 1999, are as follows:

		CG&E(1)		2000 PSI		Cinergy		CG&E(1)		1999 PSI		Cinergy
		(in millions)
Amounts due from customers—income taxes(2)		$	53	$	20	$	73	$	276	$	18	$	294
Gasification services agreement buyout costs(3)			—		251		251		—		250		250
Post-in-service carrying costs and deferred operating expenses			—		41		41		121		42		163
Coal contract buyout cost(4)			—		53		53		—		77		77
Deferred demand-side management (DSM)			—		—		—		38		11		49
Phase-in deferred return and depreciation			—		—		—		54		—		54
Deferred merger costs			7		60		67		15		65		80
Unamortized costs of reacquiring debt			11		31		42		31		30		61
Coal gasification services expenses			—		12		12		—		16		16
RTC recoverable assets(5)			432		—		432		—		—		—
Other			—		6		6		1		10		11

	Total regulatory assets	$	503	$	474	$	977	$	536	$	519	$	1,055
	Authorized for recovery(6)	$	494	$	444	$	938	$	467	$	489	$	956

(1): Includes $10 million at December 31, 2000, and $11 million at December 31, 1999, related toULH&P (for deferred merger costs, unamortized costs of reacquiring debt and other regulatory assets). Of these amounts, $3 million at December 31, 2000, and $4 million at December 31, 1999, have been authorized for recovery.
(2): The various regulatory commissions overseeing the regulated business operations of our operating companies regulate income tax provisions reflected in customer rates. In accordance with the provisions of Statement 71, we have recorded net regulatory assets forCG&E andPSI and a regulatory liability forULH&P.
(3): PSI reached an agreement with Dynegy, Inc. to purchase the remainder of its 25-year contract for coal gasification services. In accordance with an order from the Indiana Utility Regulatory Commission (IURC),PSI began recovering this asset over an 18-year period that commenced upon the termination of the gas services agreement in 2000.
(4): In August 1996,PSI entered into a coal supply agreement, which expired December 31, 2000. The agreement provided for a buyout charge, which is being recovered through the fuel adjustment clause through December 2002.
(5): In August 2000,CG&E's deregulation transition plan was approved. Effective January 1, 2001, an RTC went into effect and provides for recovery of all then existing generation-related regulatory assets and various transition costs over a ten year period. Because a separate charge provides for recovery, these assets were aggregated and are included as a single amount in the 2000 presentation. The classification of all transmission and distribution related regulatory assets has remained the same.
(6): At December 31, 2000, these amounts were being recovered through rates charged to customers over a period ranging from 1 to 23 years forCG&E, 1 to 32 years forPSI, and 3 to 21 years forULH&P.

(d) Statements of Cash Flows We defineCash equivalents as investments with maturities of three months or less when acquired. See Note 17 for information concerning non-cash financing transactions.

(e) Operating Revenues and Fuel Costs Our operating companies recordOperating revenues for electric and gas service, including unbilled revenues and the associated expenses, when they provide the service to the customers. The associated expenses include:

•: the fuel used to generate electricity;
•: electricity purchased from others;
•: natural gas purchased from others; and
•: the transportation costs associated with the purchase of fuel, electricity, and natural gas.

These expenses are shown in our Statements of Income asFuel and purchased and exchanged power andGas purchased. Any portion of these costs that are recoverable or refundable to customers in future periods is deferred in eitherAccounts receivable orAccounts payable in our Balance Sheets.

Indiana law limits the amount of fuel costs thatPSI can recover to an amount that will not result in earning a return in excess of that allowed by the Indiana Utility Regulatory Commission (IURC).

(f) Utility Plant Utility plant includes the utility business property and equipment that is in use, being held for future use, or under construction. We report our utility plant at its original cost, which includes:

•: materials;
•: salaries;
•: payroll taxes;
•: fringe benefits;
•: an allowance for funds used during construction (described below in (h)); and
•: other miscellaneous amounts.

(g) Depreciation We determine the provisions for depreciation expense using the straight-line method. The depreciation rates are based on periodic studies of the estimated useful lives (the number of years we expect to be able to use the properties) and the cost to remove the properties. The average depreciation rates for utility plant, excluding software, are presented in the table below.

		2000		1999		1998
CG&E and subsidiaries
	Electric	2.9	%	2.9	%	2.9	%
	Gas	2.9		2.9		2.9
	Common	3.3		2.7		2.6
ULH&P
	Electric	3.3		3.3		3.4
	Gas	3.1		3.1		3.1
	Common	5.1		5.2		5.0
PSI		3.0		3.0		3.0

(h) Allowance for Funds Used During Construction (AFUDC) Our operating companies finance construction projects with borrowed funds and equity funds. Regulatory authorities allow us to record the costs of these funds as part of the cost of construction projects. AFUDC is calculated using a

methodology authorized by the regulatory authorities. AFUDC rates are compounded semi-annually and are as follows:

	2000		1999		1998
Cinergy average	8.0	%	7.3	%	6.6	%
CG&E and subsidiaries average	8.4		8.0		7.1
ULH&P average	6.6		5.3		6.1
PSI average	7.4		6.5		5.6

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

	2000		1999		1998
	(in millions)
Cinergy	$	8.2	$	5.6	$	7.5
CG&E and subsidiaries		5.0		3.4		5.5
ULH&P		0.4		0.2		0.6
PSI		3.2		2.2		2.0

With the deregulation ofCG&E's generation assets, the AFUDC method will no longer be used to capitalize the cost of funds used during generation-related construction atCG&E. Instead, accounting principles require the application of Statement of Financial Accounting Standards No. 34,Capitalization of Interest Cost (Statement 34). The primary differences in methodologies are that Statement 34 does not include a component for equity funds and does not emphasize short-term borrowings over long-term borrowings.

(i) Federal and State Income Taxes Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes, requires an asset and liability approach for financial accounting and reporting of income taxes. The tax effects of differences between the financial reporting and tax basis of accounting are reported asDeferred income tax assets orliabilities in our Balance Sheets and are based on currently enacted income tax rates.

Investment tax credits, which have been used to reduce our federal income taxes payable, have been deferred for financial reporting purposes. These deferred investment tax credits are being amortized over the useful lives of the property to which they are related. For a further discussion of income taxes see Note 11.

(j) Energy Marketing and Trading We market and trade electricity, natural gas, and other energy-related products. We designate transactions as physical or trading at the time they are originated. Physical refers to our intent and projected ability to fulfill substantially all obligations from company-owned assets. We sell generation to third parties when it is not required to meet native load requirements (end-use customers within our operating companies' franchise service territory). We account for physical transactions on a settlement basis and trading transactions using the mark-to-market method of accounting. Under the mark-to-market method of accounting, trading transactions are shown at fair value in our Consolidated Balance Sheets asEnergy risk management assets—andEnergy risk management liabilities—current and long-term. We reflect changes in fair value resulting in unrealized gains and losses inFuel and purchased and exchanged power andGas purchased. We record the revenues and costs for all transactions in our Consolidated Statements of Income when the contracts are settled. We recognize revenues inOperating revenues; costs are recorded inFuel and purchased and exchanged power andGas purchased.

Although we intend to settle physical contracts with company-owned generation, there are times when we have to settle these contracts with power purchased on the open trading markets. The cost of these purchases could be in excess of the associated revenues. We recognize the gains or losses on

these transactions as the power is delivered. Open market purchases may occur for the following reasons:

•: generating station outages;
•: least-cost alternative;
•: native load requirements; and
•: extreme weather.

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

•: closing exchange prices (that is, closing prices for standardized electricity products traded on an organized exchange such as the New York Mercantile Exchange);
•: broker dealer and over-the-counter price quotations; and
•: model pricing (which considers time value and historical volatility factors of electricity pricing underlying any options and contractual commitments).

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

Commodities, through Cinergy Marketing & Trading, LLC, and International, through Cinergy Global Trading Limited, market and trade natural gas and other energy-related products.

(k) Financial Derivatives We use derivative financial instruments to manage:

•: funding costs;
•: exposures to fluctuations in interest rates; and
•: exposures to foreign currency exchange rates.

To qualify for hedge accounting, these financial instruments must be designated as a hedge (for example, an offset of foreign exchange or interest rate risks) at the inception of the contract and must be effective at reducing the risk associated with the hedged item. Accordingly, changes in the fair values or cash flows of instruments designated as hedges must be highly correlated with changes in the fair values or cash flows of the related hedged items.

From time to time, we may utilize foreign exchange forward contracts (for example, a contract obligating one party to buy, and the other to sell, a specified quantity of a foreign currency for a fixed price at a future date) and currency swaps (for example, a contract whereby two parties exchange principal and interest cash flows denominated in different currencies) to hedge foreign currency denominated purchase and sale commitments and certain of our net investments in foreign operations against currency exchange rate fluctuations. At December 31, 2000, no such instruments were held.

We also use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for floating-interest rate cash flows). Through December 31, 2000, we utilized the accrual method to account for these interest rate swaps. Accordingly, gains and losses were calculated based on the difference between the fixed-rate and the floating-rate interest amounts, using agreed upon notional amounts. These gains and losses are recognized in our Consolidated Statements of Income as a component ofInterest over the life of the agreement. Effective with our adoption of Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (Statement 133) in the first quarter of 2001, we will begin accounting for interest rate swaps using mark-to-market accounting and will assess the effectiveness of any swaps used in hedging activities. See Note 1(l) below for further discussion of Statement 133.

(l) Accounting Changes During 1998, the Financial Accounting Standards Board (FASB) issued Statement 133. This standard is effective for fiscal years beginning after June 15, 2000, and requires companies to record derivative instruments as assets or liabilities, measured at fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivatives that qualify as hedges can offset related fair value changes on the hedged item in the income statement for fair value hedges or be recorded in other comprehensive income for cash flow hedges.

(m) Translation of Foreign Currency We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally that is the local currency of the country in which the subsidiary is located) is not the United States (U.S.) dollar, using the appropriate exchange rate as of the end of the year. We translate income and expense items using the average exchange rate prevailing during the month the respective transaction occurs. We record translation gains and losses inAccumulated other comprehensive income (loss), which is a component of common stock equity.

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

•: sales ratio;
•: electric peak load ratio;
•: number of employees ratio;
•: number of customers ratio;
•: construction expenditures ratio; and
•: other statistical information ratios.

These costs were as follows for the years ended December 31:

	2000		1999		1998
	(in millions)
CG&E and its subsidiaries	$	250	$	208	$	207
PSI		187		168		183
ULH&P		25		23		24

At December 31, 2000, and 1999, the Balance Sheets of our operating companies included the following amounts payable to Services:

	2000		1999
	(in millions)
CG&E and its subsidiaries	$	23	$	23
PSI		15		7
ULH&P		2		2

2. Common Stock

(a) Changes In Common Stock Outstanding The following table reflects selected information related to our shares of common stock reserved for stock-based plans.

	Shares Reserved at Dec. 31, 2000	Shares Issued
	Shares Reserved at Dec. 31, 2000	2000	1999	1998
Cinergy Corp. 1996 Long-term Incentive Compensation Plan (LTIP)	6,956,386	—	—	—
Cinergy Corp. Stock Option Plan	4,035,787	77,042	255,828	192,591
Cinergy Corp. Employee Stock Purchase and Savings Plan	1,930,904	208	266	1,006
Cinergy Corp. UK Sharesave Scheme	75,000	—	—	—
Cinergy Corp. Retirement Plan for Directors	175,000	—	—	—
Cinergy Corp. Directors' Equity Compensation Plan	75,000	—	—	—
Cinergy Corp. Directors' Deferred Compensation Plan	200,000	—	—	—
Cinergy Corp. 401(k) Plans	6,469,373	—	—	—
Cinergy Corp. Dividend Reinvestment and Stock Purchase Plan	1,798,486	—	—	—
Cinergy Corp. Performance Shares Plan	736,751	—	34,550	—

We retired 32,988 shares of common stock in 2000; 31,777 shares in 1999; and 44,981 shares in 1998, mainly representing shares tendered as payment for the exercise of previously granted stock options.

In 1998,Cinergy Corp. issued 771,258 shares of new common stock to acquire Cinergy Marketing and Trading, LLC.

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

(b) Dividend Restrictions Cinergy Corp.'s ability to pay dividends to holders of its common stock is principally dependent on the ability ofCG&E andPSI to payCinergy Corp. common dividends.CG&E andPSI cannot purchase or otherwise acquire for value or pay dividends on their common stock if preferred stock dividends are in arrears. The amount of common stock dividends that each company can pay is also limited by certain capitalization and earnings requirements underCG&E's and

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

•: LTIP;
•: Stock Option Plan;
•: Employee Stock Purchase and Savings Plan;
•: UK Sharesave Scheme;
•: Retirement Plan for Directors;
•: Directors' Equity Compensation Plan; and
•: Directors' Deferred Compensation Plan.

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

We account for our stock-based compensation plans under Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees. In 2000, 1999, and 1998, we recognized compensation cost related to stock-based compensation plans, before income taxes, of $12.8 million, $(7) million and $1 million, respectively, in the Consolidated Statements of Income. The $7 million reduction in 1999 was a result of our revised estimates for the performance-based shares accrued under the LTIP plan for Performance Cycle (Cycle) I. For further discussion see section (i) below.

Net income for 2000, 1999, and 1998, assuming compensation cost for these plans had been determined at fair value, consistent with the provisions of Statement of Financial Accounting Standards No. 123,Accounting for Stock-Based Compensation (Statement 123), would have been decreased by $4.4 million for 2000, $3.0 million for 1999 and $2.4 million for 1998. Earnings per share (EPS) would have been decreased by $.03 basic and diluted for 2000, $.02 basic and diluted for 1999, and $.02 basic and $.03 diluted for 1998.

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

(i) LTIP The LTIP was originally adopted in 1996. Under this plan, certain key employees may be granted stock options and the opportunity to earn performance-based shares. For each Cycle, stock options are granted to participants at fair market value on the date of grant. The number of shares of common stock issuable under the LTIP is limited to a total of 7,000,000 shares.

LTIP stock option activity for 2000, 1999, and 1998 is summarized as follows:

		Shares Subject to Option		Weighted Average Exercise Price
Balance at December 31, 1997		369,600		$	33.60
	Options granted	471,400			38.19
	Options forfeited	(68,000	)		36.06

Balance at December 31, 1998		773,000			36.19
	Options granted	2,713,600			25.45
	Options forfeited	(59,500	)		35.65

Balance at December 31, 1999		3,427,100			27.69
	Options granted	1,329,800			24.59
	Options forfeited	(357,200	)		26.47

Balance at December 31, 2000		4,399,700		$	26.85

Options Exercisable:
	At December 31, 1998	11,600		$	36.05
	At December 31, 1999	88,600		$	35.78
	At December 31, 2000	1,033,020		$	28.35

The weighted average fair value of options granted was $2.78 in 2000, $2.56 in 1999, and $4.68 in 1998. The fair values of options granted were estimated as of the date of grant using the Black-Scholes option-pricing model and the following assumptions:

	2000	1999	1998
Risk-free interest rate	6.5%	6.1%	5.6%
Expected dividend yield	7.2%	7.2%	4.8%
Expected lives	5.6 yrs.	5.6 yrs.	5.6 yrs.
Expected common stock variance	4.1%	3.8%	1.8%

Price ranges, along with certain other information, for the options outstanding under the LTIP at December 31, 2000, were as follows:

	Outstanding				Exercisable
Exercise Price Range	Number of Shares	Weighted Average Exercise Price		Weighted Average Contractual Life	Number of Shares	Weighted Average Exercise Price
$23.66 - $24.38	3,266,000	$	24.00	9.0 yrs.	598,920	$	23.87
$27.28 - $33.88	345,600	$	32.68	6.7 yrs.	277,900	$	33.50
$34.13 - $38.59	788,100	$	36.12	7.5 yrs.	156,200	$	36.34

Entitlement to performance based shares is based onCinergy's Total Shareholder Return (TSR) over designated Cycles as measured against a peer group. Target grants of performance based shares were made for the following Cycles:

Cycle	Grant Date	Performance Period	Target Grant of Shares
			(in thousands)
III	1/2000	2000-2001	241
IV	1/2000	2000-2002	362
V	1/2001	2001-2003	287

Potential awards for Cycle III are prorated for the length of the cycle. Participants may earn additional performance shares ifCinergy's TSR exceeds that of the peer group. The Cycle II award of 122,820 shares for calendar year 2000 was distributed in January 2001.

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

Stock Option Plan activity for 2000, 1999, and 1998 is summarized as follows:

		Shares Subject to Option		Weighted Average Exercise Price
Balance at December 31, 1997		2,954,475		$	23.79
	Options granted	480,000			36.88
	Options exercised	(430,961	)		21.62
	Options forfeited	(100,000	)		26.92

Balance at December 31, 1998		2,903,514			26.17
	Options granted	152,500			24.66
	Options exercised	(259,865	)		21.51
	Options forfeited	(36,000	)		25.89

Balance at December 31, 1999		2,760,149			26.53
	Options exercised	(123,978	)		23.50
	Options forfeited	(45,000	)		28.34

Balance at December 31, 2000		2,591,171		$	26.64

Options Exercisable:
	At December 31, 1998	1,535,514		$	23.61
	At December 31, 1999	1,898,149			24.67
	At December 31, 2000	2,162,171			25.17

The weighted average fair value of options granted was $2.40 in 1999 and $4.53 in 1998 (no options were granted in 2000). The fair values of options granted in 1999 and 1998 were estimated as of the date of grant using the Black-Scholes option-pricing model and the following assumptions:

	1999	1998
Risk-free interest rate	6.2%	5.6%
Expected dividend yield	7.3%	4.8%
Expected lives	6.5 yrs.	6.5 yrs.
Expected common stock variance	3.9%	2.0%

Price ranges, along with certain other information, for options outstanding under the Stock Option Plan at December 31, 2000, were as follows:

	Outstanding				Exercisable
Exercise Price Range	Number of Shares	Weighted Average Exercise Price		Weighted Average Contractual Life	Number of Shares	Weighted Average Exercise Price
$17.35 - $23.81	911,747	$	22.90	4.5 yrs.	831,747	$	22.81
$24.31 - $24.63	933,451	$	24.32	4.1 yrs.	933,451	$	24.32
$25.19 - $36.88	745,973	$	34.12	6.5 yrs.	396,973	$	32.12

(iii) Employee Stock Purchase and Savings Plan The Employee Stock Purchase and Savings Plan allows essentially all full-time, regular employees to purchase shares of common stock pursuant to a stock option feature. Under the Employee Stock Purchase and Savings Plan, after-tax funds are withheld from a participant's compensation during a 26-month offering period and are deposited in an interest-bearing account. At the end of the offering period, participants may apply amounts deposited in the account, plus interest, toward the purchase of shares of common stock. The purchase price is equal to 95% of the fair market value of a share of common stock on the first date of the offering period. Any funds not applied toward the purchase of shares are returned to the participant. A participant may elect to terminate participation in the plan at any time. Participation also will terminate if the participant's employment ceases. Upon termination of participation, all funds, including interest, are returned to the participant without penalty. The third (current) offering period began March 1, 1999, and ends April 30, 2001. The purchase price for all shares under this offering is $27.73. The second offering period ended February 28, 1999. At the end of the second offering of the plan, the market price was below the established share price; therefore, in accordance with the plan provisions, all participants in the plan at February 28, 1999, were distributed cash funds in March 1999. The total number of shares of common stock issuable under the Employee Stock Purchase and Savings Plan may not exceed 2,000,000.

Employee Stock Purchase and Savings Plan activity for 2000, 1999, and 1998 is summarized as follows:

		Shares Subject to Option		Weighted Average Exercise Price
Balance at December 31, 1997		326,367		$	31.83
	Options exercised	(3,342	)		31.83
	Options forfeited	(25,651	)		31.83

Balance at December 31, 1998		297,374			31.83
	Options granted	368,889			27.73
	Options exercised	(266	)		27.73
	Options forfeited	(306,692	)		27.73

Balance at December 31, 1999		359,305			27.73
	Options exercised	(2,718	)		27.73
	Options forfeited	(76,261	)		27.73

Balance at December 31, 2000		280,326		$	27.73

The weighted average fair value of options granted was $3.97 in 1999 (no options were granted in 1998 or 2000). The fair values of options granted were estimated as of the date of grant using the Black-Scholes option-pricing model and the following assumptions:

		1999
Risk-free interest rate		5.0%
Expected dividend yield		6.2%
Expected lives		2.0 yrs.
Expected common stock variance		5.2%

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

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

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

Services, and in part,Cinergy Corp., have guaranteed repayment to the bank of 100% of each participant's loan obligations and the associated interest, and each participant has agreed to indemnify the guarantor for any payments made by it under the guaranty on the participant's behalf. A participant's obligations to the bank are unsecured, and no restrictions are placed on the participant's ability to sell, pledge or otherwise encumber or dispose of his or her purchased shares.

3. Change in Preferred Stock of Subsidiaries

In 2000,PSI redeemed 289,250 shares of its $100 par value, 6.875% Series preferred stock for $29 million. In 1998,PSI redeemed approximately 3.4 million shares of its $25 par value, 7.44% Series preferred stock for $85 million. All other classes of preferred stock redeemed from 1998 to 2000 were immaterial forCG&E andPSI. Refer to the Consolidated Statements of Capitalization for detailed information forCG&E andPSI.

4. Long-Term Debt

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

				December 31
				2000			1999
				(in thousands)
Cinergy Corp.
	Other Long-term Debt
		6.53% Debentures due December 16, 2008		$	200,000		$	200,000
		6.125% Debentures due April 15, 2004			200,000			200,000

			Total Other Long-term Debt		400,000			400,000
	Unamortized Discount				(265	)		(333	)

			Total—Cinergy Corp.	$	399,735		$	399,667
Global Resources
	Other Long-term Debt
		6.20% Debentures due November 3, 2008		$	150,000		$	150,000
		Variable interest rate of London Inter-Bank Offered Rate (LIBOR) plus 1.75%, due July 2015			14,156			15,300
		Variable interest rate of LIBOR plus 2.5%, due July 2015			6,323			7,100
		Variable interest rates ranging between the 3 month Prague Inter-Bank Offered Rate plus 0.55% to the 3 month Euro Inter-Bank Offered Rate plus 4.12%, maturing April 30, 2002 to June 20, 2004			8,314			—
		7.4% interest rate, due May 30, 2003			18,783			—

			Total Other Long-term Debt		197,576			172,400
	Unamortized Discount				(260	)		(293	)

			Total—Global Resources	$	197,316		$	172,107
Operating Companies
	CG&E and its subsidiaries			$	1,205,061		$	1,205,916
	PSI				1,074,255			1,211,552

			Total—Operating Companies	$	2,279,316		$	2,417,468
Total—Cinergy				$	2,876,367		$	2,989,242

The following table reflects the long-term debt maturities for the next five years, excluding any redemptions due to the exercise of call or put provisions. Callable means the issuer has the right to buy

back a given security from the holder at a specified price before maturity. Putable means the holder has the right to sell a given security back to the issuer at a specified price before maturity.

	Cinergy and Subsidiaries(1)			CG&E and Subsidiaries(1)			PSI(1)
	(in millions)
2001	$	41	(2)	$	1		$	39
2002		145			100			24
2003		85			20	(3)		57
2004		313			110			1
2005		3			—			1

	$	587		$	231		$	122

(1): Excludes capital leases.
(2): Excludes $27 million ofLong-term debt due within one year for a subsidiary of Global Resources, which is classified asNotes payable and other short-term obligations.
(3): CG&E and subsidiaries includesULH&P's $20 million maturing in 2003.

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

5. Notes Payable and Other Short-term Obligations

Short-term obligations may include:

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

Short-term Notes Short-term borrowings mature within one year from the date of issuance. We primarily use unsecured revolving lines of credit for short-term borrowings. A portion of each company's committed lines is used to provide credit support for commercial paper (discussed below). When committed lines are reserved for commercial paper or backing letters of credit, they are not available for additional borrowings. The fees we paid to secure short-term notes were immaterial during the period from 1998 to 2000.

At December 31, 2000,Cinergy Corp. had $157 million remaining unused and available relating to its authorized $795 million revolving and uncommitted lines. Early in 2001,Cinergy Corp. successfully placed a new $400 million, 364-day revolving credit facility. This new facility will support an expansion of our commercial paper program and is not included in the lines of credit discussed above.

Commercial Paper As of December 31, 2000, the commercial paper (debt instruments exchanged between companies) program is limited to a maximum outstanding principal amount of $400 million forCinergy Corp. As of December 31, 2000,Cinergy Corp. had issued $216 million in commercial paper. Additionally,CG&E andPSI have the capacity to issue commercial paper, which must be supported by available committed lines of the respective company. The maximum outstanding principal amount forCG&E is $200 million and forPSI is $100 million. NeitherCG&E norPSI issued commercial paper in 2000 or 1999.

programs atCG&E andPSI. TheCinergy Corp. commercial paper program expansion is supported by the new $400 million, 364-day revolving credit facility as discussed above.

Variable Rate Pollution Control Notes CG&E andPSI have issued variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development to control pollution). Because the holders of these notes have the right to redeem their notes on any business day, they are reflected inNotes payable and other short-term obligations in the Consolidated Balance Sheets forCinergy, forCG&E, and forPSI.

The following tables summarize ourNotes payable and other short-term obligations, but excludeNotes payable to affiliated companies.

Cinergy

			December 31, 2000						December 31, 1999
			Established Lines		Outstanding		Weighted Average Rate		Established Lines		Outstanding		Weighted Average Rate
					(in millions)						(in millions)
Cinergy Corp.
	Committed lines
		Revolving lines	$	750	$	359	6.84	%	$	600	$	—	—	%
	Uncommitted line			45		12	7.25			45		—	—
	Commercial paper			400		216	7.06			—		—	—
	Operating companies
	Committed lines			180		180	7.18			195		120	6.68
	Uncommitted lines			125		5	7.00			300		81	6.44
	Pollution control notes			N/A		267	4.52			N/A		267	4.10
	Non-regulated subsidiaries
	Revolving lines			13		11	5.86			14		13	6.26
	Short-term debt			79		79	6.77			69		69	6.86

Cinergy Total					$	1,129	6.38	%			$	550	5.41	%

CG&E

	December 31, 2000						December 31, 1999
	Established Lines		Outstanding		Weighted Average Rate		Established Lines		Outstanding		Weighted Average Rate
			(in millions)						(in millions)
Committed lines	$	80	$	80	7.06	%	$	65	$	30	6.27	%
Uncommitted line		40		—	—			130		21	6.42
Pollution control notes		N/A		184	4.61			N/A		184	4.08

Total			$	264	5.35	%			$	235	4.57	%

PSI

	December 31, 2000						December 31, 1999
	Established Lines		Outstanding		Weighted Average Rate		Established Lines		Outstanding		Weighted Average Rate
			(in millions)						(in millions)
Committed lines	$	100	$	100	7.27	%	$	130	$	90	6.81	%
Uncommitted line		85		5	7.00			170		60	6.44
Pollution control notes		N/A		83	4.34			N/A		83	4.15

Total			$	188	5.97	%			$	233	5.77	%

Money Pool Cinergy Corp., Services, and our operating companies and their subsidiaries 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 others. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown asNotes receivable from affiliated companies orNotes payable to affiliated companies on the Consolidated Balance Sheets forCG&E andPSI, and on the Balance Sheets forULH&P.

6. Sale of Accounts Receivable

CG&E,PSI, andULH&P have an agreement to sell, on a revolving basis, undivided percentage interests in certain of their accounts receivable and the related collections up to an aggregate maximum of $350 million.CG&E retains servicing responsibilities for its role as a collection agent of the amounts due on the sold receivables. However, the purchaser assumes the risk of collection on the sold receivables without recourse toCG&E,PSI, orULH&P in the event of a loss. Proceeds from a portion of the sold receivables are held back as a reserve to reduce the purchaser's credit risk.CG&E,PSI, andULH&P do not retain any ownership interest in the sold receivables, but do retain undivided interests in their remaining balances of accounts receivable. The recorded amounts of the retained interests are measured at net realizable value.

TheAccounts receivable on the Consolidated Balance Sheets ofCinergy, CG&E andPSI and on the Balance Sheets of
ULH&P are net of the amounts sold at December 31, 2000, and 1999. The following table shows the receivables sold, the associated reserves held back, and the net amounts received as of December 31, 2000, and 1999, as well as the losses on the sales of accounts receivable for the years ended December 31, 2000, and 1999:

	Receivables Sold		Reserves		Net Amount		Loss on Sale(1)
			(in millions)
2000
Cinergy	$	316	$	59	$	257	$	17
CG&E and subsidiaries		192		36		156		11
PSI		124		23		101		6
ULH&P		32		6		26		1
1999
Cinergy	$	306	$	49	$	257	$	15
CG&E and subsidiaries		187		30		157		10
PSI		119		19		100		5
ULH&P		25		4		21		1

(1): Represents monthly fees payable to the purchaser.

7. Leases

(a) Operating Leases We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space. Total rental payments on operating leases for each of the past three years are detailed in the table below. This table also shows future minimum lease payments required for operating leases with remaining non-cancelable lease terms in excess of one year as of December 31, 2000:

	Actual Payments						Estimated Minimum Payments
	1998		1999		2000		2001		2002		2003		2004		2005		After 2005		Total
	(in millions)						(in millions)
Cinergy(1)	$	42	$	50	$	56	$	41	$	31	$	23	$	17	$	15	$	68	$	195
CG&E and subsidiaries		21		27		30		10		9		7		5		5		18		54
PSI		21		21		21		9		8		7		6		5		25		60
ULH&P(2)		3		4		4		—		—		—		—		—		—		—

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

(b) Capital Leases In 2000 and 1999,CG&E,PSI, andULH &P entered into capital lease arrangements to fund the purchase of gas and electric meters. The lease terms are for 120 months commencing December 2000 and December 1999, respectively, with early buyout options at 48, 72, and 105 months. Since the objective is to own the meters indefinitely, the companies plan to exercise the buyout option at month 105. The lease rate used to determine the monthly payments is 6.385% and 6.71% for 2000 and 1999, respectively. The meters are depreciated at the same rate as if they were owned by the companies.CG&E,PSI, andULH&P each recorded a capital lease obligation, included inNon-current liabilities—other.

Effective October 2000,CG&E entered into a capital lease agreement with a lease term of 120 months, to fund the purchase of equipment for the William H. Zimmer Station. The lease rate used to determine the monthly payments is a variable rate that is based upon the applicable LIBOR rate and was 8.275% at December 31, 2000. LIBOR is the rate at which the highest rated banks offer to lend to one another. Interest rates are frequently quoted as a spread to LIBOR. The equipment under the capital lease is depreciated at the same rate as if it was owned byCG&E.CG&E recorded a capital lease obligation, included inCurrent liabilities—other for $.9 million andNon-current liabilities—other for $8.4 million, which is the book value of the equipment at the beginning of the lease. The title to all equipment will transfer toCG&E at the end of the lease term. The capitalized lease obligation is amortized over the term of the lease.

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

	Total Minimum Lease Payments
	Cinergy			CG&E and subsidiaries			PSI			ULH&P
				(in millions)
Total minimum lease payments(1)	$	46		$	31		$	15		$	6
Less: amount representing interest		(12	)		(8	)		(4	)		(1	)

Present value of minimum lease payments	$	34		$	23		$	11		$	5

(1): Annual minimum lease payments are immaterial.

In 1996,CG&E entered into a sale-leaseback agreement for certain equipment at Woodsdale Generating Station. The lease is a capital lease with an initial lease term of five years, which expires on October 31, 2001. At the end of this term, the lease may be renewed at mutually agreeable terms orCG&E may purchase the equipment at the original sale amount. The monthly lease payment is interest only and is based on the applicable LIBOR rate. The capital lease obligation will not be reduced over the initial lease term. The equipment under the capital lease is depreciated at the same rate as if it was owned byCG&E. CG&E recorded a capital lease obligation, included inNon-current liabilities—other for $22 million, which is the book value of the equipment at the beginning of the lease.

8. Financial Instruments

(a) Financial Derivatives We have entered into financial derivative contracts for the purposes described below.

(i) Interest Rate Risk Management Our current policy in managing exposure to fluctuations in interest rates is to maintain approximately 25% of the total outstanding debt in floating interest rate debt instruments. To help maintain this level of exposure, we have previously and will consider in the future entering into interest rate swaps. Under these swaps, we have agreed with other parties to exchange, at specified intervals, the difference between fixed-rate and floating-rate interest amounts calculated on an agreed notional amount.PSI had an interest rate swap agreement that expired on November 15, 2000, which had a notional amount of $100 million.CG&E has an outstanding interest rate swap agreement that decreased the percentage of floating rate debt. Under the seven-year agreement, which has a notional amount of $100 million,CG&E pays a fixed rate and receives a floating rate. This swap will qualify 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 be effective as a hedge. Future changes in fair value of this swap will be recorded inAccumulated other comprehensive income (loss), beginning with our adoption of Statement 133 effective January 1, 2001. In the future, we will continually monitor market conditions to evaluate whether to increase, or decrease, our level of exposure to fluctuations in interest rates. See Note 1(l) on page 107 for further discussion of Statement 133.

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

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

	December 31, 2000				December 31, 1999
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(in millions)
Cinergy
First mortgage bonds and other long-term debt (includes amounts reflected as long-term debt due within one year)	$	2,917	$	2,950	$	3,020	$	2,820
CG&E and subsidiaries
First mortgage bonds and other long-term debt (includes amounts reflected as long-term debt due within one year)	$	1,206	$	1,203	$	1,206	$	1,065
PSI
First mortgage bonds and other long-term debt (includes amounts reflected as long-term debt due within one year)	$	1,113	$	1,136	$	1,243	$	1,215
ULH&P
Other long-term debt	$	75	$	76	$	75	$	71

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

Cash and cash equivalents, Restricted deposits, andNotes payable and other short-term obligations Due to the short period to maturity, the carrying amounts reflected on the Balance Sheets approximate fair values.

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

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

(i) Trade Receivables and Physical Power Portfolio Our concentration of credit risk with respect to Delivery's 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 Commodities' power marketing and trading operations are primarily with the traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 2000, we do not believe we had significant exposure to credit risk with our trade accounts receivable within Delivery or our physical portfolio within Commodities.

(ii) Power-Trading Contracts within the trading portfolio of the power marketing and trading operations are primarily with power marketers and other investor-owned utilities. As of December 31, 2000, approximately 60% of the activity within the total trading portfolio was with 10 counterparties. The majority of these contracts are for terms of one year or less. Electric power 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, especially when dealing with new market entrants. Credit discounts are included in the determination of fair value for all open positions in the power-trading portfolio.

During the last quarter of 2000, the Western U.S., primarily California, began experiencing unprecedented price levels for wholesale electricity. Because of the nature of deregulation in California, the utilities have been unable to pass these price increases on to customers. Consequently, California's two largest utilities have accumulated significant unpaid obligations and are having difficulty obtaining capital. While we maintain a balanced Western U.S. portfolio and have no unrealized gain positions directly with these utilities, a large portion of such positions are with less than five power marketers. If prices continue at elevated levels or should these utilities be unable to fund their unpaid obligations, credit failures by power marketers could result. Given these issues, the fair values of our positions in the Western U.S. have been adjusted to reflect a higher level of credit discount. We have also been actively pursuing other forms of credit enhancement including, but not limited to, parent company guarantees and letters of credit from counterparties. In determining fair value for all derivative instruments, we consider the credit quality of each counterparty, contractual netting arrangements for longs and shorts with the same counterparty, and any security obtained. A significant portion of ourEnergy risk management assets andEnergy risk management liabilities—current are with counterparties in the Western U.S. Nonperformance by any of the Western U.S. counterparties could have a material effect on the operating results ofCinergy,CG&E, andPSI.

(iii) Gas-Trading As of December 31, 2000, approximately 50% of the activity within the physical gas marketing and trading portfolio represented commitments with 20 counterparties. Credit risk losses related to gas and other physical commodity and trading operations have not been significant. At December 31, 2000, the credit risk within the gas and commodity trading portfolios was not believed to be significant because of the characteristics of counterparties and customers with which transactions are executed.

(iv) 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.

9. Pension and Other Postretirement Benefits

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

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

•: years of participation;
•: age at retirement; and
•: the applicable average Social Security wage base or benefit amount.

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

We provide certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments. NeitherCG&E norULH&P pre-fund their obligations for these postretirement benefits. In 1999,PSI began pre-funding its obligations through a grantor trust as authorized by the IURC.

In 2000,Cinergy offered early retirement plans to certain individuals under a Limited Early Retirement Program (LERP). In accordance with Statement of Financial Accounting Standards No. 88,Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88),Cinergy recognized a one-time expense of $12.8 million in 2000.

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

		Pension Benefits									Other Postretirement Benefits
		2000			1999			1998			2000			1999			1998
								(in millions)
Service cost		$	27.4		$	24.8		$	21.8		$	3.4		$	3.5		$	4.1
Interest cost			73.0			70.8			71.6			17.0			16.2			16.1
Expected return on plans' assets			(77.0	)		(72.0	)		(66.9	)		—			—			—
Amortization of transition (asset) obligation			(1.3	)		(1.3	)		(1.3	)		5.0			5.0			5.0
Amortization of prior service cost			4.5			4.5			4.4			—			—			—
Recognized actuarial (gain) loss			(2.4	)		0.6			—			—			0.8			0.4
LERP Statement 88 cost			11.9			—			—			—			—			—

Net periodic benefit cost		$	36.1		$	27.4		$	29.6		$	25.4		$	25.5		$	25.6
Actuarial assumptions:
	Discount rate		7.50	%		7.50	%		6.75	%		7.50	%		7.50	%		6.75	%
	Rate of future compensation increase		4.50			4.50			3.75			N/A			N/A			N/A
	Rate of return on plans' assets		9.00			9.00			9.00			N/A			N/A			N/A

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

The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ended December 31, 2000, and a statement of the funded status as of December 31 of both years.

	Pension Benefits						Other Postretirement Benefits
	2000			1999			2000			1999
				(in millions)
Change in benefit obligation
Benefit obligation at beginning of period	$	1,002.0		$	1,052.1		$	234.4		$	246.5
Service cost		27.4			24.8			3.4			3.5
Interest cost		73.0			70.8			17.0			16.2
Amendments(1)		13.1			1.1			—			—
Actuarial (gain) loss		12.0			(90.3	)		6.7			(18.4	)
Benefits paid		(63.0	)		(56.5	)		(14.4	)		(13.4	)

Benefit obligation at end of period		1,064.5			1,002.0			247.1			234.4
Change in plan assets
Fair value of plan assets at beginning of period		946.1			865.3			—			—
Actual return on plan assets		160.5			137.3			—			—
Employer contribution		—			—			14.4			13.4
Benefits paid		(63.0	)		(56.5	)		(14.4	)		(13.4	)

Fair value of plan assets at end of period		1,043.6			946.1			—			—
Funded status		(20.9	)		(55.9	)		(247.1	)		(234.4	)
Unrecognized prior service cost		36.6			39.9			—			—
Unrecognized net actuarial (gain) loss		(249.6	)		(180.6	)		26.6			20.1
Unrecognized net transition (asset) obligation		(4.5	)		(5.8	)		55.8			60.8

Accrued benefit cost at December 31	$	(238.4	)	$	(202.4	)	$	(164.7	)	$	(153.5	)

(1): The 2000 Amendments balance contains $11.9 million of LERP expenses in accordance with Statement 88 as previously discussed.

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

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(in millions)
Effect on total of service and interest cost components	$	3.1	$	(2.7	)
Effect on postretirement benefit obligation		33.8		(29.2	)

In addition, we sponsor non-qualified pension plans (plans that do not meet the criteria for tax benefits) that cover officers, certain other key employees, and non-employee directors. We began funding certain of these non-qualified plans through a rabbi trust in 1999.

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

	2000		1999
	(in millions)
Pension benefit obligation	$	67.0	$	37.0
Pension cost	$	8.3	$	4.0

10. Disposition of Unconsolidated Subsidiary

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

The pro forma information presented below reflectsCinergy's net income and EPS without the investment in Midlands for 1999 and 1998.

		Year Ended December 31
		1999					1998
		Net Income			EPS(1)		Net Income			EPS(2)
		(in millions, except for earnings per share)
Reported results		$	404		$	2.54	$	261		$	1.65
Pro forma adjustments:
	Equity in earnings of Midlands		(58	)				(57	)
	Gain on sale of investment in Midlands		(99	)				—
	Interest		21					43
	Income taxes		40					(18	)

Pro forma results		$	308		$	1.94	$	229		$	1.45

(1): Represents basic EPS. Actual diluted EPS were $2.53, and pro forma diluted EPS were $1.93.
(2): Both basic and diluted.

11. Income Taxes

The following table shows the significant components ofCinergy's, CG&E's, andPSI's net deferred income tax liabilities as of December 31, 2000, and 1999:

		Cinergy(1)				CG&E and subsidiaries				PSI
		2000		1999		2000		1999		2000		1999
		(in millions)				(in millions)				(in millions)
Deferred Income Tax Liability
	Utility plant	$	1,135.9	$	1,130.4	$	703.0	$	696.0	$	432.8	$	434.4
	Unamortized costs of reacquiring debt		18.2		20.9		8.1		10.5		10.1		10.4
	Deferred operating expenses and carrying costs		60.2		43.5		40.7		26.9		19.5		16.6
	Amounts due from customers—income taxes		96.2		95.6		91.2		91.6		5.0		4.0
	Gasification services agreement buyout costs		94.8		94.9		—		—		94.8		94.9
	Other		60.9		55.7		37.0		23.3		9.0		6.8

Total Deferred Income Tax Liability			1,466.2		1,441.0		880.0		848.3		571.2		567.1
Deferred Income Tax Asset
	Unamortized investment tax credits		56.1		53.6		42.8		37.3		13.2		16.3
	Accrued pension and other benefit costs		137.7		88.0		67.5		34.3		39.8		26.9
	Net energy risk management liabilities		24.6		32.3		6.1		11.5		18.5		20.9
	Rural Utilities Service (RUS) obligation		28.2		30.7		—		—		28.2		30.7
	Other		33.6		61.6		27.8		45.0		12.9		11.6

Total Deferred Income Tax Asset			280.2		266.2		144.2		128.1		112.6		106.4

Net Deferred Income Tax Liability		$	1,186.0	$	1,174.8	$	735.8	$	720.2	$	458.6	$	460.7

(1): Cinergy's net deferred income tax liability also includes the effects of foreign non-registrant subsidiaries' activity.

We will file a consolidated federal income tax return for the year ended December 31, 2000. The current tax liability is allocated among the members of theCinergy consolidated group pursuant to a tax sharing agreement filed with the SEC under the PUHCA.

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

			Cinergy									CG&E and subsidiaries									PSI
			2000			1999			1998			2000			1999			1998			2000			1999			1998
			(in millions)									(in millions)									(in millions)
Current Income Taxes
	Federal		$	187.3		$	114.0		$	209.0		$	121.5		$	137.3		$	151.7		$	84.4		$	(30.6	)	$	69.8
	State			16.9			(1.5	)		16.9			1.6			4.0			3.9			10.8			(3.1	)		10.5

Total Current Income Taxes				204.2			112.5			225.9			123.1			141.3			155.6			95.2			(33.7	)		80.3
Deferred Income Taxes
	Federal
		Depreciation and other utility plant-related items		26.1			24.0			25.3			19.0			13.8			14.7			7.1			10.2			10.7
		Pension and other benefit costs		(21.3	)		(10.5	)		(3.3	)		(7.5	)		(5.3	)		5.0			(11.5	)		(5.0	)		(1.9	)
		RUS obligations		—			—			(22.5	)		—			—			—			—			—			(22.5	)
		Unrealized energy risk management losses		10.9			(5.1	)		(49.4	)		5.6			(11.6	)		(25.2	)		2.0			6.5			(24.2	)
		Fuel costs		28.7			4.3			(1.0	)		26.7			2.7			(1.5	)		2.0			1.6			.5
		Gasification services agreement buyout costs		(0.1	)		83.6			—			—			—			—			(0.1	)		83.6			—
		Other items—net		11.0			(5.1	)		(40.8	)		(3.0	)		8.3			(13.7	)		(1.2	)		(4.5	)		(10.6	)

Total Deferred Federal Income Taxes				55.3			91.2			(91.7	)		40.8			7.9			(20.7	)		(1.7	)		92.4			(48.0	)
		State		1.7			14.2			(7.4	)		1.5			.6			(.4	)		(1.4	)		13.6			(5.8	)

Total Deferred Income Taxes				57.0			105.4			(99.1	)		42.3			8.5			(21.1	)		(3.1	)		106.0			(53.8	)
Investment Tax Credits—Net				(9.6	)		(9.2	)		(9.6	)		(6.0	)		(6.1	)		(6.2	)		(3.6	)		(3.1	)		(3.4	)

Total Income Taxes			$	251.6		$	208.7		$	117.2		$	159.4		$	143.7		$	128.3		$	88.5		$	69.2		$	23.1

The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the

federal income tax expense reported in the Consolidated Statements of Income forCinergy, CG&E, andPSI.

		Cinergy									CG&E and subsidiaries									PSI
		2000			1999			1998			2000			1999			1998			2000			1999			1998
					(in millions)									(in millions)									(in millions)
Statutory federal income tax provision		$	221.3		$	209.9		$	129.0		$	148.1		$	130.4		$	119.2		$	75.1		$	61.6		$	24.7
Increases (Reductions) in taxes resulting from:
	Amortization of investment tax credits		(9.6	)		(9.2	)		(9.6	)		(6.0	)		(6.1	)		(6.2	)		(3.6	)		(3.1	)		(3.4	)
	Depreciation and other utility plant-related differences		17.7			14.4			10.4			14.0			11.6			9.0			3.6			2.8			1.5
	Preferred dividend requirements of subsidiaries		1.6			1.9			2.3			—			—			—			—			—			—
	Foreign tax adjustments		—			(15.5	)		(20.0	)		—			—			—			—			—			—
Other—net			2.0			(5.5	)		(4.4	)		0.2			3.2			2.8			4.0			(2.6	)		(4.4	)

Federal income tax expense		$	233.0		$	196.0		$	107.7		$	156.3		$	139.1		$	124.8		$	79.1		$	58.7		$	18.4

The following table shows the significant components ofULH&P's net deferred income tax liability as of December 31, 2000, and 1999:

		ULH&P
		2000		1999
		(in thousands)
Deferred Income Tax Liability
	Utility plant	$	32,674	$	34,903
	Unamortized costs of reacquiring debt		747		1,356
	Deferred fuel costs		6,934		—
	Other		3,620		2,062

Total Deferred Income Tax Liability			43,975		38,321
Deferred Income Tax Asset
	Unamortized investment tax credits		1,309		1,608
	Amounts due to customers—income taxes		2,627		4,618
	Deferred fuel costs		—		949
	Accrued pension and other benefit costs		2,660		2,282
	Other		1,557		5,864

Total Deferred Income Tax Asset			8,153		15,321
Net Deferred Income Tax Liability		$	35,822	$	23,000

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

			ULH&P
			2000			1999			1998
			(in thousands)
Current Income Taxes
	Federal		$	5,003		$	8,668		$	6,699
	State			(129	)		2,253			1,336

Total Current Income Taxes				4,874			10,921			8,035
Deferred Income Taxes
	Federal
		Depreciation and other utility plant-related items		1,059			831			420
		Pension and other benefit costs		(605	)		40			319
		Fuel costs		8,564			(1,385	)		820
		Unamortized costs of reacquiring debt		(30	)		(39	)		(58	)
		Service company allocations		251			324			(1,376	)
		Other items-net		(338	)		(155	)		(415	)

Total Deferred Federal Income Taxes				8,901			(384	)		(290	)
Deferred State Income Taxes				303			(76	)		308

Total Deferred Income Taxes				9,204			(460	)		18
Investment Tax Credits—Net				(277	)		(277	)		(279	)

Total Income Taxes			$	13,801		$	10,184		$	7,774

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

		ULH&P
		2000			1999			1998
		(in thousands)
Statutory federal income tax provision		$	13,391		$	7,098		$	6,937
Increases (Reductions) in taxes resulting from:
	Amortization of investment tax credits		(277	)		(277	)		(279	)
	Depreciation and other utility plant-related differences		830			94			(168	)
	Other—net		(317	)		1,092			(360	)

Federal income tax expense		$	13,627		$	8,007		$	6,130

12. Commitments and Contingencies

(a) Construction and Other Commitments Forecasted construction and other committed expenditures for the year 2001 and for the five-year period 2001-2005 (in nominal dollars) are presented in the table below:

	2001		2001-2005
	(in millions)
Cinergy(1)	$	1,467	$	4,635
CG&E and subsidiaries		423		1,676
PSI		406		2,264
ULH&P		37		178

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

This forecast includes an estimate of expenditures in accordance with the companies' plans regarding nitrogen oxide (NO_X) emission control standards and other environmental compliance (excluding implementation of the tentative EPA Agreement), as discussed below. Approximately $210 million is estimated to be spent in 2001 and approximately $789 million is estimated to be spent between 2001 and 2005. This forecast also includes expenditures for the pending purchase of two natural gas-fired merchant electric generating facilities from Enron North America with a total combined capacity of 998 megawatts (MW), the acquisition of an interest in a gas distribution business in Athens, Greece, and other committed investments.

(b) Ozone Transport Rulemaking In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the U.S. Environmental Protection Agency (EPA) to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant with ozone standards) in the Northeast, Midwest, and South. Ozone transport refers to wind-blown movement of ozone and ozone-causing materials across city and state boundaries. In late 1997, the EPA published a proposed call for revisions to State Implementation Plans (SIPs). SIP is an acronym for a state's implementation plan for achieving emissions reductions to address air quality concerns. The EPA must approve all SIPs.

NO_X SIP Call In October 1998, the EPA finalized its ozone transport rule, also known as the NO_X SIP Call. It applied to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate, and also proposed a model NO_X emission allowance trading program. This rule recommended states reduce NO_X emissions primarily from industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999 to incorporate NO_X reductions and, at the discretion of the state, a NO_X trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NO_X reductions by May 2003 if states failed to revise their SIPs.

In March 2000, the Court of Appeals substantially upheld the EPA's rule. On April 11, 2000, the EPA asked the Court of Appeals to remove its May 25, 1999, suspension of the rule and also directed states to submit SIP revisions by September 1, 2000. On April 17, 2000, various states and industry groups (some of which we are a member) filed a request with the Court of Appeals for a rehearing of the NO_X SIP Call decisions. On April 24, 2000, the same group filed a request with the Court of Appeals to require a rulemaking and a comment period to determine a new compliance date. The

states also filed a request to obtain more time to file their SIPs. On June 23, 2000, the Court of Appeals denied both requests and directed the states to submit their SIP revisions by October 30, 2000. The states of Indiana, Kentucky, and Ohio subsequently submitted letters stating their intent to revise their SIPs in response to the NO_X SIP Call.

In August 2000, the Court of Appeals extended the May 1, 2003 deadline for NO_X reductions to May 31, 2004. The states and other groups appealed the Court of Appeals ruling to the U.S. Supreme Court.

•: install up to 11 selective catalytic reduction units (SCRs) at several different generating stations;
•: install other pollution control technologies, including new computer software, at all generating stations;
•: make combustion improvements; and
•: utilize market opportunities to buy and sell NO_X allowances.

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

State Ozone Plans On November 15, 1999, the State of Indiana and the Commonwealth of Kentucky (along with Jefferson County, Kentucky) jointly filed an amendment to their attainment demonstration on how they intend to bring the greater Louisville area, including Floyd and Clark Counties in Indiana, into attainment with the one-hour ozone standard. The SIP amendments call for, among other things, statewide NO_X reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA's NO_X SIP Call. Indiana and Kentucky committed to adopt utility NO_X control rules by December 2000, that would require controls be installed by May 2003. However, Indiana, halted the rulemaking for NO_X controls at this level, but continues to develop NO_X SIP Call level reduction regulations. Kentucky did complete their rulemaking, but has issued a notice of intent to revise the rules to change the compliance deadline to mirror the NO_X SIP Call (May 31, 2004).

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

(c) New Source Review (NSR) The CAA's NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major change to an existing facility unless the changes are exempt. In July 1998, the EPA requested comments on proposed revisions to the NSR rules that would change NSR applicability by eliminating exemptions contained in the current regulation.

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

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

On March 1, 2000, the EPA also filed an amended complaint in a separate lawsuit alleging violations of the CAA relating to the NSR, Prevention of Significant Deterioration (PSD), and Ohio SIP requirements regarding a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), andCG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP.

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

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

(d) Beckjord Station NOV On November 30, 1999, the EPA filed an NOV againstCinergy andCG&E alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit. The NOV indicated that the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. The allegations contained in this NOV were incorporated within the March 1, 2000 amended complaint, as discussed in section (c). On June 22, 2000, the EPA issued an NOV and a Finding of Violation (FOV) alleging additional particulate emission violations at Beckjord Station and offered us an opportunity to

meet and discuss the allegations and corrective measures. The NOV/FOV indicated the EPA may issue an administrative compliance order, issue an administrative penalty order, or bring a civil or criminal action.

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

(e) EPA Agreement On December 21, 2000,Cinergy,CG&E, andPSI reached an agreement in principle with the EPA, the U.S. Department of Justice, three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated byCinergy's operating subsidiaries. The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties. If a final agreement is reached with these parties, this would resolve past claims of the NSR as well as the Beckjord Station NOVs/FOV discussed above.

In return for resolution of past claims, future operational certainty, and protection of system wide demand growth, we have tentatively agreed to:

•: shut down or repower with natural gas nine small coal-fired boilers at three power plants beginning in 2004;
•: build four additional SO₂ scrubbers, the first of which must be operational by December 31, 2007;
•: upgrade existing pollution control systems;
•: phase in the operation of NO_X reduction technology year-round starting in 2004;
•: retire 50,000 tons of SO₂ allowances between 2001 and 2005 and reduce our SO₂ cap by 35% in 2013;
•: pay a civil penalty of $8.5 million to the U.S. government; and
•: implement $21.5 million in environmental mitigation projects.

(f) Manufactured Gas Plant (MGP) Sites

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

(ii) PSI Coal tar residues, related hydrocarbons, and various metals associated with MGP sites have been found at former MGP sites in Indiana, including at least 21 sites whichPSI or its predecessors previously owned.PSI acquired four of the sites from Northern Indiana Public Service

Company (NIPSCO) in 1931. At the same time,PSI sold NIPSCO the sites located in Goshen and Warsaw, Indiana. In 1945,PSI sold 19 of these sites (including the four sites it acquired from NIPSCO) to the predecessor of the Indiana Gas Company, Inc. (IGC). IGC later sold the site located in Rochester, Indiana, to NIPSCO.

IGC (in 1994) and NIPSCO (in 1995) both made claims againstPSI. The basis of these claims was thatPSI is a Potentially Responsible Party with respect to the 21 MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted thatPSI is legally responsible for the costs of investigating and remediating the sites. In August 1997, NIPSCO filed suit againstPSI in federal court claiming recovery (pursuant to CERCLA) of NIPSCO's past and future costs of investigating and remediating MGP-related contamination at the Goshen MGP site.

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

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

(g) Other In compliance with an electric wholesale rate case settlement adopted by the FERC effective February 2000,CG&E reduced the cost of fuel reflected in its wholesale base rates and revised its wholesale fuel adjustment factor. Beginning March 1, 2000,ULH&P began passing through to retail customers the fuel costs incurred pursuant to the revised wholesale fuel adjustment factor. The company believes it is not required to synchronize the cost of fuel reflected in retail base rates with the reduced cost of fuel reflected in wholesale base rates, outside of a general rate proceeding. As a result, in 2000,ULH&P recovered and recognized as revenue approximately $14 million more in costs than it incurred. This issue is currently before the Kentucky Public Service Commission (KPSC). WhileULH&P believes its position is consistent with applicable rate regulations, it is possible that the KPSC might require rate synchronization prospectively or disallow recovery of the $14 million recognized as revenue during 2000.ULH&P currently cannot predict the outcome of this matter.

13. Jointly-Owned Plant

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

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

			Ownership Share		Utility Plant in Service		Accumulated Depreciation		Construction Work in Progress
			(in millions)
CG&E
	Production:
		Miami Fort Station (Units 7 and 8)	64.00	%	$	227	$	134	$	17
		Beckjord Station (Unit 6)	37.50			42		29		1
		Stuart Station(1)	39.00			280		146		21
		Conesville Station (Unit 4)(1)	40.00			77		44		—
		Zimmer Station	46.50			1,241		348		9
		East Bend Station	69.00			336		190		13
		Killen Station(1)	33.00			187		101		1
	Transmission		Various			65		34		6
PSI
	Production:
		Gibson Station (Unit 5)	50.05			214		112		1
	Transmission and local facilities		94.94			2		1		—

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

14. Quarterly Financial Data (unaudited)

		Cinergy					CG&E					PSI
Quarter Ended		2000		1999			2000		1999			2000		1999
		(in millions, except per share amounts)
March 31
	Operating Revenues	$	1,583	$	1,402		$	716	$	645		$	534	$	482
	Operating Income		274		234			181		155			102		86
	Net Income		138		127			96		80			50		40
	Basic EPS		.87		.80			N/A		N/A			N/A		N/A
	Diluted EPS		.87		.80			N/A		N/A			N/A		N/A
June 30
	Operating Revenues	$	1,770	$	1,275		$	707	$	531		$	620	$	463
	Operating Income		167		137			113		88			49		61
	Net Income		75		59			56		39			19		26
	Basic EPS		.47		.37			N/A		N/A			N/A		N/A
	Diluted EPS		.47		.37			N/A		N/A			N/A		N/A
September 30
	Operating Revenues	$	2,300	$	1,782		$	840	$	738		$	804	$	707
	Operating Income		196		137	(2)		81		104	(2)		63		47	(2)
	Net Income		94		122	(1,2)		39		48	(2)		31		16	(2)
	Basic EPS		.59		.77	(1,2)		N/A		N/A			N/A		N/A
	Diluted EPS		.58		.76	(1,2)		N/A		N/A			N/A		N/A
December 31
	Operating Revenues	$	2,769	$	1,479		$	967	$	637		$	726	$	484
	Operating Income		225		185			153		132			83		78
	Net Income		92		96			76		67			35		35
	Basic EPS		.58		.60			N/A		N/A			N/A		N/A
	Diluted EPS		.58		.60			N/A		N/A			N/A		N/A
Total
	Operating Revenues	$	8,422	$	5,938		$	3,230	$	2,551		$	2,684	$	2,136
	Operating Income		862		693			528		479			297		272
	Net Income		399		404			267		234			135		117
	Basic EPS		2.51		2.54			N/A		N/A			N/A		N/A
	Diluted EPS		2.50		2.53			N/A		N/A			N/A		N/A

(1): In the third quarter of 1999, we realized a net contribution to earnings of approximately $.43 per share (basic and diluted) when we sold our 50% ownership interest in Midlands.
(2): In the third quarter of 1999, throughCG&E andPSI, we experienced extreme weather conditions which resulted in a reduction in net income of $57 million ($16 million forCG&E, $41 million forPSI) after tax or $.36 per share (basic and diluted).

15. Financial Information by Business Segment

During 1998, we adopted the requirements of Statement of Financial Accounting Standards No. 131,Disclosures about Segments of an Enterprise and Related Information (Statement 131). Statement 131 requires disclosures about reportable operating segments in annual and interim condensed financial statements based on the following:

•: products and services;
•: geography;
•: legal structure;
•: management structure; or
•: any other manner in which management divides a company.

Our business units were initially formed during the second half of 1996 and began operating as separately identifiable business units in 1997. As of December 31, 2000, each business unit has its own management structure, headed by a business unit president. As discussed in Note 1(a), during 2000 our business units were Commodities, Delivery, Cinergy Investments, and International. Each business unit and its responsibilities as of this date, are described below.

Commodities operates and maintains our domestic regulated and non-regulated electric generating plants and some of our jointly-owned plants. It also conducts the following activities:

•: wholesale energy marketing and trading;
•: energy risk management;
•: financial restructuring services; and
•: proprietary arbitrage activities.

Commodities earns revenues from external customers from its marketing, trading, and risk management activities. Commodities earns intersegment revenues from the sale of electric power to Delivery.

Delivery plans, constructs, operates, and maintains our operating companies' transmission and distribution systems and provides gas and electric energy to consumers. Delivery earns revenues from wholesale customers primarily by transmitting electric power through our transmission system. Delivery currently receives all of its electricity from Commodities at a transfer price based upon current regulatory ratemaking methodology.

Cinergy Investments manages the development, marketing, and sales of our domestic non-regulated and non-wholesale energy and energy-related products and services. This is accomplished through various subsidiaries and joint ventures. These products and services include the following:

•: providing energy management-consulting services and infrastructure solutions to government, industrial, and commercial customers that operate retail facilities;
•: providing various utility services to utilities (for example, providing underground locating and construction services for utilities);
•: providing telecommunication services including dark fiber, high capacity service, internet service, local phone service, and long distance service;
•: leasing of space on wireless telecommunication towers and the purchase and construction of such towers;
•: providing various engineering, procurement, construction, operation and maintenance functions such as designing and constructing turnkey gas pipelines, electric transmission and distribution lines, substations for industrial and large commercial customers, and fiber optic telecommunication cables;
•: providing information, systems, and services to multi-site national chains in retail industries to optimize their energy, telecommunications, and other facility-wide costs;
•: building, owning, operating, and maintaining combined heat and power facilities; and
•: pursuing technology equity investments and running technology pilots.

International primarily directs and manages our international business holdings. These holdings include wholly-owned and jointly-owned companies in ten foreign countries. In addition, International directs our renewable energy investing activities (for example, wind farms), which includes investments within the U.S. as well as abroad. International earns (1) revenues from consolidated subsidiaries, and (2) equity earnings from unconsolidated companies primarily from energy-related businesses.

As the utility industry continues to evolve,Cinergy will continue to analyze its operating structure and make modifications as appropriate. In early 2001, we announced certain organizational changes which further aligned the business units consistent withCinergy's strategic vision. The revised structure reflects three business units, as follows:

•: Energy Merchant—will operate power plants, both domestically and abroad, and conduct all wholesale energy marketing, trading, origination and risk management services;
•: Regulated Businesses—will operate all gas and electric transmission and distribution services, both domestically and abroad, and will be responsible for all regulatory planning for the regulated utility businesses ofCG&E,PSI, andULH&P; and
•: Power Technology and Infrastructure Services—will originate and manage a portfolio of emerging energy businesses.

Financial information by (1) business units, (2) products and services, and (3) geographic areas and long-lived assets for the years ending December 31, 2000, 1999, and 1998, are as follows:

Business Units

		2000
		Cinergy Business Units
		Commodities			Delivery		Cinergy Investments			International			Total		All Other(1)		Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues—
	External customers	$	4,923		$	3,333	$	83		$	83		$	8,422	$	—	$	—		$	8,422
	Intersegment revenues		1,889			—		—			—			1,889		—		(1,889	)		—
Depreciation and amortization(3)			212			146		3			13			374		—		—			374
Equity in earnings of unconsolidated subsidiaries			(8	)		—		4			9			5		—		—			5
Interest(4)			99			92		11			22			224		—		—			224
Income taxes			159			109		(6	)		(10	)		252		—		—			252
Segment profit (loss)(5)			254			168		(11	)		(12	)		399		—		—			399
Total segment assets			7,084			4,413		283			508			12,288		42		—			12,330
Investments in unconsolidated subsidiaries			364			—		79			95			538		—		—			538
Total expenditures for long-lived assets			260			265		(1	)		—			524		1		—			525

(1): The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2): The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3): The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4): Interest income is deemed immaterial.
(5): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.

Business Units (cont.)

		1999
		Cinergy Business Units
		Commodities			Delivery		Cinergy Investments			International		Total		All Other(1)		Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues—
	External customers	$	2,586		$	3,232	$	59		$	61	$	5,938	$	—	$	—		$	5,938
	Intersegment revenues		1,857			—		—			—		1,857		—		(1,857	)		—
Depreciation and amortization(3)			209			138		—			7		354		—		—			354
Equity in earnings of unconsolidated subsidiaries			(2	)		—		—			60		58		—		—			58
Gain on sale of investment in unconsolidated subsidiary			—			—		—			99		99		—		—			99
Interest(4)			96			102		4			32		234		1		—			235
Income taxes			70			120		(6	)		25		209		—		—			209
Segment profit (loss)(5)			136			184		(9	)		93		404		—		—			404
Total segment assets			5,042			4,058		130			340		9,570		47		—			9,617
Investments in unconsolidated subsidiaries			257			—		25			77		359		—		—			359
Total expenditures for long-lived assets			131			256		3			—		390		—		—			390

(1): The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2): The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3): The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4): Interest income is deemed immaterial.
(5): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.

Business Units (cont.)

		1998
		Cinergy Business Units
		Commodities			Delivery		Cinergy Investments			International			Total		All Other(1)			Reconciling Eliminations(2)			Consolidated
		(in millions)
Operating revenues—
	External customers	$	2,726		$	3,090	$	52		$	43		$	5,911	$	—		$	—		$	5,911
	Intersegment revenues		1,782			—		—			—			1,782		—			(1,782	)		—
Depreciation and amortization(3)			197			127		—			2			326		—			—			326
Equity in earnings of unconsolidated subsidiaries			(1	)		—		(4	)		56			51		—			—			51
Interest(4)			95			91		—			51			237		7			—			244
Income taxes			57			90		(6	)		(17	)		124		(7	)		—			117
Segment profit (loss)(5)			94			157		(11	)		32			272		(11	)		—			261
Total segment assets			4,863			3,987		42			752			9,644		43			—			9,687
Investments in unconsolidated subsidiaries			—			—		8			566			574		—			—			574
Total expenditures for long-lived assets			108			242		3			—			353		17			—			370

(1): The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2): The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3): The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4): Interest income is deemed immaterial.
(5): Management utilizes segment profit (loss) after taxes to evaluate segment profitability.

Products and Services

	Revenues
	Utility						Energy Marketing and Trading
Year	Electric		Gas		Total		Electric		Gas		Total		Other		Consolidated
	(in millions)
2000	$	2,932	$	503	$	3,435	$	2,452	$	2,439	$	4,891	$	96	$	8,422
1999		2,938		420		3,358		1,375		1,176		2,551		29		5,938
1998		2,707		441		3,148		2,056		659		2,715		48		5,911

Our products and services focus on providing utility services (the supply of electric energy and gas) and energy marketing and trading services.

Geographic Areas and Long-Lived Assets

	Revenues
			International
Year	Domestic		United Kingdom (UK)(1)		All Other(2)		Total		Consolidated
	(in millions)
2000	$	8,339	$	—	$	83	$	83	$	8,422
1999		5,877		—		61		61		5,938
1998		5,868		—		43		43		5,911

	Long-Lived Assets
			International
Year	Domestic		United Kingdom (UK)(1)		All Other(2)		Total		Consolidated
2000	$	8,267	$	—	$	328	$	328	$	8,595
1999		7,841		2		277		279		8,120
1998		7,375		501		209		710		8,085

(1): As discussed in Note 10, on July 15, 1999, we sold our 50% ownership interest in Midlands. Prior to the sale, Midlands had provided the majority of International's earnings.
(2): International revenues are primarily from assets which we own in the Czech Republic, the majority of which are four district heating plants that provide 1,094 MW of thermal steam capacity which may be used to produce 149 MW of electricity. The Czech assets and results of operations are consolidated into our financial statements.

16. Earnings Per Common Share

A reconciliation of basic EPS to earnings per common share assuming dilution (diluted EPS) is presented below:

		Income		Shares	EPS
		(in millions, except per share amounts)
2000
Basic EPS:
	Net income	$	399	159	$	2.51
Effect of dilutive securities:
	Common stock options			1

Diluted EPS:
	Net income plus assumed conversions	$	399	160	$	2.50
1999
Basic EPS:
	Net income	$	404	159	$	2.54
Effect of dilutive securities:
	Common stock options			—

Diluted EPS:
	Net income plus assumed conversions	$	404	159	$	2.53
1998
Basic EPS:
	Net income	$	261	158	$	1.65
Effect of dilutive securities:
	Common stock options			1

Diluted EPS:
	Net income plus assumed conversions	$	261	159	$	1.65

Options to purchase shares of common stock are excluded from the calculation of diluted EPS when the exercise prices of these options are greater than the average market price of the common shares during the period. For 2000, 1999, and 1998, approximately two million, two million, and one million shares, respectively, were excluded from the diluted EPS calculation.

The Employee Stock Purchase and Savings Plan was also excluded from the diluted EPS calculation in 2000, 1999, and 1998 since the purchase price was greater than the average market price during this period. This plan allows all full-time, regular employees to purchase shares of common stock pursuant to a stock option feature.

17. WVPA Settlement

In February 1989,PSI and WVPA entered into a settlement agreement to resolve all claims related to Marble Hill, a nuclear project canceled in 1984. Implementation of the settlement was contingent on a number of events. During 1998,PSI reached agreement on all matters with the relevant parties and, as a result, recorded a liability to the RUS.PSI will repay the obligation to the RUS with interest over a 35-year term. The net proceeds from a 35-year power sales agreement with WVPA will be used to fund the principal and interest on the obligation to the RUS. Assumption of the liability (recorded asLong-term debt in the Consolidated Balance Sheet) resulted in a charge against earnings of $80 million ($50 million after tax or $.32 per share basic and diluted) in the second quarter of 1998.

18. Ohio Deregulation

On July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill), beginning the transition to electric deregulation and customer choice for the state of Ohio. The Electric Restructuring Bill created a competitive electric retail service market effective January 1, 2001. The legislation provided for a market development period that began January 1, 2001, and ends no later than December 31, 2005. Ohio electric utilities have an opportunity to recover PUCO approved transition costs during a transition period. The legislation also froze retail electric rates during the market development period, at the rates in effect on October 4, 1999, except for a five-percent reduction in the generation component of residential rates. Furthermore, the legislation contemplated that 20% of the current electric retail customers will switch suppliers no later than December 31, 2003.

•: Residential customer rates will be frozen through December 31, 2005;
•: Residential customers will receive a five-percent reduction in the generation portion of their electric rates, effective January 1, 2001;
•: CG&E has agreed to provide four million dollars over the next five years in support of energy efficiency and weatherization services for low income customers;
•: The creation of an RTC designed to recoverCG&E's regulatory assets and other transition costs over a ten-year period;
•: Authority forCG&E to transfer its generation assets to one or more separate, non-regulated corporate subsidiary(ies) to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;
•: Authority forCG&E to apply the proceeds of transition cost recovery to costs incurred during the transition period including implementation costs and purchased power costs that may be incurred byCG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;
•: CG&E will provide standard offer default supplier service (i.e.,CG&E will be the supplier of last resort, so that no customer will be without an electric supplier); and
•: CG &E has agreed to provide shopping credits to switching customers.

As indicated above, the August 31, 2000 order authorizesCG&E to transfer its generation assets to one or more non-regulated corporate subsidiary(ies). This transfer may require the approval or consent of one or more of the following: the IURC, the Kentucky Public Service Commission, the FERC, the SEC under the PUHCA, and various third parties. As the transfer is contingent upon the company receiving various consents and approvals, the timing and receipt of which are unknown, the completion date of the transfer of generation assets to a non-regulated subsidiary is uncertain. See Note 1(c) regarding the effects of the transition order.

In connection with the approval of the stipulation agreement,CG&E discontinued the application of Statement 71 for the generation portion of its business and adopted Statement 101, with no material financial statement impact. Pursuant to Statement of Financial Accounting Standards No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of our analysis indicates future revenues will be sufficient to recover the costs of our generating assets over their estimated remaining lives.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

BOARD OF DIRECTORS

Information regardingCinergy Corp.'s directors is incorporated by reference from its definitive Proxy Statement for the 2001 Annual Meeting of Shareholders.

The directors of The Cincinnati Gas & Electric Company (CG&E) at January 31, 2001, are as follows:

•: J. Joseph Hale, Jr.—Mr. Hale, age 51, is President ofCG&E, a position he has held since July 2000. He has served as a director ofCG&E since December 2000. His current term as director expires April 30, 2001.
•: James E. Rogers—Mr. Rogers, age 53, is Chairman of the Board and Chief Executive Officer ofCG&E. He has served as a director ofCG&E since 1994. His current term as director expires April 30, 2001.
•: James L. Turner—Mr. Turner, age 41, is Vice President ofCG&E, a position he has held since July 2000. He has served as a director ofCG&E since February 15, 1999. His current term as director expires April 30, 2001.

Additional information on each of the directors ofCG&E is presented in and incorporated in the following "Executive Officers" section.

Information regarding PSI Energy, Inc.'s (PSI) directors is incorporated by reference from its 2001 Information Statement.

EXECUTIVE OFFICERS

The names of the executive officers of each registrant, their ages (as of December 31, 2000), the positions they hold, held, or have been elected to as of this report filing date, and their business experience during the past five years is included in the chart below.

		Positions and Length of Service
Name	Age	Cinergy Corp.	CG&E	PSI
Vicky A. Bailey(1)	48			President 2/00 - present
John Bryant(2)	54	Vice President 1/98 - present President, International Business Unit 7/00 - 2/01

Michael J. Cyrus(3)	45	Executive Vice President 2/01 - present Chief Executive Officer, Energy Merchant Business Unit 2/01 - present President, Energy Commodities Business Unit 3/99 - 2/01 Vice President 4/98 - present Chief Operating Officer, Energy Commodities Business Unit 11/98 - 3/99	Executive Vice President 2/01 - present Vice President 4/99 - 2/01	Executive Vice President 2/01 - present Vice President 4/99 - 2/01
R. Foster Duncan(4)	46	Executive Vice President and Chief Financial Officer 2/01 - present	Executive Vice President and Chief Financial Officer 2/01 - present	Executive Vice President and Chief Financial Officer 2/01 - present
Lisa D. Gamblin(5)	37	Vice President and Treasurer 10/00 - present Vice President and Chief Financial Officer, Energy Delivery Business Unit 3/99 - 10/00 Vice President and Chief Financial Officer, International Business Unit 2/98 - 3/99 Manager, Corporate Development 5/97 - 2/98	Vice President and Treasurer 10/00 - present	Vice President and Treasurer 10/00 - present

William J. Grealis(6)	55	Executive Vice President 2/01 - present Chief Executive Officer, Regulated Businesses Business Unit 2/01 - present Executive Vice President and Chief of Staff 7/00 - 2/01 Vice President, Corporate Services, and Chief Strategic Officer 8/98 - 7/00 Vice President 1/95 - 8/98	Executive Vice President 2/01 - present Executive Vice President and Chief of Staff 7/00 - 2/01 Vice President, Corporate Services, and Chief Strategic Officer 8/98 - 7/00 Vice President 4/98 - 8/98 President 1/95 - 3/98	Executive Vice President 2/01 - present Executive Vice President and Chief of Staff 7/00 - 2/01 Vice President, Corporate Services, and Chief Strategic Officer 8/98 - 7/00 Vice President 4/98 - 8/98
J. Joseph Hale, Jr.(7)	51	Vice President 12/96 - present	President 7/00 - present Vice President 8/98 - 7/00 General Manager, Marketing Operations 1/95 - 8/98	Vice President 2/00 - 7/00 Interim President 6/99 - 2/00 Vice President 8/98 - 6/99
M. Stephen Harkness(8)	52	Vice President 12/96 - present General Manager, Corporate Development and Financial Services 10/94 - 12/96
Donald B. Ingle, Jr.(9)	51	President, Power Technology and Infrastructure Services Business Unit 2/01 - present President, Cinergy Investments Business Unit 3/99 - 2/01 Vice President 10/97 - present	Vice President 10/97 - 3/99	Vice President 10/97 - 3/99

Julia S. Janson	36	Secretary 7/00 - present Senior Counsel 7/98 - present Counsel 5/96 - 7/98 Manager, Investor Relations 1/95 - 5/96	Assistant Secretary 7/00 - present Senior Counsel 7/98 - present Counsel 5/96 - 7/98 Manager, Investor Relations 1/95 - 5/96	Secretary 7/00 - present Senior Counsel 7/98 - present Counsel 5/96 - 7/98 Manager, Investor Relations 1/95 - 5/96
Bernard F. Roberts	48	Vice President and Comptroller 3/99 - present Vice President and Chief Financial Officer, Energy Commodities Business Unit 7/96 - 3/99 Assistant Treasurer 12/94 - 7/96	Vice President and Comptroller 3/99 - present Assistant Treasurer 1/95 - 7/96	Vice President and Comptroller 3/99 - present Assistant Treasurer 12/94 - 7/96
James E. Rogers	53	Chairman of the Board, President and Chief Executive Officer 12/00 - present Vice Chairman, President and Chief Executive Officer 12/95 - 12/00	Chairman of the Board and Chief Executive Officer 12/00 - present Vice Chairman and Chief Executive Officer 12/95 - 12/00	Chairman of the Board and Chief Executive Officer 12/00 - present Vice Chairman and Chief Executive Officer 12/95 - 12/00

Larry E. Thomas(10)	55	Executive Vice President 2/01 - present Chief Executive Officer, Power Technology and Infrastructure Services Business Unit 2/01 - present Group President 7/00 - 2/01 Vice President 4/97 - 7/00 President, Energy Delivery Business Unit 5/96 - 7/00 Group Vice President and Chief Transformation Officer 9/95 - 4/97	Executive Vice President 2/01 - present Group President 7/00 - 2/01 Vice President 4/97 - 7/00 Group Vice President and Chief Transformation Officer 9/95 - 4/97	Executive Vice President 2/01 - present Group President 7/00 - 2/01 Vice President 4/97 - 7/00 Group Vice President and Chief Transformation Officer 9/95 - 4/97
James L. Turner(11)	41	President, Regulated Businesses Business Unit 2/01 - present President, Energy Delivery Business Unit 7/00 - 2/01 Vice President 4/99 - present Senior Counsel 6/95 - 3/97	Vice President 7/00 - present President 2/99 - 7/00	Vice President 7/00 - present
Jerome A. Vennemann	50	Vice President and General Counsel 1/00 - present Acting General Counsel 3/99 - 1/00 Assistant Secretary 12/94 - present Associate General Counsel 2/96 - 3/99 Senior Counsel 10/94 - 2/96	Vice President and General Counsel 1/00 - present Acting General Counsel 3/99 - 1/00 Secretary 4/98 - present Associate General Counsel 2/96 - 3/99 Assistant Secretary 1/95 - 4/98 Senior Counsel 10/94 - 2/96	Vice President and General Counsel 1/00 - present Acting General Counsel 3/99 - 1/00 Assistant Secretary 12/94 - present Associate General Counsel 2/96 - 3/99 Senior Counsel 10/94 - 2/96

Timothy J. Verhagen(12)		54		Vice President 1/01 - present
Charles J. Winger		55		Vice President 2/01 - present Vice President and Acting Chief Financial Officer 6/00 - 2/01 Vice President 3/99 - 6/00 Vice President and Chief Financial Officer 4/98 - 3/99 Vice President 8/97 - 4/98 Vice President and Comptroller 4/97 - 8/97 Comptroller 12/94 - 4/97		Vice President and Acting Chief Financial Officer 6/00 - 2/01 Vice President and Chief Financial Officer 4/98 - 3/99 Vice President and Comptroller 4/97 - 8/97 Comptroller 1/95 - 4/97		Vice President and Acting Chief Financial Officer 6/00 - 2/01 Vice President and Chief Financial Officer 4/98 - 3/99 Vice President and Comptroller 4/97 - 8/97 Comptroller 3/84 - 4/97

None of the officers are related in any manner. Our executive officers hold the offices set opposite their names until the next annual meeting of the Board of Directors and until their successors have been elected and qualified.

(1): Prior to joiningPSI, Ms. Bailey served as Commissioner of the Federal Energy Regulatory Commission, a position she had held since 1993.
(2): Mr. Bryant also serves as the President of Cinergy Global Resources, Inc. and Cinergy Global Power, Inc., and as the Managing Director of Cinergy Global Power Services Limited,Cinergy's (which includesCinergy Corp. and all of our regulated and non-regulated subsidiaries) international project development subsidiary from 1997 to present. Previously, he served as the Executive Generation Director of Midlands Electricity plc (Midlands; a non-affiliate ofCinergy) from 1996 to 1997, and Generation Director of Midlands from 1992 to 1996.
(3): Prior to joiningCinergy, Mr. Cyrus was Senior Vice President of Trading and Operations with Electric Clearinghouse, Inc. (a non-affiliate ofCinergy), the power subsidiary of Natural Gas Clearinghouse (NGC; a non-affiliate ofCinergy) in Houston, Texas, a position he had held since 1997. Prior to that, Mr. Cyrus was President of NGC Canada and Executive Vice President of Novagas Clearinghouse, Ltd. Previously, Mr. Cyrus held various executive positions involving energy trading, marketing, and risk management with NGC since 1993.
(4): Prior to joiningCinergy, Mr. Duncan was Executive Vice President and Chief Financial Officer of LG&E Energy Corporation (LG&E; a non-affiliate ofCinergy) in Louisville, Kentucky since December 1998. Prior to that, he was Executive Vice President of Planning and Corporate Development at LG&E from January 1998 to December 1998. Prior to joining LG&E, in January 1998, he was Vice President and Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold (non-affiliates ofCinergy), global natural resource companies headquartered in New Orleans, Louisiana since May 1994.
(5): From October 1995 to May 1997, Ms. Gamblin served as Assistant to the Chief Executive Officer, where she had responsibility for a wide range of projects, including venture capital analysis, merger and acquisition analysis, international projects and general strategy.
(6): As Executive Vice President and Chief of Staff, Mr. Grealis had responsibility for all shared service functions, including legal, external communications, human resources, creative services, information technology, budgets and certain accounting functions. Mr. Grealis served as President of Cinergy Investments, Inc. (Investments) from 1995 to March 1999. Mr. Grealis also served as President of the former Energy Services Business Unit from 1996 to May 1997.
(7): Since 1992, Mr. Hale has served as President of Cinergy Foundation, Inc., aCinergy affiliate that is organized and operated exclusively for charitable purposes.
(8): Mr. Harkness also serves as President and Chief Operating Officer of Cinergy Solutions, Inc.
(9): From 1995 to March 1999, Mr. Ingle served as Contract Consultant for Investments. Mr. Ingle also served as President of the former Energy Services Business Unit from 1997 to March 1999.
(10): As Group President, Mr. Thomas had responsibility forCinergy's new technology initiatives and energy delivery. Effective January 10, 2000,Cinergy's Economic Development, Community Affairs, State Regulatory Affairs and State Governmental Affairs were merged into the former Energy Delivery Business Unit.
(11): In March 1997, Mr. Turner was appointed Vice President of Cinergy Services, Inc., (Services) having responsibility for the coordination of transition issues across all corporate subsidiaries in the move for full customer choice. Beginning in April 1998 until January 2000, Mr. Turner had full responsibility forCinergy's Government and Regulatory Affairs Department. Mr. Turner served as Vice President of Customer Services from January 2000 until July 2000.
(12): Prior to joiningCinergy, Mr. Verhagen served as Senior Vice President, Human Resources and Administration of United Dominion Industries Ltd. (United Dominion; a non-affiliate ofCinergy), a diversified manufacturer of industrial test equipment in Charlotte, North Carolina, from 1998 to 2000. From 1993 to 1998 he served as Vice President, Human Resources of United Dominion.

ITEM 11. EXECUTIVE COMPENSATION

Information in response to this item forCinergy Corp. andCG&E is incorporated by reference from its definitive Proxy Statement for the 2001 Annual Meeting of Shareholders.

AllCG&E directors currently are employees ofCinergy Corp. orCG&E, and receive no compensation for their services as directors.

Information in response to this item forPSI executive compensation is incorporated by reference fromPSI's 2001 Information Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT

Information in response to this item forCinergy Corp. is incorporated by reference from its definitive Proxy Statement for the 2001 Annual Meeting of Shareholders.

Cinergy Corp. owns all outstanding shares of common stock ofCG&E,CG&E's only voting security. Pursuant to Section 13(d) of the Securities Exchange Act of 1934, a beneficial owner of a security is any person who directly or indirectly has or shares voting or investment power over such security. No person or group is known by the management ofCG&E to be the beneficial owner of more than 5% of any series ofCG&E's class of cumulative preferred stock as of December 31, 2000.

CG&E's directors and executive officers did not beneficially own shares of any series of the class ofCG&E's cumulative preferred stock as of January 31, 2001. The beneficial ownership ofCinergy Corp. common stock by each director and named executive officer ofCG&E as of January 31, 2001, is set forth in the following table:

Name of Beneficial Owner(1)		Amount and Nature of Beneficial Ownership(2)
Michael J. Cyrus		166,473 shares
William J. Grealis		284,275 shares
J. Joseph Hale, Jr.		56,991 shares
Jackson H. Randolph		270,137 shares
James E. Rogers		988,863 shares
Larry E. Thomas		302,987 shares
James L. Turner		25,268 shares
Charles J. Winger		98,340 shares
All directors and executive officers as a group (11 persons)		2,319,167 shares (representing 1.46% of the class)

(1): No individual listed beneficially owned more than 0.623% of the outstanding shares of our common stock.
(2): Includes shares which there is a right to acquire within 60 days pursuant to the exercise of stock options in the following amounts: Mr. Cyrus—54,300; Mr. Grealis—157,796; Mr. Hale—29,221; Mr. Randolph—136,887; Mr. Rogers—696,429; Mr. Thomas—144,945; Mr. Turner—14,600; Mr. Winger—58,617; and all directors and executive officers as a group—1,376,477.

Information in response to this item forPSI is incorporated by reference from its 2001 Information Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information in response to this item forCinergy Corp. andCG&E is incorporated by reference fromCinergy Corp.'s definitive Proxy Statement for the 2001 Annual Meeting of Shareholders.

Information in response to this item forPSI is incorporated by reference from its 2001 Information Statement.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K

Financial Statements and Schedules

Refer to the page captioned "Index to Financial Statements and Financial Statement Schedules", for an index of the financial statements and financial statement schedules included in this report.

Reports on Form 8-K

The following reports on Form 8-K were filed during the quarter ended December 31, 2000:

Date of Report		Registrant(s)		Item Filed
October 16, 2000		Cinergy Corp.		Item 5. Other Events Item 7. Financial Statements and Exhibits.
December 22, 2000		Cinergy Corp. CG&E PSI		Item 5. Other Events Item 7. Financial Statements and Exhibits.

Exhibits

The documents listed below are being filed or have previously been filed on behalf ofCinergy Corp.,CG&E,PSI, and The Union Light, Heat and Power Company (ULH&P) and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Articles of Incorporation /By-laws
3-a	Cinergy Corp.(1)	Certificate of Incorporation ofCinergy Corp., a Delaware corporation.	Cinergy Corp. 1993 Form 10-K.
3-b	Cinergy Corp.	By-Laws ofCinergy Corp., as amended on April 27, 2000.	Cinergy Corp. September 30, 2000, Form 10-Q.
3-c	Cinergy Corp.	By-Laws ofCinergy Corp., as amended on December 14, 2000.
3-d	CG&E(2)	Amended Articles of Incorporation ofCG&E effective October 23, 1996.	CG&E September 30, 1996, Form 10-Q.
3-e	CG&E	Regulations ofCG&E as amended, April 25, 1996.	CG&E March 31, 1996, Form 10-Q.
3-f	PSI(3)	Amended Articles of Consolidation ofPSI, as amended to April 20, 1995.	PSI June 30, 1995, Form 10-Q.
3-g	PSI	Amendment to Article D of the Amended Articles of Consolidation ofPSI, effective July 10, 1997.	Cinergy Corp. 1997 Form 10-K.
3-h	PSI	By-Laws ofPSI, as amended to December 17, 1996.	PSI March 31, 1997, Form 10-Q.
3-i	ULH&P(4)	Restated Articles of Incorporation made effective May 7, 1976.	ULH&P Form 8-K, May 1976.
3-j	ULH&P	By-Laws ofULH&P as amended, adopted May 8, 1996.	ULH&P March 31, 1996, Form 10-Q.
3-k	ULH&P	Amendment to Restated Articles of Incorporation ofULH&P (Article Third) and Amendment to the By-laws ofULH&P (Article 1), both effective July 24, 1997.	Cinergy Corp. 1997 Form 10-K.
Instruments defining the rights of holders, incl. Indentures
4-a	Cinergy Corp. PSI	Original Indenture (First Mortgage Bonds) dated September 1, 1939, betweenPSI and The First National Bank of Chicago, as Trustee, and LaSalle National Bank as Successor Trustee.	Exhibit A-Part 3 in File No. 70-258 Supplemental Indenture dated March 30, 1984.

4-b	Cinergy Corp. PSI	Twenty-fifth Supplemental Indenture betweenPSI and The First National Bank of Chicago dated September 1, 1978.	File No. 2-62543.
4-c	Cinergy Corp. PSI	Thirty-fifth Supplemental Indenture betweenPSI and The First National Bank of Chicago dated March 30, 1984.	PSI 1984 Form 10-K.
4-d	Cinergy Corp. PSI	Forty-second Supplemental Indenture betweenPSI and LaSalle National Bank dated August 1, 1988.	PSI 1988 Form 10-K.
4-e	Cinergy Corp. PSI	Forty-fourth Supplemental Indenture betweenPSI and LaSalle National Bank dated March 15, 1990.	PSI 1990 Form 10-K.
4-f	Cinergy Corp. PSI	Forty-fifth Supplemental Indenture betweenPSI and LaSalle National Bank dated March 15, 1990.	PSI 1990 Form 10-K.
4-g	Cinergy Corp. PSI	Forty-sixth Supplemental Indenture betweenPSI and LaSalle National Bank dated June 1, 1990.	PSI 1991 Form 10-K.
4-h	Cinergy Corp. PSI	Forty-seventh Supplemental Indenture betweenPSI and LaSalle National Bank dated July 15, 1991.	PSI 1991 Form 10-K.
4-i	Cinergy Corp. PSI	Forty-eighth Supplemental Indenture betweenPSI and LaSalle National Bank dated July 15, 1992.	PSI 1992 Form 10-K.
4-j	Cinergy Corp. PSI	Forty-ninth Supplemental Indenture betweenPSI and LaSalle National Bank dated February 15, 1993.	PSI 1992 Form 10-K.
4-k	Cinergy Corp. PSI	Fiftieth Supplemental Indenture betweenPSI and LaSalle National Bank dated February 15, 1993.	PSI 1992 Form 10-K.
4-l	Cinergy Corp. PSI	Fifty-first Supplemental Indenture betweenPSI and LaSalle National Bank dated February 1, 1994.	PSI 1993 Form 10-K.
4-m	Cinergy Corp. PSI	Fifty-second Supplemental Indenture betweenPSI and LaSalle National Bank, as Trustee, dated as of April 30, 1999.	PSI March 31, 1999, Form 10-Q.
4-n	Cinergy Corp. PSI	Indenture (Secured Medium-term Notes, Series A), dated July 15, 1991, betweenPSI and LaSalle National Bank, as Trustee.	PSI Form 10-K/A, Amendment No. 2, dated July 15, 1993.
4-o	Cinergy Corp. PSI	Indenture (Secured Medium-term Notes, Series B), dated July 15, 1992, betweenPSI and LaSalle National Bank, as Trustee.	PSI Form 10-K/A, Amendment No. 2, dated July 15, 1993.
4-p	Cinergy Corp. PSI	Loan Agreement betweenPSI and the City of Princeton, Indiana dated as of November 7, 1996.	PSI September 30, 1996, Form 10-Q.
4-q	Cinergy Corp. PSI	Loan Agreement betweenPSI and the City of Princeton, Indiana dated as of February 1, 1997.	Cinergy Corp. 1996 Form 10-K.
4-r	Cinergy Corp. PSI	Indenture dated November 15, 1996, betweenPSI and The Fifth Third Bank, as Trustee.	Cinergy Corp. 1996 Form 10-K.
4-s	Cinergy Corp. PSI	First Supplemental Indenture dated November 15, 1996, betweenPSI and The Fifth Third Bank, as Trustee.	Cinergy Corp. 1996 Form 10-K.
4-t	Cinergy Corp. PSI	Third Supplemental Indenture dated as of March 15, 1998, betweenPSI and The Fifth Third Bank, as Trustee.	Cinergy Corp. 1997 Form 10-K.
4-u	Cinergy Corp. PSI	Fourth Supplemental Indenture dated as of August 5, 1998, betweenPSI and The Fifth Third Bank, as Trustee.	PSI June 30, 1998, Form 10-Q.
4-v	Cinergy Corp. PSI	Fifth Supplemental Indenture dated as of December 15, 1998, betweenPSI and The Fifth Third Bank, as Trustee.	PSI 1998 Form 10-K.
4-w	Cinergy Corp. PSI	Sixth Supplemental Indenture betweenPSI and Fifth Third Bank, as Trustee, dated as of April 30, 1999.	PSI March 31, 1999, Form 10-Q.
4-x	Cinergy Corp. PSI	Seventh Supplemental Indenture dated as of October 20, 1999, betweenPSI and Fifth Third Bank as Trustee.	PSI September 30, 1999, Form 10-Q.
4-y	Cinergy Corp. PSI	Unsecured Promissory Note dated October 14, 1998, betweenPSI and the Rural Utilities Service.	PSI 1998 Form 10-K.
4-z	Cinergy Corp. PSI	Loan Agreement betweenPSI and the Indiana Development Finance Authority dated as of July 15, 1998.	PSI June 30, 1998, Form 10-Q.
4-aa	Cinergy Corp. PSI	Loan Agreement betweenPSI and the Indiana Development Finance Authority dated as of May 1, 2000.	PSI June 30, 2000, Form 10-Q.

4-bb	Cinergy Corp. CG&E	Original Indenture (First Mortgage Bonds) betweenCG&E and The Bank of New York (as Trustee) dated as of August 1, 1936.	CG&E Registration Statement No. 2-2374.
4-cc	Cinergy Corp. CG&E	Fourteenth Supplemental Indenture betweenCG&E and The Bank of New York dated as of November 2, 1972.	CG&E Registration Statement No. 2-60961.
4-dd	Cinergy Corp. CG&E	Thirty-third Supplemental Indenture betweenCG&E and The Bank of New York dated as of September 1, 1992.	CG&E Registration Statement No. 33-53578.
4-ee	Cinergy Corp. CG&E	Thirty-fourth Supplemental Indenture betweenCG&E and The Bank of New York dated as of October 1, 1993.	CG&E September 30, 1993, Form 10-Q.
4-ff	Cinergy Corp. CG&E	Thirty-fifth Supplemental Indenture betweenCG&E and The Bank of New York dated as of January 1, 1994.	CG&E Registration Statement No. 33-52335.
4-gg	Cinergy Corp. CG&E	Thirty-sixth Supplemental Indenture betweenCG&E and The Bank of New York dated as of February 15, 1994.	CG&E Registration Statement No. 33-52335.
4-hh	Cinergy Corp. CG&E	Thirty-seventh Supplemental Indenture betweenCG&E and The Bank of New York dated as of October 14, 1996.	Cinergy Corp. 1996 Form 10-K.
4-ii	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the County of Boone, Kentucky dated as of February 1, 1985.	CG&E 1984 Form 10-K.
4-jj	Cinergy Corp. CG&E	Repayment Agreement betweenCG&E and The Dayton Power and Light Company dated as of December 23, 1992.	CG&E 1992 Form 10-K.
4-kk	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the County of Boone, Kentucky dated as of January 1, 1994.	CG&E 1993 Form 10-K.
4-ll	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the State of Ohio Air Quality Development Authority dated as of December 1, 1985.	CG&E 1985 Form 10-K.
4-mm	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the State of Ohio Air Quality Development Authority dated as of September 13, 1995.	CG&E September 30, 1995, Form 10-Q.
4-nn	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the State of Ohio Water Development Authority dated as of January 1, 1994.	CG&E 1993 Form 10-K.
4-oo	Cinergy Corp. CG&E	Loan Agreement betweenCG&E and the State of Ohio Air Quality Development Authority dated as of January 1, 1994.	CG&E 1993 Form 10-K.
4-pp	Cinergy Corp. CG&E	Original Indenture (Unsecured Debt Securities) betweenCG&E and The Fifth Third Bank dated as of May 15, 1995.	CG&E Form 8-A dated July 24, 1995.
4-rr	Cinergy Corp. CG&E	First Supplemental Indenture betweenCG&E and The Fifth Third Bank dated as of June 1, 1995.	CG&E June 30, 1995, Form 10-Q.
4-ss	Cinergy Corp. CG&E	Second Supplemental Indenture betweenCG&E and The Fifth Third Bank dated as of June 30, 1995.	CG&E Form 8-A dated July 24, 1995.
4-tt	Cinergy Corp. CG&E	Third Supplemental Indenture betweenCG&E and The Fifth Third Bank dated as of October 9, 1997.	CG&E September 30, 1997, Form 10-Q.
4-uu	Cinergy Corp. CG&E	Fourth Supplemental Indenture betweenCG&E and The Fifth Third Bank dated as of April 1, 1998.	CG&E March 31, 1998, Form 10-Q.
4-vv	Cinergy Corp. CG&E	Fifth Supplemental Indenture betweenCG&E and The Fifth Third Bank dated as of June 9, 1998.	CG&E June 30, 1998, Form 10-Q.
4-ww	Cinergy Corp. CG&E ULH&P	Original Indenture (First Mortgage Bonds) betweenULH&P and The Bank of New York dated as of February 1, 1949.	ULH&P Registration Statement No. 2-7793.
4-xx	Cinergy Corp. CG&E ULH&P	Fifth Supplemental Indenture betweenULH&P and The Bank of New York dated as of January 1, 1967.	CG&E Registration Statement No. 2-60961.
4-yy	Cinergy Corp. CG&E ULH&P	Thirteenth Supplemental Indenture betweenULH&P and The Bank of New York dated as of August 1, 1992.	ULH&P 1992 Form 10-K.
4-zz	Cinergy Corp. CG&E ULH&P	Original Indenture (Unsecured Debt Securities) betweenULH&P and The Fifth Third Bank dated as of July 1, 1995.	ULH&P June 30, 1995, Form 10-Q.

Material contracts
4-aaa	Cinergy Corp. CG&E ULH&P	First Supplemental Indenture betweenULH&P and The Fifth Third Bank dated as of July 15, 1995.	ULH&P June 30, 1995, Form 10-Q.
4-bbb	Cinergy Corp. CG&E ULH&P	Second Supplemental Indenture betweenULH&P and The Fifth Third Bank dated as of April 30, 1998.	ULH&P March 31, 1998, Form 10-Q.
4-ccc	Cinergy Corp. CG&E ULH&P	Third Supplemental Indenture betweenULH&P and The Fifth Third Bank dated as of December 8, 1998.	ULH&P 1998 Form 10-K.
4-ddd	Cinergy Corp. CG&E ULH&P	Fourth Supplemental Indenture dated as of September 17, 1999, betweenULH&P and Fifth Third Bank as Trustee.	ULH&P September 30, 1999 Form 10-Q.
4-eee	Cinergy Corp.	Base Indenture dated as of October 15, 1998, between Cinergy Global Resources, Inc. (Global Resources) and The Fifth Third Bank as Trustee.	Cinergy Corp. September 30, 1998, Form 10-Q.
4-fff	Cinergy Corp.	First Supplemental Indenture dated as of October 15, 1998, between Global Resources and The Fifth Third Bank as Trustee.	Cinergy Corp. September 30, 1998, Form 10-Q.
4-ggg	Cinergy Corp.	Indenture dated as of December 16, 1998, betweenCinergy Corp. and The Fifth Third Bank.	Cinergy Corp. 1998 Form 10-K.
4-hhh	Cinergy Corp.	Indenture betweenCinergy Corp. and Fifth Third Bank, as Trustee, dated as of April 15, 1999.	Cinergy Corp. March 31, 1999, Form 10-Q.
4-iii	Cinergy Corp.	Rights Agreement betweenCinergy Corp. and The Fifth Third Bank, as Rights Agent.	Cinergy Corp. Registration Statement on Form 8-A dated October 16, 2000.
10-a	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated October 24, 1994, amongCG&E (an Ohio corporation),Cinergy Corp. (a Delaware corporation),PSI Resources, Inc., andPSI, and Jackson H. Randolph.	Cinergy Corp. 1994 Form 10-K.
10-b	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, among Services,CG&E, andPSI, and James E. Rogers.	Cinergy Corp. 1999 Form 10-K.
10-c	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, amongCinergy Corp., Services,CG&E, andPSI, and William J. Grealis.	Cinergy Corp. 1999 Form 10-K.
10-d	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, amongCinergy Corp., Services,CG&E, andPSI and Larry E. Thomas.	Cinergy Corp. 1999 Form 10-K.
10-e	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, amongCinergy Corp., Services,CG&E, andPSI, and Donald B. Ingle, Jr.	Cinergy Corp. 1999 Form 10-K.
10-f	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, amongCinergy Corp., Services,CG&E, andPSI, and Michael J. Cyrus.	Cinergy Corp. 1999 Form 10-K.
10-g	Cinergy Corp. CG&E PSI	Employment Agreement dated December 30, 1999 amongCinergy Corp., Services,CG&E, andPSI, and Jerome A. Vennemann.	Cinergy Corp. 1999 Form 10-K.
10-h	Cinergy Corp. CG&E PSI	Amended and Restated Employment Agreement dated December 30, 1999, amongCinergy Corp., Services,CG&E andPSI, and Charles J. Winger.	Cinergy Corp. 1999 Form 10-K.
10-i	Cinergy Corp. PSI	Deferred Compensation Agreement, effective as of January 1, 1992, betweenPSI and James E. Rogers.	PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993.
10-j	Cinergy Corp. PSI	Split Dollar Life Insurance Agreement, effective as of January 1, 1992, betweenPSI and James E. Rogers.	PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993.

10-k		Cinergy Corp. PSI	First Amendment to Split Dollar Life Insurance Agreement betweenPSI and James E. Rogers dated December 11, 1992.	PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993.
10-l		Cinergy Corp. CG&E	Deferred Compensation Agreement betweenCG&E and Jackson H. Randolph dated January 1, 1992.	CG&E 1992 Form 10-K.
10-m		Cinergy Corp. CG&E	Split Dollar Insurance Agreement, effective as of May 1, 1993, betweenCG&E and Jackson H. Randolph.	Cinergy Corp. 1994 Form 10-K.
10-n		Cinergy Corp. CG&E	Amended and Restated Supplemental Retirement Income Agreement betweenCG&E and Jackson H. Randolph.	Cinergy Corp. 1995 Form 10-K.
10-o		Cinergy Corp. CG&E	Amended and Restated Supplemental Executive Retirement Income Agreement betweenCG&E and certain executive officers.	Cinergy Corp. 1997 Form 10-K.
10-p		Cinergy Corp.	Cinergy Corp. Union Employees' 401(k) Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.	Cinergy Corp. 1999 Form 10-K.
10-q		Cinergy Corp.	Amendment toCinergy Corp. Union Employees' 401(k) Plan, adopted December 10, 1999, effective December 1, 1999.	Cinergy Corp. 1999 Form 10-K.
10-r		Cinergy Corp.	Cinergy Corp. Non-Union Employees' 401(k) Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.	Cinergy Corp. 1999 Form 10-K.
10-s		Cinergy Corp.	Amendment toCinergy Corp. Non-Union Employees' 401(k) Plan, adopted December 10, 1999, effective December 1, 1999.	Cinergy Corp. 1999 Form 10-K.
10-t		Cinergy Corp.	Cinergy Corp. Union Employees' Savings Incentive Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.	Cinergy Corp. 1999 Form 10-K.
10-u		Cinergy Corp.	Amendment toCinergy Corp. Union Employees' Savings Incentive Plan, effective December 1, 1999, adopted December 10, 1999.	Cinergy Corp. 1999 Form 10-K.
10-v		Cinergy Corp.	Cinergy Corp. Supplemental Executive Retirement Plan amended and restated effective January 1, 1999, adopted October 15, 1998.	Cinergy Corp. 1999 Form 10-K.
10-w		Cinergy Corp.	1997 Amendments to Various Compensation and Benefit Plans ofCinergy Corp., adopted January 30, 1997.	Cinergy Corp. 1997 Form 10-K.
10-x		Cinergy Corp.	Cinergy Corp. Stock Option Plan, adopted October 18, 1994, effective October 24, 1994.	Cinergy Corp. Form S-8, filed October 19, 1994.
10-y		Cinergy Corp.	Amendment toCinergy Corp. Stock Option Plan, amended October 22, 1996, effective November 1, 1996.	Cinergy Corp. September 30, 1996, Form 10-Q.
10-z		Cinergy Corp.	Cinergy Corp. Annual Incentive Plan, adopted October 18, 1994, effective October 24, 1994.	Cinergy Corp. 1994 Form 10-K.
10-aa		Cinergy Corp.	Amendment toCinergy Corp. Annual Incentive Plan, amended January 25, 1996, effective January 1, 1996.	Cinergy Corp. 1996 Form 10-K.
10-bb		Cinergy Corp.	Cinergy Corp. Employee Stock Purchase and Savings Plan, adopted October 18, 1994, effective October 24, 1994.	Cinergy Corp. Form S-8, filed October 19, 1994.
10-cc		Cinergy Corp.	Amendment toCinergy Corp. Employee Stock Purchase and Savings Plan, adopted April 26, 1996, effective January 1, 1996.	Cinergy Corp. June 30, 1996, Form 10-Q.
10-dd	��	Cinergy Corp.	Amendment toCinergy Corp. Employee Stock Purchase and Savings Plan, adopted October 22, 1996, effective November 1, 1996.	Cinergy Corp. September 30, 1996, Form 10-Q.
10-ee		Cinergy Corp.	Cinergy Corp. UK Sharesave Scheme, adopted and effective December 16, 1999.	Cinergy Corp. 1999 Form 10-K.
10-ff		Cinergy Corp.	Cinergy Corp. Directors' Deferred Compensation Plan, adopted October 18, 1994, effective October 24, 1994.	Cinergy Corp. Form S-8, filed October 19, 1994.
10-gg		Cinergy Corp.	Amendment toCinergy Corp. Directors' Deferred Compensation Plan, adopted October 22, 1996.	Cinergy Corp. September 30, 1996, Form 10-Q.
10-hh		Cinergy Corp.	Cinergy Corp. Retirement Plan for Directors, adopted October 18, 1994, effective October 24, 1994.	Cinergy Corp. 1994 Form 10-K.

Subsidiaries of the registrant
10-ii	Cinergy Corp.	Cinergy Corp. Retirement Plan for Directors, amended and restated effective January 1, 1999, adopted October 15, 1998.	Cinergy Corp. Schedule 14A Definitive Proxy Statement filed March 12, 1999.
10-jj	Cinergy Corp.	Cinergy Corp. Directors' Equity Compensation Plan adopted October 15, 1998, effective January 1, 1999.	Cinergy Corp. Schedule 14A Definitive Proxy Statement filed March 12, 1999.
10-kk	Cinergy Corp.	Cinergy Corp. Executive Supplemental Life Insurance Program adopted October 18, 1994, effective October 24, 1994, consisting of Defined Benefit Deferred Compensation Agreement, Executive Supplemental Life Insurance Program Split Dollar Agreement I, and Executive Supplemental Life Insurance Program Split Dollar Agreement II.	Cinergy Corp. 1994 Form 10-K.
10-ll	Cinergy Corp.	Cinergy Corp. 1996 Long-term Incentive Compensation Plan, adopted April 26, 1996.	Cinergy Corp. Schedule 14A Definitive Proxy Statement filed March 13, 1996.
10-mm	Cinergy Corp.	Amendment toCinergy Corp. 1996 Long-term Incentive Compensation Plan, adopted October 22, 1996, effective November 1, 1996.	Cinergy Corp. September 30, 1996, Form 10-Q.
10-nn	Cinergy Corp.	Cinergy Corp. 401(k) Excess Plan, effective January 1, 1997, adopted December 17, 1996.	Cinergy Corp. 1996 Form 10-K.
10-oo	Cinergy Corp.	Cinergy Corp. Nonqualified Deferred Incentive Compensation Plan, effective January 1, 1997, adopted December 17, 1996.	Cinergy Corp. 1996 Form 10-K.
10-pp	Cinergy Corp.	Cinergy Corp. Director, Officer and Key Employee Stock Purchase Program, effective January 7, 2000, adopted December 10, 1999.	Cinergy Corp. 1999 Form 10-K.
10-qq	Cinergy Corp.	Cinergy Corp. Non-Union Employees' Pension Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.	Cinergy Corp. 1999 Form 10-K.
10-rr	Cinergy Corp.	Cinergy Corp. Union Employees' Retirement Income Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.	Cinergy Corp. 1999 Form 10-K.
10-ss	Cinergy Corp. CG&E PSI	Employment Agreement dated February 12, 2001, amongCinergy Corp., Services,CG&E, andPSI, and R. Foster Duncan.
21	Cinergy Corp. CG&E PSI	Subsidiaries ofCinergy Corp.,CG&E, andPSI
Consent of experts and counsel
23	Cinergy Corp. CG&E PSI ULH&P	Consent of Independent Public Accountants
Power of attorney
24	Cinergy Corp. CG&E PSI ULH&P	Power of Attorney

(1): Cinergy Corp.in file number 1-11377
(2): CG&Ein file number 1-1232
(3): PSIin file number 1-3543
(4): ULH&Pin file number 2-7793
(5): Each registrant hereby undertakes to furnish to the Commission upon request a copy of any long-term debt instrument not listed above.

CINERGY CORP.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2000

(in thousands)

Col. A			Col. B		Col. C				Col. D				Col. E
					Additions				Deductions
Description			Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions Deducted from Applicable Assets
	Allowance for Doubtful Accounts
		2000	$	26,811	$	22,746	$	4,486	$	24,092	$	—	$	29,951
		1999	$	25,622	$	20,805	$	3,777	$	23,393	$	—	$	26,811
		1998	$	10,382	$	29,430	$	4,022	$	18,212	$	—	$	25,622

THE CINCINNATI GAS & ELECTRIC COMPANY

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2000

(in thousands)

Col. A			Col. B		Col. C				Col. D				Col. E
					Additions				Deductions
Description			Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions Deducted from Applicable Assets
	Allowance for Doubtful Accounts
		2000	$	16,740	$	14,056	$	4,486	$	16,238	$	—	$	19,044
		1999	$	17,607	$	9,754	$	4,017	$	14,638	$	—	$	16,740
		1998	$	9,199	$	16,131	$	4,021	$	11,744	$	—	$	17,607

PSI ENERGY, INC.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2000

(in thousands)

Col. A			Col. B		Col. C					Col. D				Col. E
					Additions					Deductions
Description			Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts			For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions Deducted from Applicable Assets
	Allowance for Doubtful Accounts
		2000	$	9,934	$	7,088	$	—		$	7,705	$	—	$	9,317
		1999	$	7,893	$	11,036	$	(240	)	$	8,755	$	—	$	9,934
		1998	$	1,183	$	13,178	$	—		$	6,468	$	—	$	7,893

THE UNION LIGHT, HEAT AND POWER COMPANY

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2000

(in thousands)

Col. A			Col. B		Col. C				Col. D				Col. E
					Additions				Deductions
Description			Balance at Beginning of Period		Charged to Expenses		Charged to Other Accounts		For Purposes for Which Reserves Were Created		Other		Balance at Close of Period
Accumulated Provisions Deducted from Applicable Assets
	Allowance for Doubtful Accounts
		2000	$	1,513	$	2,555	$	746	$	3,322	$	—	$	1,492
		1999	$	1,248	$	2,169	$	693	$	2,597	$	—	$	1,513
		1998	$	996	$	1,861	$	583	$	2,192	$	—	$	1,248

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company each duly has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CINERGY CORP.
THE CINCINNATI GAS & ELECTRIC COMPANY
PSI ENERGY, INC.
THE UNION LIGHT, HEAT AND POWER COMPANY
Registrants

Date: February 27, 2001
	By		/s/ JAMES E. ROGERS James E. Rogers Chairman

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the indicated registrants and in the capacities and on the dates indicated:

Signature		Title	Date
Cinergy
	Phillip R. Cox	Director
	George C. Juilfs	Director
	Thomas E. Petry	Director
	Jackson H. Randolph	Director
	Mary L. Schapiro	Director
	John J. Schiff, Jr.	Director
	Philip R. Sharp	Director
	Dudley S. Taft	Director
Cinergy and PSI
	James K. Baker	Director
	Michael G. Browning	Director
	John A. Hillenbrand II	Director
CG&E and ULH&P
	James L. Turner	Vice President and Director
CG&E
	J. Joseph Hale, Jr.	President and Director
PSI
	Vicky A. Bailey	President and Director
Cinergy, CG&E, PSI, and ULH&P
/s/ JAMES E. ROGERS James E. Rogers Attorney-in-fact for all the foregoing persons		Chairman, Chief Executive Officer, and Director President of Cinergy (Principal Executive Officer)	February 27, 2001
/s/ CHARLES J. WINGER Charles J. Winger		Vice President and Director of ULH&P (Principal Financial Officer)	February 27, 2001
/s/ BERNARD F. ROBERTS Bernard F. Roberts		Vice President and Comptroller (Principal Accounting Officer)	February 27, 2001

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	7th grade Avg

CINergy (CIN) Inactive 10-K2000 FY Annual report

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