UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2004

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

For the transition period from to

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

1-11377	CINERGY CORP. (A Delaware Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-1385023

1-1232	THE CINCINNATI GAS & ELECTRIC COMPANY (An Ohio Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-0240030

1-3543	PSI ENERGY, INC. (An Indiana Corporation) 1000 East Main Street Plainfield, Indiana 46168 (513) 421-9500	35-0594457

2-7793	THE UNION LIGHT, HEAT AND POWER COMPANY (A Kentucky Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500	31-0473080

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	%

PSI Energy, Inc.	Cumulative Preferred Stock	4.32	%
	Cumulative Preferred Stock	4.16	%
	Cumulative Preferred Stock	6-7/8	%

The Union Light, Heat and Power Company	None

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 ý No o

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. o

Requirements pursuant to Item 405 of Regulation S-K are not applicable for The 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.

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Cinergy Corp.	Yes	ý	No	o
The Cincinnati Gas & Electric Company	Yes	o	No	ý
PSI Energy, Inc.	Yes	o	No	ý
The Union Light, Heat and Power Company	Yes	o	No	ý

As of June 30, 2004, the aggregate market value of the common equity of Cinergy Corp. held by non-affiliates (shareholders who are not directors or executive officers) was $6.8 billion. All of the common stock of The Cincinnati Gas & Electric Company and PSI Energy, Inc. is owned by Cinergy Corp., and all of the common stock of The Union Light, Heat and Power Company is owned by The Cincinnati Gas & Electric Company. As of January 31, 2005, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares

Cinergy Corp.	Par value $.01 per share	191,404,406

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 of Cinergy Corp. and the Information Statement of PSI Energy, Inc. to be filed with the Securities and Exchange Commission in 2005 are incorporated by reference into Part III of this report.

This combined Form 10-K is separately filed by Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The 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
	Website Access to Reports
	Organization
	Business Segments
	Employees
	Environmental Matters
	Future Expectations/Trends
2	Properties
	Commercial Business Unit
	Regulated Business Unit
	Peak Load
3	Legal Proceedings
	Clean Air Act Lawsuit
	Carbon Dioxide Lawsuit
	Selective Catalytic Reduction Units at Gibson Generating Station
	Zimmer Generating Station
	Manufactured Gas Plant Sites
	Asbestos Claim Litigation
4	Submission of Matters to a Vote of Security Holders

	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
6	Selected Financial Data
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Executive Summary
	2004 Results of Operations - Cinergy
	2004 Results of Operations - CG&E
	2004 Results of Operations - PSI
	2004 Results of Operations - ULH&P
	2003 Results of Operations - Cinergy
	2003 Results of Operations - CG&E
	2003 Results of Operations - PSI
	Liquidity and Capital Resources
	Future Expectations/Trends
	Market Risk Sensitive Instruments
	Accounting Matters
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
9A	Controls and Procedures
9B	Other Information

	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 and Related Stockholder Matters
13	Certain Relationships and Related Transactions
14	Principal Accountant Fees and Services


	PART IV
15	Exhibits and Financial Statement Schedules
	Financial Statements and Schedules
	Exhibits
	Financial Statement Schedules
	Signatures

CAUTIONARY STATEMENTS

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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate”, “believe”, “intend”, “estimate”, “expect”, “continue”, “should”, “could”, “may”, “plan”, “project”, “predict”, “will”, and similar expressions.

Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

• Factors affecting operations, such as:

(1) unanticipated weather conditions;

(2) unscheduled generation outages;

(3) unusual maintenance or repairs;

(4) unanticipated changes in costs;

(5) environmental incidents; and

(6) electric transmission or gas pipeline system constraints.

• Legislative and regulatory initiatives and legal developments.

• Additional competition in electric or gas markets and continued industry consolidation.

• Financial or regulatory accounting principles including costs of compliance with existing and future environmental requirements.

• Changing market conditions and other factors related to physical energy and financial trading activities.

• 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.

• 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.

We undertake no obligation to update the information contained herein.

BUSINESS

PART I

ITEM 1. BUSINESS

WEBSITE ACCESS TO REPORTS

We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934 available free of charge on or through our internet website, www.cinergy.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC).

ORGANIZATION

Cinergy Corp., a Delaware corporation organized in 1993, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utilities. As a result of this ownership, we are considered a utility holding company. Because we are a holding company with material utility subsidiaries operating in multiple states, we are registered with and are subject to regulation by the SEC under the Public Utility Holding Company Act of 1935, as amended. Our other principal subsidiaries are Cinergy Services, Inc. (Services) and Cinergy Investments, Inc. (Investments).

CG&E, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through The Union Light, Heat and Power Company (ULH&P), in nearby areas of Kentucky. CG&E is responsible for the majority of our power marketing and trading activity. CG&E’s principal subsidiary, ULH&P, a Kentucky corporation organized in 1901, provides electric and gas service in northern Kentucky.

CG&E is in a market development period for residential customers and in the competitive retail electric market for non-residential customers, transitioning to deregulation of electric generation and a competitive retail electric service market in the state of Ohio. Applicable legislation governing the transition period provides for a market development (frozen rate) period that began January 1, 2001, ended December 31, 2004 for non-residential customers and is scheduled to end December 31, 2005 for residential customers. At the end of these market development periods, CG&E will not implement market rates, but rather a rate stabilization plan (RSP) approved by the Public Utilities Commission of Ohio (PUCO) that covers the period after the market development period through 2008. The RSP, among other things, increases rates for environmental costs and capacity reserves and provides for a fuel and emission allowance tracker through 2008. See “Electric Industry” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)” for the various filings that led to the PUCO’s approval of CG&E’s RSP, further details of the plan, and a discussion of key elements of Ohio deregulation.

PSI, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana.

The following table presents further information related to the operations of our domestic utility companies, CG&E, PSI, and ULH&P (our utility 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 • Electric commodity marketing and trading operations	Cincinnati, OH Middletown, OH Covington, KY Florence, KY Newport, KY	2,064,000



PSI	• Generation, transmission, distribution, and sale of electricity	Bloomington, IN Carmel, IN Columbus, IN Kokomo, IN Lafayette, IN New Albany, IN Terre Haute, IN	2,283,000

ULH&P(1)	• Transmission, distribution, and sale of electricity • Sale and transportation of natural gas	Covington, KY Florence, KY Newport, KY	345,000
ULH&P(1)		Covington, KY Florence, KY Newport, KY	345,000

(1) See “Generation — Fuel Supply and Emission Allowances” under the “Regulated” section for further discussion of the possible transfer of generation assets.

Services is a service company that provides our subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our non-regulated, energy-related businesses and investments, including natural gas marketing and trading operations (which are primarily conducted through Cinergy Marketing and Trading, LP (Marketing & Trading), one of its subsidiaries).

BUSINESS SEGMENTS

We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:

• Commercial Business Unit (Commercial);

• Regulated Business Unit (Regulated); and

• Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure).

The following section describes the activities of our business segments as of December 31, 2004.

See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for financial information by business segment.

Commercial

Commercial manages our wholesale generation and energy marketing and trading activities. Commercial’s wholesale generation consists of CG&E’s electric generation in Ohio due to Ohio’s transition to deregulation of electric generation and a competitive retail service market. See “Electric Industry” in “Item 7. MD&A” for further detail of key elements of Ohio deregulation. Commercial also performs energy risk management activities, provides

customized energy solutions and is responsible for all of our international operations. See the “Market Risk Sensitive Instruments” section of “Item 7. MD&A” for information on risks associated with these activities.

Detail of Commercial’s operations can be found in the following sections:

• Generation — Fuel Supply and Emission Allowances — Describes Commercial’s generation capacity, sources of fuel, and its various cost recovery mechanisms;

• Trading Operations and Risk Management — Describes Commercial’s energy marketing and trading activities in the United States and Canada;

• Competition — Describes the key competitors to Commercial’s various business operations;

• Energy Services — Describes Commercial’s operations consulting services and its operation of a synthetic fuel production facility;

• International — Describes Commercial’s operations outside of the United States; and

• Revenue Data and Customer Base — Describes the primary revenue generators for the various business operations of Commercial.

Generation — Fuel Supply and Emission Allowances

As of December 31, 2004, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Commercial’s domestic generating plants was 6,276 megawatts (MW). Approximately 67 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for further discussion of the generating facilities.

Each year CG&E purchases over 10 million tons of coal to generate electricity, primarily from mines located in Indiana, West Virginia, Ohio, Kentucky, Pennsylvania, Illinois, and Colorado. The price of coal has increased dramatically in 2004 as compared to 2003. Contributing to the rise in the price of coal are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has a general practice to procure a substantial portion of coal through fixed-price contracts of varying length. We hold fixed-price contracts that will source a substantial portion of our expected 2005 coal requirements. We evaluate the appropriate amount of contract coal and length of contracts based on market conditions, including pricing trends, volatility and supplier reliability. See “Contractual Cash Obligations” in “Item 7. MD&A” for further detail on CG&E’s total commitment under fixed-price coal contracts.

Commercial has natural gas-fired peaking plants that have a capacity of 1,766 MW. The fuel for these units is primarily obtained through the natural gas spot market as it is difficult to forecast the natural gas requirements for these plants. For further information on the risk of purchasing natural gas, see the “Market Risk Sensitive Instruments” section of “Item 7. MD&A”.

A joint operating agreement, effective in April 2002, allows Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E. Under this agreement, transfers of power between PSI and CG&E are generally priced at market rates.

Commercial monitors alternative sources of coal and natural gas to assure a continuing availability of economical fuel supplies. As such, it will maintain its practice of purchasing a portion of coal and natural gas requirements on the open market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements. Cinergy and CG&E believe that they can continue to obtain enough coal and natural gas to meet future needs. However, future environmental requirements may significantly impact the availability and price of these fuels.

At times, Commercial purchases power to meet the energy needs of its customers. Factors that could cause Commercial to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. We believe we can obtain enough purchased power to meet future needs. However, during periods of excessive demand, the price and availability of these purchases may be significantly impacted.

Commercial emits sulfur dioxide (SO₂) and nitrogen oxides (NO_X) in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with NO_X and SO₂ emission reduction requirements. In 2004, the market prices of SO₂ allowances rose more than 200 percent from 2003. Cinergy is continually evaluating market conditions and managing our overall cost structure through the addition of pollution control equipment, where economically feasible, and the use of emission allowance markets to help manage our emissions costs.

Under CG&E’s new RSP, retail fuel and emission allowance costs will be recovered through a cost tracking mechanism that recovers costs that exceed the amount originally included in the rates frozen in CG&E’s earlier transition plan. CG&E will recover retail fuel and emission allowance costs consumed in serving retail load and collect a Provider of Last Resort charge from non-residential customers from 2005 through 2008 and from residential customers from 2006 through 2008. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.

Trading Operations and Risk Management

Commercial’s energy marketing and trading activities principally consist of Marketing & Trading’s natural gas marketing and trading operations and CG&E’s power marketing and trading operations. In April 2002, CG&E and PSI executed a new joint operating agreement whereby new power marketing and trading contracts since April 2002 are originated on behalf of CG&E only. Historically, such contracts were executed on behalf of CG&E and PSI jointly.

Our domestic 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 United States), natural gas, and other energy-related products, including coal and emission allowances. Our natural gas domestic operations provide services that manage storage, transportation, gathering, and processing activities. In addition, our domestic operations also market and trade natural gas and other energy-related products on the New York Mercantile Exchange.

Marketing & Trading’s natural gas marketing and trading operations also extend to Canada where natural gas marketing and management services are provided to producers and industrial customers. Our Canadian operations also market and trade over-the-counter contracts.

See the “Market Risk Sensitive Instruments” section of “Item 7. MD&A” for information on risks associated with these activities.

Competition

Commercial competes for wholesale contracts for the purchase and sale of electricity and natural gas. Commercial’s main competitors include public utilities, power and natural gas marketers and traders, and independent power producers.

Energy Services

Commercial, through Cinergy Solutions Holding Company, Inc., is an on-site energy solutions and utility services provider. We provide utility systems construction, operation and maintenance of utility facilities, energy efficiencies and conservation consulting services, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.

Commercial, through Cinergy Capital & Trading, Inc., owns a coal-based synthetic fuel production facility which converts coal feedstock into synthetic fuel for sale to a third party. As of December 31, 2004, Cinergy has produced and sold approximately 7.8 million tons of synthetic fuel at this facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29 if certain requirements are satisfied. The three key requirements are that (a) the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel, (b) the fuel produced is sold to an unrelated entity

and (c) the fuel was produced from a facility that was placed in service before July 1, 1998. For further information on the tax credit qualifications see Note 11(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.

International

As of December 31, 2004, we had ownership interests in (1) generation assets located in three countries capable of producing approximately 150 MW of electricity and 700 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries, through which we serve approximately 8,500 transmission and distribution customers. These assets serve retail and wholesale customers by providing utility services including generation of electricity and heat as well as the distribution of gas and electric commodities.

Revenue Data and Customer Base

Commercial primarily recognizes revenues from generation provided to customers in CG&E’s service territory who have not switched to an alternative generation supplier under Ohio’s electric deregulation market. Because rates are frozen during the market development period in Ohio, the majority of these revenues are under a fixed-price tariff. Under the Ohio customer choice program, CG&E’s retail customers may choose their electric supplier. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:

			MW Hours For the		Switching
	MW at December 31		Years Ended December 31		Percentage at December 31(1)
Revenue Class	2004	2003	2004	2003	2004		2003

Residential	75	92	334,224	283,477	4.07	%	5.17	%
Commercial	339	374	1,722,822	1,654,061	19.17	%	21.55	%
Industrial	226	295	1,376,210	1,591,345	17.89	%	23.60	%
Other Public Authorities	89	91	284,214	265,039	19.09	%	19.95	%
Total	729	852	3,717,470	3,793,922

(1) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand.

Customer switching reduces retail revenues by the generation component of rates and shopping incentives. CG&E still collects transmission and distribution revenues from the delivery of electricity to switched customers (see Regulated section for further information). During the market development period, the reduction in revenues due to customer switching is mitigated by wholesale power sales from the freed-up generation capacity. For further discussion on Ohio deregulation and the recently approved RSP see “Electric Industry” in “Item 7. MD&A”.

Commercial’s operating revenue is also derived by providing electricity at wholesale and trading electricity primarily in the midwest region of the United States. In addition, Commercial provides and trades natural gas primarily to wholesale customers across the United States. The majority of these customers are public utilities, power and natural gas marketers and traders, and independent power producers.

Energy services operating revenues are derived primarily by providing steam, electricity, and operation and maintenance services to large industrial customers.

No single Commercial customer provides more than 10 percent of total operating revenues.

Regulated

Regulated consists of PSI’s regulated generation and transmission and distribution operations, and CG&E and its subsidiaries’ regulated electric and gas transmission and distribution systems. Regulated plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers. Regulated also earns revenues from wholesale customers primarily by these customers transmitting electric power

through Cinergy’s transmission system. These businesses are subject to cost of service rate making where rates to be charged to customers are based on prudently incurred costs over a test period plus a reasonable rate of return. Regulated operated approximately 48,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.5 million customers as of December 31, 2004. Regulated operated approximately 9,226 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 domestic regulated transmission and distribution services to approximately 500,000 customers as of December 31, 2004. See “Item 2. Properties” for a further discussion of the transmission and distribution systems owned by our utility operating companies.

Detail of Regulated’s operations can be found in the following sections:

• Generation - Fuel Supply and Emission Allowances — Describes Regulated’s generation capacity, sources of fuel, and its various cost recovery mechanisms;

• Transmission and Distribution — Describes Regulated’s agreements with the regional utilities and regional transmission organization (RTO) that coordinate the planning and operation of generation and transmission facilities and the associated cost recovery mechanisms;

• Gas Supply — Describes Regulated’s responsibility to purchase and deliver natural gas to native load (the total requirements of a wholesale utility’s franchised retail market) customers and the mechanisms used to fulfill their responsibility; and

• Revenue Data and Customer Base — Describes the primary revenue generators for the various business operations of Regulated.

Generation - Fuel Supply and Emission Allowances

As of December 31, 2004, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Regulated’s generating plants was 7,055 MW. Approximately 78 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for a further discussion of the generating facilities.

Each year PSI purchases over 15 million tons of coal to generate electricity, primarily from mines located in Indiana, Pennsylvania, and Illinois. The price of coal has increased dramatically in 2004 as compared to 2003. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has a general practice to procure a substantial portion of coal through fixed-price contracts of varying length. We hold fixed-price contracts that will source a substantial portion of our expected 2005 coal requirements. We evaluate the appropriate amount of contract coal and length of contracts based on market conditions, including pricing trends, volatility and supplier reliability. See “Contractual Cash Obligations” in “Item 7. MD&A” for further detail on PSI’s total commitment under fixed-price coal contracts.

Regulated has natural gas-fired peaking plants that have a capacity of 1,263 MW. The fuel for these units is primarily obtained through the natural gas spot market as it is difficult to forecast the natural gas requirements for these plants. For further information on the risk of purchasing natural gas see the “Market Risk Sensitive Instruments” section of “Item 7. MD&A”.

At times, Regulated purchases power to meet the energy needs of its customers. Factors that could cause Regulated to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. We believe we can obtain enough purchased power to meet future needs. However, during periods of excessive demand, the price and availability of these purchases may be significantly impacted.

ULH&P purchases energy from CG&E pursuant to a contract effective January 1, 2002, which was approved by the Federal Energy Regulatory Commission (FERC) and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed-rate contract with CG&E.

The KPSC has conditionally approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E as previously discussed. Under this new plan, CG&E will transfer ownership of approximately 1,100 MW of electric generating capacity to ULH&P. The capacity is currently part of CG&E’s generating assets used to service ULH&P under a multi-year wholesale power supply contract as previously discussed. ULH&P is currently seeking approval of the transaction from the SEC, wherein the Ohio Consumers Counsel has intervened in opposition, and the FERC. The transfer, which will be paid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through December 31, 2006. Assuming receipt of regulatory approvals, we would anticipate the transfer to take place in the second quarter of 2005.

Cinergy is studying the feasibility of constructing a commercial integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would own all or part of the facility and operate it. Cinergy will partner with Bechtel Corporation and General Electric Company to complete this study. An IGCC plant turns coal to gas, removing most of the SO₂ and other emissions before the gas is used to fuel a combustion turbine generator. The technology uses less water and has fewer emissions than a conventional coal-fired plant with currently required pollution control equipment. Another benefit is the potential to remove mercury and carbon dioxide (CO₂) upstream of the combustion process at a lower cost than conventional plants. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the Indiana Utility Regulatory Commission (IURC) to begin construction. If approved, we would anticipate the IURC’s subsequent approval to include the assets in PSI’s rate base.

Regulated monitors alternative sources of coal and natural gas to assure a continuing availability of economical fuel supplies. As such, it will maintain its practice of purchasing a portion of coal and natural gas requirements on the open market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements. Cinergy and PSI believe that they can continue to obtain enough coal and natural gas to meet future needs. However, future environmental requirements may significantly impact the availability and price of these fuels.

PSI recovers retail and a portion of its wholesale fuel costs from customers on a dollar-for-dollar basis through a cost tracking recovery mechanism (commonly referred to as a fuel adjustment clause). In addition to the fuel adjustment clause, PSI utilizes a purchased power tracking mechanism approved by the IURC for the recovery of costs related to certain specified purchases of power necessary to meet native load peak demand requirements to the extent such costs are not recovered through the existing fuel adjustment clause.

Regulated emits SO₂ and NO_X in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with NO_X and SO₂ emission reduction requirements. In 2004, the market prices of SO₂ allowances rose more than 200 percent from 2003. PSI utilizes a cost tracking mechanism as approved by the IURC allowing it to recover substantially all of its emission allowance costs from its customers. Cinergy is continually evaluating market conditions and managing our overall cost structure through the addition of pollution control equipment, where economically feasible, and the use of emission allowance markets to help manage our emissions costs.

Transmission and Distribution

Cinergy (through our utility operating companies) and other non-affiliated utilities in a nine-state region are parties to the East Central Area Reliability Coordination (ECAR) Agreement. Through the ECAR Agreement, ECAR supports the planning and operation of generation and transmission facilities, which provides for reliability of regional bulk power supply.

Cinergy (through our utility operating companies) is also a member of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a RTO established in 1998 as a non-profit organization which maintains functional control over the combined transmission systems of its members.

The Midwest ISO is the provider for transmission service requested on the transmission facilities under its tariff. It is responsible for the reliable operation of those transmission facilities and the regional planning of new

transmission facilities. The Midwest ISO also will administer energy markets utilizing Locational Marginal Pricing (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses) as the methodology for relieving congestion on the transmission facilities under its functional control. ECAR will maintain the responsibility for establishing the level of operating reserves for those utilities participating in the ECAR Agreement and the operation of the Automatic Reserve Sharing system upon the Midwest ISO’s implementation of its Energy Markets Tariff. See “Electric Industry” in “Item 7. MD&A” for further detail regarding the Midwest ISO energy markets.

Transmission and Distribution Cost Recovery

Transmission cost recovery mechanisms will be established under CG&E’s new RSP to, among other things, permit CG&E to recover Midwest ISO charges. CG&E also plans to file a distribution rate case to recover certain distribution costs with rates to become effective January 1, 2006 and has deferred certain costs in 2004 and will defer costs in 2005 pursuant to its RSP. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.

PSI has received IURC approval for the recovery of Midwest ISO costs and is currently seeking IURC approval that would further define the mechanisms for recovery of such costs.

Transmission System Interconnections

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

Gas Supply

Regulated is responsible for the purchase and the subsequent delivery of natural gas to native load customers. Regulated’s natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows Regulated to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides Regulated the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under Regulated’s customer choice/gas transportation programs. In 2004, firm supply purchase commitment agreements provided approximately 63 percent of the natural gas supply, with the remaining gas 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 due primarily to changing weather conditions.

Regulated manages natural gas procurement-price volatility mitigation programs for CG&E and ULH&P. These programs pre-arrange between 20-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements. CG&E and ULH&P use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2004, CG&E and ULH&P, combined, had hedged approximately 60 percent of their winter 2004/2005 base load requirements. See the “Gas Industry” section of “Item 7. MD&A” 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.

Revenue Data and Customer Base

Regulated’s generation revenue is derived from the fulfillment of its native load requirements. The percent of retail operating revenues derived from full service electricity and gas sales and transportation for each of the three years ended December 31 were as follows:

	Operating Revenues
Registrant	2004				2003				2002
	Electric		Gas		Electric		Gas		Electric		Gas

Cinergy	76	%	24	%	76	%	24	%	81	%	19	%
CG&E and subsidiaries	45		55		46		54		56		44
PSI	100		—		100		—		100		—
ULH&P	65		35		67		33		74		26

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 electricity and gas demand.

The service territory of CG&E and its utility subsidiaries, including ULH&P, is heavily populated and is characterized by a stable residential customer base and a diverse mix of industrial customers. The territory served by PSI is composed of residential, agricultural, and widely diversified industrial customers. No single retail customer provides more than 10 percent of total operating revenues (electric or gas) for Regulated.

Power Technology and Infrastructure

Power Technology and Infrastructure primarily manages Cinergy Ventures, LLC (Ventures), Cinergy’s venture capital subsidiary. Ventures identifies, invests in, and integrates new energy technologies into Cinergy’s existing businesses, focused primarily on operational efficiencies and clean energy technologies. In addition, Power

Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers.

In March 2004, Cinergy announced that it would begin offering broadband over power line (BPL) services in the Cincinnati, Ohio area. BPL utilizes the low and medium voltage distribution lines of Cinergy to transmit high speed data and other digital information to and from the internet via home electrical outlets and can be used for monitoring utility infrastructure. These services are being offered through joint ventures created by Ventures and Current Communications Group LLC, marketing to Cinergy service territory and municipal and co-op utilities throughout the United States. Ventures has invested approximately $18 million to date.

EMPLOYEES

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

The following table indicates the number of employees by classification at January 31, 2005:

Classification	CG&E(4)	PSI	ULH&P	Cinergy(5)

IBEW(1)	1,018	1,218	60	2,546
USWA(2)	280	—	79	398
UWUA(3)	387	—	58	768
Various Union Organizations	—	—	—	355
Non-Bargaining	198	354	19	3,775
	1,883	1,572	216	7,842

(1) IBEW #1347 contract will expire on April 1, 2006, IBEW #1393 contract will expire on May 1, 2005, and IBEW #352 contract expired on February 5, 2005 and was replaced with a new contract set to expire on February 5, 2008.

(2) USWA #12049 and #5541-06 contracts will expire on May 15, 2007.

(3) Contract will expire on March 31, 2005.

(4) CG&E and subsidiaries excluding ULH&P.

(5) Includes 3,154 Services’ employees who provide services to our operating utilities and other non-regulated companies.

ENVIRONMENTAL MATTERS

Cinergy is currently affected by several different issues which involve compliance with federal and state regulations regarding the protection of the environment including, but not limited to, reductions in mercury, NO_X, and SO₂ emissions. Cinergy is able to recover certain costs of this environmental compliance equipment through various trackers set up with Cinergy’s respective state regulatory agencies. See the “Environmental Issues” section in “Item 7. MD&A” for a discussion of these environmental issues and the estimated capital expenditures.

FUTURE EXPECTATIONS/TRENDS

See the information appearing under the same caption in “Item 7. MD&A” for the following discussions:

• Regulatory Outlook and Significant Rate Developments;

• FERC and Midwest ISO;

• Gas Industry; and

• Other Matters.

PROPERTIES

ITEM 2. PROPERTIES

COMMERCIAL BUSINESS UNIT (COMMERCIAL)

Electric

Domestic Power Generation

Commercial’s domestic power generating stations’ total winter electric capacity, reflected in megawatts (MW), as of December 31, 2004, are shown in the table that follows. Commercial’s electric generating plants are primarily located in Ohio and Kentucky and are wholly-owned or jointly-owned facilities.

			Natural
		Coal	Gas	Oil	Total
Commercial(1)	Stations	MW	MW	MW	MW

The Cincinnati Gas & Electric Company (CG&E)	9	4,186	736	324	5,246
Cinergy Investments, Inc. (Investments)(2)	2	—	1,030	—	1,030

Total	11	4,186	1,766	324	6,276

(1) This table includes only our portion of the total capacity for the jointly-owned plants.

(2) Represents natural gas peaking plants located in Tennessee and Mississippi, owned by Investments, that sell electricity on the wholesale market.

During 2004, Commercial’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 68 percent and a utilization factor of 83 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 84 percent. A capacity factor is a percentage that indicates how much of a power plant’s capacity is used over time. A utilization factor is a percentage that indicates how much of a power plant’s capacity is used while being available. An equivalent availability factor is a percentage that indicates how much of a unit is available to generate compared to its potential maximum generation.

Below is a geographical map showing the locations of Commercial’s generation plants.

Legend
Number	Generation Plant	Fuel Type	MW Capacity

1	Dick’s Creek	Gas	172
2	Woodsdale	Gas	564
3	Miami Fort	Coal/Oil	962
4	East Bend	Coal	414
5	Beckjord	Coal/Oil	1,107
6	Wm. Zimmer	Coal	604
7	J.M. Stuart	Coal	913
8	Killen	Coal	198
9	Conesville	Coal	312
10	Brownsville	Gas	480
	Caledonia(1)	Gas	550
		Total	6,276

(1) Commercial’s generation plant not included in the map is located in Caledonia, Mississippi.

Cogeneration

As of December 31, 2004, Cinergy had ownership interests in and/or operated 27 domestic cogeneration facilities capable of producing 5,357 MW of electricity, 4,303 MW equivalents of steam and 236 MW equivalents of chilled water. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source. During 2005, Cinergy anticipates completion of an expansion at one of our existing cogeneration facilities, which is expected to provide an additional 70 MW equivalents of steam and 42 MW equivalents of chilled water.

Synthetic Fuel

Cinergy Capital & Trading, Inc. owns a coal-based synthetic fuel production facility, which converts coal into synthetic fuel for sale to a third party. See “Synthetic Fuel Production” in “Item 7. MD&A” for additional information regarding this business initiative.

International

REGULATED BUSINESS UNIT (REGULATED)

Electric

Domestic Power Generation

Regulated’s domestic power generating stations’ total winter electric capacity, reflected in MW, as of December 31, 2004, are shown in the table that follows. The electric generating plants are located in Indiana and Ohio and are wholly-owned or jointly-owned facilities.

Natural

Coal

Gas

Oil

Hydro

Total

Regulated(1)

Stations

PSI

5,488

1,263

259

7,055

(1) This table includes only our portion of the total capacity for the jointly-owned plants.

During 2004, Regulated’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 74 percent and a utilization factor of 85 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 89 percent. A capacity factor is a percentage that indicates how much of a power plant’s capacity is used over time. A utilization factor is a percentage that indicates how much of a power plant’s capacity is used while being available. An equivalent availability factor is a percentage that indicates how much of a unit is available to generate compared to its potential maximum generation.

Below is a geographical map showing the locations of Regulated’s generation plants.

Legend
Number	Generation Plant	Fuel Type	MW Capacity

1	Cayuga	Coal/Gas/Oil	1,135
2	Wabash River	Coal/Oil	966
3	Edwardsport	Coal/Oil	160
4	Gibson	Coal	2,844
5	Miami Wabash	Oil	104
6	Noblesville	Gas	310
7	Henry County	Gas	129
8	Connersville	Oil	98
9	Gallagher	Coal	560
10	Markland	Hydro	45
11	Madison	Gas	704
		Total	7,055

Transmission and Distribution

Relevant information for our utility operating companies’ electric transmission and distribution systems located in Ohio, Kentucky, and Indiana is as follows:

	Electric	Electric	Substation
	Transmission	Distribution	Combined
Registrant	Systems	Systems	Capacity
	(circuit miles)	(circuit miles)	(kilovolt-amperes)(1)

CG&E and subsidiaries
CG&E	1,561	16,743	21,121,288
The Union Light, Heat and Power Company (ULH&P)	106	2,883	1,419,878
Other subsidiaries	40	—	—
Total CG&E and subsidiaries	1,707	19,626	22,541,166
PSI Energy, Inc. (PSI)	5,354	20,917	30,569,289

Total	7,061	40,543	53,110,455

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

At the end of 2004, our utility operating companies’ electric systems were interconnected with 14 other utilities. 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 the 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. The Midwest Independent Transmission System Operator, Inc. (Midwest ISO) holds functional control of Regulated’s transmission systems.

Gas

As of December 31, 2004, the natural gas transmission and distribution systems of Cinergy and CG&E and its subsidiaries had approximately 9,226 miles of mains and service lines located in southwestern Ohio and northern Kentucky. Cinergy and CG&E and its subsidiaries also jointly own three underground caverns with a total storage capacity of approximately 23 million gallons of liquid propane (of which 18.7 million gallons belongs to CG&E, including 7.5 million gallons belonging to ULH&P). As of December 31, 2004, Cinergy had 16.6 million gallons of liquid propane in storage (of which 14.4 million gallons belongs to CG&E, including 5.8 million gallons belonging to ULH&P). This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants store propane and, when needed, vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

PEAK LOAD

In July 2004, we experienced peak loads for the year of 10,911 MW, 4,998 MW, and 6,000 MW for Cinergy, CG&E, and PSI, respectively. Cinergy and CG&E set record peak loads of 11,305 MW and 5,311 MW in August 2002, respectively, while PSI set a record peak load of 6,088 MW in July 2002.

LEGAL PROCEEDINGS

ITEM 3. LEGAL PROCEEDINGS

CLEAN AIR ACT (CAA) LAWSUIT

In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana (District Court) against Cinergy, CG&E, and PSI alleging various violations of the CAA. Specifically, the lawsuit alleges that we violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review (NSR), and Ohio and Indiana State Implementation Plans (SIP) permits for various projects at our owned and co-owned generating stations. Additionally, the suit claims that we violated an Administrative Consent Order entered into in 1998 between the Environmental Protection Agency (EPA) and Cinergy relating to alleged violations of Ohio’s SIP provisions governing particulate matter at Unit 1 at CG&E’s W.C. Beckjord Generating Station (Beckjord Station). The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s Beckjord Station and Miami Fort Station, and PSI’s Cayuga Generating Station, Gallagher Generating Station, Wabash River Generating Station, and Gibson Generating Station (Gibson Station), and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. The case is currently in discovery, and the District Court has set the case for trial by jury commencing in February 2006.

In March 2000, the United States also filed in the District Court an amended complaint in a separate lawsuit alleging violations of the CAA relating to PSD, NSR, and Ohio SIP requirements regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and CG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. In April 2001, the District Court in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision.

In addition, Cinergy and CG&E have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of PSD, NSR, and Ohio SIP requirements at a generating station operated by DP&L and jointly-owned by CG&E. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against Cinergy, DP&L and CSP for alleged violations of the CAA at this same generating station.

We are unable to predict whether resolution of these matters would have a material effect on our financial position or results of operations. We intend to vigorously defend against these allegations.

CARBON DIOXIDE (CO₂) LAWSUIT

In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. That same day, a similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO₂ from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO₂. Plaintiffs are seeking an injunction requiring each defendant to cap its CO₂emissions and then reduce them by a specified percentage each year for at least a decade. Cinergy intends to defend these lawsuits vigorously in court and filed motions to dismiss with the other defendants in September 2004. We are not able to predict whether resolution of these matters would have a material effect on our financial position or results of operations.

SELECTIVE CATALYTIC REDUCTION UNITS (SCR) AT GIBSON GENERATING STATION

In May 2004, SCRs and other pollution control equipment became operational at Units 4 and 5 of PSI’s Gibson Station in accordance with compliance deadlines under the NO_X SIP Call. In June and July 2004, Gibson Station temporarily shut down the equipment on these units due to a concern over an acid aerosol mist haze (plume) sometimes occurring in areas near the plant. Portions of the plume from those units’ stacks appeared to break apart and descend to ground level at certain times under certain weather conditions. As a result, and, working with the City of Mt. Carmel, Illinois, Illinois EPA, Indiana Department of Environmental Management (IDEM), EPA, and the State of Illinois, we developed a protocol regarding the use of the SCRs while we explored alternatives to address this issue. After the protocol was finalized, the Illinois Attorney General brought an action in Wabash County Circuit Court against PSI seeking a preliminary injunction to enforce the protocol. In August 2004, the court granted that preliminary injunction. PSI is appealing that decision to the Fifth District Appellate Court, but we cannot predict the ultimate outcome of that appeal or of the underlying action by the Illinois Attorney General.

We will seek recovery of any related capital as well as increased emission allowance expenditures through the regulatory process. We do not believe costs related to resolving this matter will have a material impact on our financial position or results of operations.

ZIMMER GENERATING STATION (ZIMMER STATION) LAWSUIT

In November 2004, a citizen of the Village of Moscow, Ohio, the town adjacent to CG&E’s Zimmer Station, brought a purported class action in the United States District Court for the Southern District of Ohio seeking monetary damages and injunctive relief against CG&E for alleged violations of the CAA, the Ohio SIP, Ohio laws against nuisance and common law nuisance. CG&E filed a motion to dismiss the lawsuit on primarily procedural grounds and we intend to defend against these claims vigorously. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or result of operations.

MANUFACTURED GAS PLANT (MGP) SITES

Coal tar residues, related hydrocarbons, and various metals have been found in at least 22 sites that PSI or its predecessors previously owned and sold in a series of transactions with Northern Indiana Public Service Company (NIPSCO) and Indiana Gas Company, Inc. (IGC). The 22 sites are in the process of being studied and will be remediated, if necessary. In 1998 NIPSCO, IGC, and PSI entered into Site Participation and Cost Sharing Agreements to allocate liability and responsibilities between them. The IDEM oversees investigation and cleanup of all of these sites. Thus far, PSI has primary responsibility for investigating, monitoring and, if necessary, remediating nine of these sites. In December 2003, PSI entered into a voluntary remediation plan with the state of Indiana, providing a formal framework for the investigation and cleanup of the sites.

In April 1998, PSI filed suit in Hendricks County in the state of Indiana against its general liability insurance carriers. PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites; or (2) pay PSI’s cost of defense. The trial court issued a variety of rulings with respect to the claims and defenses in the litigation. PSI appealed certain adverse rulings to the Indiana Court of Appeals and the appellate court remanded the case to the trial court. PSI settled its claims with all but one of the insurance carriers in January 2005 prior to commencement of the trial. With respect to the lone insurance carrier, a jury returned a verdict against PSI in February 2005. PSI is considering whether to appeal this decision. At the present time, PSI cannot predict the outcome of this litigation if it were to appeal the decision.

PSI has accrued costs related to investigation, remediation, and groundwater monitoring for those sites where such costs are probable and can be reasonably estimated. We will continue to investigate and remediate the sites as outlined in the voluntary remediation plan. As additional facts become known and investigation is completed, we will assess whether the likelihood of incurring additional costs becomes probable. Until all investigation and remediation is complete, we are unable to determine the overall impact on our financial position or results of operations.

CG&E and ULH&P have performed site assessments on certain of their sites where we believe MGP activities have occurred at some point in the past and have found no imminent risk to the environment. At the present time,

CG&E and ULH&P cannot predict whether investigation and/or remediation will be required in the future at any of these sites.

ASBESTOS CLAIM LITIGATION

CG&E and PSI have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 100 pending lawsuits. In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work at the CG&E and PSI generating stations. The plaintiffs further claim that as the property owner of the generating stations, CG&E and PSI should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. A majority of the lawsuits to date have been brought against PSI. The impact on CG&E’s and PSI’s financial position or results of operations of these cases to date has not been material.

Of these lawsuits, one case filed against PSI has been tried to verdict. The jury returned a verdict against PSI in the amount of approximately $500,000 on a negligence claim and a verdict for PSI on punitive damages. PSI received an adverse ruling in its initial appeal of the negligence claim verdict, but the Indiana Supreme Court accepted the transfer of the case and heard oral argument in June 2004. In addition, PSI has settled a number of other lawsuits for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations.

At this time, CG&E and PSI are not able to predict the ultimate outcome of these lawsuits or the impact on CG&E’s and PSI’s financial position or results of operations.

We currently, and from time to time, are involved in lawsuits, claims, and complaints incidental to the conduct of our business. In the opinion of management, no such proceeding is likely to have a material adverse effect on us.

See Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information regarding our commitments and contingencies.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

No matters were submitted to a vote of security holders of Cinergy, The Cincinnati Gas & Electric Company, or PSI Energy, Inc. during the fourth quarter of 2004.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

PART II

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
2004
First Quarter	$	41.10	$	37.17
Second Quarter	41.04		34.92
Third Quarter	40.75		36.95
Fourth Quarter	42.63		38.08

2003
First Quarter	$	35.87	$	29.77
Second Quarter	38.75		33.25
Third Quarter	36.99		33.14
Fourth Quarter	38.86		35.19

Cinergy Corp. holds all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), and CG&E holds all of the common stock of The Union Light, Heat and Power Company (ULH&P). Therefore, no public trading market exists for the common stock of CG&E, PSI, and ULH&P.

As of January 31, 2005, Cinergy Corp. had 45,628 shareholders of record.

Cinergy Corp. declared dividends on its common stock of $.47 and $.46 per share for each quarter of 2004 and 2003, respectively. The quarterly dividends paid to Cinergy Corp. by CG&E and PSI, and to CG&E by ULH&P for the past two years were as follows:

Registrant	Quarter	2004		2003
		(in thousands)

CG&E	First	$	54,926	$	47,082
	Second	55,612		63,100
	Third	57,971		56,473
	Fourth	67,249		61,208

PSI	First	$	28,957	$	30,503
	Second	28,913		17,837
	Third	26,839		24,984
	Fourth	17,879		20,626

ULH&P	First	$	—	$	—
	Second	—		6,305
	Third	—		—
	Fourth	14,600		—

On January 14, 2005, the Board of Directors of Cinergy Corp. declared dividends on its common stock of $.48 per share, payable February 15, 2005, to shareholders of record at the close of business on February 1, 2005.

See “Dividend Restrictions” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a brief description of the registrants’ common stock dividend restrictions.

The number of shares (or units) provided in the table below represent shares exchanged in connection with employee option exercises and shares purchased by the plan trustee on behalf of the 401(k) Excess Plan.

Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs

October 1 — October 31	4,580	$	39.67	N/A	N/A
November 1 — November 30	2,288	$	39.45	N/A	N/A
December 1 — December 31	—	$	—	N/A	N/A

SELECTED FINANCIAL DATA

ITEM 6. SELECTED FINANCIAL DATA

	2004		2003			2002			2001			2000
	(in millions, except per share amounts)

Cinergy(1)
Results of Operations:
Operating revenues	$	4,688	$	4,416		$	4,059		$	3,950		$	3,752
Income before discontinued operations and cumulative effect of changes in accounting principles	401		435			397			457			400
Discontinued operations, net of tax(2)	—		9			(25		)	(15		)	(1		)
Cumulative effect of changes in accounting principles, net of tax(3)	—		26			(11		)	—			—
Net income	401		470			361			442			399

Per Share Data:
Earnings per common share (EPS) - basic:
Income before discontinued operations and cumulative effect of changes in accounting principles	2.22		2.46			2.37			2.87			2.52
Discontinued operations, net of tax(2)	—		0.05			(0.15		)	(0.09		)	(0.01		)
Cumulative effect of changes in accounting principles, net of tax(3)	—		0.15			(0.06		)	—			—
Net income	2.22		2.66			2.16			2.78			2.51
EPS - diluted:
Income before discontinued operations and cumulative effect of changes in accounting principles	2.18		2.43			2.34			2.84			2.51
Discontinued operations, net of tax(2)	—		0.05			(0.15		)	(0.09		)	(0.01		)
Cumulative effect of changes in accounting principles, net of tax(3)	—		0.15			(0.06		)	—			—
Net income	2.18		2.63			2.13			2.75			2.50
Cash dividends declared per share	1.88		1.84			1.80			1.80			1.80

Balance Sheet Data (at end of period):
Total assets from continuing operations	14,982		14,114			13,685			12,558			12,604
Total assets from discontinued operations	—		5			147			234			197
	14,982		14,119			13,832			12,792			12,801
Long-term debt (including amounts due within one year)	4,448		4,971			4,188			3,656			2,868

The Cincinnati Gas & Electric Company (CG&E)
Results of Operations:
Operating revenues	$	2,511	$	2,382		$	2,137		$	2,247		$	2,101
Income before cumulative effect of changes in accounting principles	257		300			264			327			267
Cumulative effect of changes in accounting principles, net of tax(4)	—		31			—			—			—
Net income	257		331			264			327			267

Balance Sheet Data (at end of period):
Total assets	6,232		5,809			5,751			5,559			6,182
Long-term debt (including amounts due within one year)	1,594		1,569			1,690			1,205			1,206

PSI Energy, Inc. (PSI)
Results of Operations:
Operating revenues	$	1,754	$	1,603		$	1,611		$	1,574		$	1,512
Income before cumulative effect of a change in accounting principle	165		134			214			162			135
Cumulative effect of a change in accounting principle, net of tax(5)	—		(1		)	—			—			—
Net income	165		133			214			162			135

Balance Sheet Data (at end of period):
Total assets	5,450		5,140			4,539			4,864			4,906
Long-term debt (including amounts due within one year)	1,874		1,720			1,372			1,348			1,113

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

(2) See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further explanation.

(3) In 2003, Cinergy recognized a gain/(loss) on cumulative effect of changes in accounting principles of $39 million (net of tax) and $(13) million (net of tax) as a result of the reversal of accrued cost of removal for non-regulated generating assets and the change in accounting of certain energy related contracts from fair value to accrual. In 2002, Cinergy recognized a cumulative effect of a change in accounting principle of $(11) million (net of tax) as a result of an impairment charge for goodwill related to certain of our international assets.

(4) In 2003, CG&E recognized a gain/(loss) on cumulative effect of changes in accounting principles of $39 million (net of tax) and $(8) million (net of tax) as a result of the reversal of accrued cost of removal for non-regulated generating assets and the change in accounting of certain energy related contracts from fair value to accrual.

(5) In 2003, PSI recognized a loss on cumulative effect of a change in accounting principle of $(1) million (net of tax) as a result of a change in accounting of certain energy related contracts from fair value to accrual.

MD&A - EXECUTIVE SUMMARY

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

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

The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this report. We have reclassified certain prior-year amounts in the financial statements of Cinergy, The Cincinnati Gas & Electric Company (CG&E), PSI Energy, Inc. (PSI), and The Union Light, Heat and Power Company (ULH&P) to conform to current presentation. The following discussions of results are not necessarily indicative of the results to be expected in any future period.

EXECUTIVE SUMMARY

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), we explain our general operating environment, as well as our results of operations, liquidity, capital resources, future expectations/trends, market risk sensitive instruments, and accounting matters. Specifically, we discuss the following:

• factors affecting current and future operations;

• why results changed from period to period;

• potential sources of cash for future capital expenditures; and

• how these items affect our overall financial condition.

Financial Highlights

Net income for Cinergy for the years ended December 31, 2004, and 2003 was as follows:

	Cinergy
	2004		2003		Change			% Change
	(in millions)

Net income	$	401	$	470	$	(69	)	(15	)%

The decrease in net income was primarily due to the following factors:

• Higher operating costs due, in part, to increases in costs for employee labor and benefits, production maintenance, and the implementation of a continuous improvement initiative;

• Lower margins from the sale of electricity in the Commercial Business Unit (Commercial) primarily due to higher fuel and emission allowance costs;

• Impairment and disposal charges on certain investments primarily in the Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure); and

• Net gains recognized in 2003 resulting from the implementation of certain accounting changes and the disposal of discontinued operations.

These decreases were partially offset by:

• A higher price received per megawatt hour (MWh) resulting from the Indiana Utility Regulatory Commission’s (IURC) approval of PSI’s base retail electric rate increase in May 2004;

• Growth in non-weather related demand for electricity;

• An increase in gross margins on power marketing, trading, and origination contracts; and

• A gain related to a Power Technology and Infrastructure investment.

For further information, see “2004 Results of Operations — Cinergy”.

Forward-looking Challenges and Risks

Environmental Challenges

Cinergy faces many uncertainties with regard to future environmental legislation and the impact of this legislation on our generating assets and our decisions to construct new assets. In two separate rulemakings, the Environmental Protection Agency (EPA) has proposed significant reductions in sulfur dioxide (SO₂), nitrogen oxides (NO_X) and mercury emissions from power plants, neither of which have been finalized. Additionally, multi-emissions reductions legislation could be passed in 2005 that may take the place of these proposed rulemakings. In 2004, Cinergy’s utility operating companies began an environmental construction program to reduce overall plant emissions that is estimated to cost approximately $1.8 billion over the next five years. We believe that our construction program optimally balances these uncertainties and provides a level of emission reduction that will be required and/or economical to Cinergy under a variety of possible regulatory outcomes. See “Environmental Issues” in “Liquidity and Capital Resources” for further information.

Regulatory Challenges

Ohio has enacted electric generation deregulation legislation. CG&E’s residential customers are in a market development period through 2005, during which prices are fixed, while non-residential customers are under a recently approved rate stabilization plan (RSP) that runs through December 31, 2008. Residential customers will be under the RSP beginning in 2006, also ending in 2008. At this time, it is difficult to predict how the regulatory environment will look after the rate stabilization period ends. To date, deregulation in Ohio has not progressed as originally anticipated and the Ohio General Assembly may consider re-regulation laws as early as 2005. However, the possibility of deregulation or a hybrid of both deregulation and regulation still exists. These regulatory uncertainties are particularly challenging as we attempt to address short-term and long-term generation capacity needs as well as environmental requirements previously discussed. See “Regulatory Outlook and Significant Rate Developments” in “Future Expectations/Trends” for further discussion of these risks and uncertainties.

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

The projected implementation date is April 1, 2005 for the Midwest ISO to begin operating under the Energy Markets Tariff (sometimes referred to as a Locational Marginal Pricing (LMP) market or MISO Day 2 market). The implementation of an LMP market will introduce new scheduling requirements, new products for mitigating transmission congestion risks, and new pricing points for the purchase and sale of power. Cinergy is in the process of preparing for the implementation and the Midwest ISO is currently conducting market trials and testing of the Energy Markets. This is a significant undertaking by the Midwest ISO and its stakeholders and testing is not yet complete. See “Midwest ISO Energy Markets” in “Future Expectations/Trends” for further details regarding these new markets.

Rising Coal and Emission Allowance Prices

The prices of coal and SO₂ allowances have increased dramatically in 2004, as compared to 2003. Contributing to the increases in coal and SO₂ prices have been (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. Since rates have been frozen for non-residential customers through 2004 and residential customers through 2005, pursuant to Ohio deregulation, these increases in coal and emission allowance prices could not be recovered through rates. The impact of these price increases on earnings is discussed in more detail in “Results of Operations”. See “Generation Portfolio Risks” in “Market Risk Sensitive Instruments” for information on how we plan to mitigate these risks going forward.

MD&A - 2004 RESULTS OF OPERATIONS - CINERGY

2004 RESULTS OF OPERATIONS - CINERGY

Gross Margins

Given the dynamics of our business, which include regulatory revenues with directly offsetting expenses and commodity trading operations for which results are primarily reported on a net basis, we have concluded that a discussion of our results on a gross margin basis is most appropriate. Electric gross margins represent electric operating revenues less the related direct costs of fuel, emission allowances, and purchased power. Gas gross margins represent gas operating revenues less the related direct cost of gas purchased. Within each of these areas, we will discuss the key drivers of our results. Gross margins for Cinergy for the Regulated Business Unit (Regulated) and Commercial for the years ended December 31, 2004, and 2003 were as follows:

	Cinergy
	Regulated								Commercial
	2004		2003		Change		% Change		2004		2003		Change			% Change
	(in millions)

Electric gross margin(1)	$	1,656	$	1,469	$	187	13	%	$	637	$	714	$	(77	)	(11	)%
Gas gross margin(2)	263		244		19		8		92		88		4			5
Total gross margin	$	1,919	$	1,713	$	206	12		$	729	$	802	$	(73	)	(9	)

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact weather has on results of operations. Cooling degree days and heating degree days in Cinergy’s service territory for the years ended December 31, 2004, and 2003 were as follows:

	Cinergy
	2004	2003	Change		% Change

Cooling degree days(1)	882	831	51		6	%
Heating degree days(2)	5,006	5,316	(310	)	(6	)

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

The change in cooling degree days and heating degree days did not have a material effect on Cinergy’s gross margins for the year ended December 31, 2004, as compared to 2003.

Regulated Gross Margins

The 13 percent increase in Regulated’s electric gross margins was primarily due to the following factors:

• An approximate $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and

• An approximate $32 million increase due to growth in non-weather related demand.

The eight percent increase in Regulated’s gas gross margins was primarily due to an approximate $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was an approximate $7 million decrease reflecting a decline in non-weather related demand.

Commercial

Gross Margins

The 11 percent decrease in Commercial’s electric gross margins was primarily due to the following factors:

• An approximate $51 million increase in CG&E’s average price of fuel without a matching increase in the price of power charged to customers (the majority of which were under fixed price contracts); and

• An approximate $62 million increase in emission allowance costs, primarily due to increases in SO₂ emission allowance market prices, without a matching increase in the price of power charged to customers. The number of SO₂ emission allowances used also increased in 2004.

Partially offsetting these decreases were:

• An approximate $24 million increase in gross margins on power marketing, trading, and origination contracts attributable to higher margins on physical and financial trading, primarily related to regional spreads between the mideast and midwest markets; and

• An approximate $15 million increase due to growth in non-weather related demand.

Commercial’s gas gross margins under generally accepted accounting principles (GAAP) and Commercial’s adjusted gas gross margins were relatively flat in 2004, as compared to 2003, although volatility during 2004 was significant due to timing differences in revenue recognition between physical storage activities and the associated derivative contracts that hedge the physical storage. We evaluate the results of our gas marketing and trading business on an economic basis, which we term “adjusted gas gross margins”.

Our gas marketing and trading business regularly hedges its price exposure of natural gas held in storage by selling derivative contracts for winter month delivery. The majority of the gas held in storage is designated as being hedged under Statement of Financial Accounting Standards No. 133’s, Accounting for Derivative Instruments and Hedging Activities (Statement 133), fair value hedge accounting model, which allows the gas to be accounted for at its fair value (based on spot prices). Under GAAP, the derivative contracts hedging the gas are accounted for at fair value (based on forward winter prices). Conversely, the agreements with pipelines to store this natural gas until the winter periods are not derivatives and are not adjusted for changes in fair value (see footnote 1 in the table below).

For a more complete understanding of our gas marketing and trading results, we have prepared the following table, which reconciles the gas margins under GAAP, the impact of adjusting these margins for the fair value of pipeline agreements and certain gas held in storage, and the resulting adjusted gas gross margins:

	2004			2003			Change
	(in millions)

Gas margins, as reported (GAAP)	$	92		$	88		$	4

Fair value adjustments not recognized under GAAP(1)	(7		)	(5		)	(2		)

Adjusted gas gross margins	$	85		$	83		$	2

(1) Relates to fair value of storage agreements. The value of a storage agreement is the ability to store and optimize gas between periods of lower prices (typically summer) and periods of higher prices (typically winter). A large component of the fair value is therefore the differences between winter prices and spot prices. As this spread gets wider, the value of a storage agreement increases.

Other Operating Revenues and Costs of Fuel Resold

The 41 percent increase in Other Operating Revenues was primarily due to the following factors:

• An approximate $67 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts. Coal origination includes contract structuring and marketing of physical coal; and

• An approximate $28 million increase in Commercial’s revenues from the sale of synthetic fuel.

Costs of fuel resold includes Commercial’s costs of coal origination activities and the production of synthetic fuel. These costs have increased in 2004, which is consistent with the increases in the associated revenues as previously discussed.

The following explanations correspond with the line items on the Statements of Income for Cinergy. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	Cinergy
	2004		2003		Change		% Change
	(in millions)

Operation and maintenance	$	1,282	$	1,119	$	163	15	%
Depreciation	460		399		61		15
Taxes other than income taxes	254		250		4		2
Total	$	1,996	$	1,768	$	228	13

Operation and Maintenance

The 15 percent increase in Operation and maintenance expense was primarily due to the following factors:

• Costs primarily associated with employee labor and benefits increased approximately $50 million. Labor and benefit costs increased approximately six percent;

• Maintenance expenses, primarily production related, were higher by approximately $26 million;

• An approximate $20 million of costs incurred in 2004 related to a continuous improvement initiative;

• Higher transmission costs of approximately $15 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year; and

• An approximate $14 million increase in operation expenses for non-regulated service subsidiaries that started operations, or became fully consolidated, after the second quarter of 2003.

These increases were partially offset by:

• The recognition of approximately $14 million of costs associated with voluntary early retirement programs and employee severance programs in 2003; and

• An approximate $12 million for costs incurred in 2003 associated with the bankruptcy of Enron Corp.

Depreciation

The 15 percent increase in Depreciation expense was primarily due to the following factors:

• An approximate $36 million increase due to the addition of depreciable plant, primarily for pollution control equipment, and the accelerated gas main replacement program; and

• An approximate $27 million increase resulting from a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal and b) recovery of deferred depreciation costs, both of which were approved in PSI’s latest retail rate case.

These increases were partially offset by approximately $15 million due to longer estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003.

Equity in Earnings of Unconsolidated Subsidiaries

The increase in Equity in Earnings of Unconsolidated Subsidiaries was primarily due to a gain of approximately $21 million relating to the sale of most of the assets by a company in which Power Technology and Infrastructure holds an investment. See Note 15(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.

Miscellaneous Income (Expense) - Net

The decrease in Miscellaneous Income (Expense) — Net was primarily due to the recognition of approximately $56 million in impairment and disposal charges in 2004 primarily associated with certain investments in the Power Technology and Infrastructure portfolio. The values of these investments reflect our estimates and judgments about the future performance of these investments, for which actual results may differ. A substantial portion of these charges relate to a company, in which Cinergy holds a non-controlling interest that sold its major assets in 2004. This company is involved in the development and sale of outage management software.

This decrease was partially offset by interest income of approximately $9 million on the notes receivable of two subsidiaries consolidated in the third quarter of 2003.

Interest Expense

The two percent increase in Interest Expense was primarily due to the following factors:

• An approximate $12 million increase due to Cinergy’s recognition of a note payable to a trust; and

• An approximate $9 million increase related to additional debt recorded in accordance with the consolidation of two new entities.

The note payable and additional debt were both recorded in July 2003 resulting from the adoption of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities (Interpretation 46).

These increases were partially offset by:

• A decline in average long-term debt; and

• Charges recorded during 2003 associated with CG&E’s refinancing of certain debt.

Preferred Dividend Requirement of Subsidiary Trust

The decrease in Preferred Dividend Requirement of Subsidiary Trust was a result of the implementation of Interpretation 46. Effective July 1, 2003, the preferred trust securities and the related dividends are no longer reported in Cinergy’s financial statements. However, interest expense is still being incurred on a note payable to this trust as previously discussed. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.

Income Taxes

Cinergy’s 2004 effective tax rate was approximately 21 percent, a decrease of four percent from 2003, resulting from a greater amount of tax credits associated with the production and sale of synthetic fuel and the successful resolution of certain tax matters.

Discontinued Operations

During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the United States, and substantially sold or liquidated the assets of its energy trading operation in the Czech Republic. Pursuant to Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-lived Assets (Statement 144), these investments have been classified as discontinued operations in our financial statements. See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.

Cumulative Effect of Changes in Accounting Principles

In 2003, Cinergy recognized a Cumulative effect of changes in accounting principles, net of tax gain of approximately $26 million. The cumulative effect of changes in accounting principles was a result of the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (Statement 143) and the rescission of Emerging Issues Task Force (EITF) Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.

MD&A - 2004 RESULTS OF OPERATIONS – CG&E

2004 RESULTS OF OPERATIONS - CG&E

Summary of Results

Net income for CG&E for the years ended December 31, 2004, and 2003 were as follows:

	CG&E and subsidiaries
	2004		2003		Change			% Change
	(in millions)

Net income	$	257	$	331	$	(74	)	(22	)%

The decrease in net income was primarily due to the following factors:

• Higher operating costs due, in part, to increases in costs for employee labor and benefits;

• Lower margins from the sale of electricity primarily due to higher fuel and emission allowance costs; and

• A net gain recognized in 2003 resulting from the implementation of certain accounting changes.

These decreases were partially offset by:

• Growth in non-weather related demand for electricity; and

• An increase in gross margins on power marketing, trading, and origination contracts.

Gross Margins

Gross margins for CG&E for the years ended December 31, 2004, and 2003 were as follows:

	CG&E and subsidiaries
	2004		2003		Change			% Change
	(in millions)

Electric gross margin(1)	$	1,168	$	1,195	$	(27	)	(2	)%
Gas gross margin(2)	263		245		18			7

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.

Cooling degree days and heating degree days in CG&E’s service territory for the years ended December 31, 2004, and 2003 were as follows:

	CG&E and subsidiaries
	2004	2003	Change		% Change

Cooling degree days(1)	876	812	64		8	%
Heating degree days(2)	4,881	5,119	(238	)	(5	)

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

The change in cooling degree days and heating degree days did not have a material effect on CG&E’s gross margins for the period.

Electric Gross Margins

The two percent decrease in CG&E’s electric gross margins was primarily due to the following factors:

• An approximate $51 million increase in the average price of fuel without a matching increase in the price of power charged to customers (the majority of which were under fixed price contracts); and

• An approximate $32 million increase in emission allowance costs, primarily due to an increase in SO₂ emission allowance market prices, without a matching increase in the price of power charged to customers.

These decreases were partially offset by:

• An approximate $31 million increase in margins from retail customers due to growth in non-weather related demand; and

• An approximate $29 million increase in gross margins on power marketing, trading, and origination contracts attributable to higher margins on physical and financial trading, primarily related to regional spreads between the mideast and midwest markets.

Gas Gross Margins

The seven percent increase in CG&E’s gas gross margins was primarily due to an approximate $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was an approximate $7 million decrease reflecting a decline in non-weather related demand.

Other Operating Revenues and Costs of Fuel Resold

The increase in Other Operating Revenues was due to an approximate $67 million increase in revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts.

Costs of fuel resold represents the costs of coal origination activities. These costs have increased in 2004, which is consistent with the increase in the associated revenues as previously discussed.

The following explanations correspond with the line items on the Statements of Income for CG&E. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	CG&E and subsidiaries
	2004		2003		Change			% Change
	(in millions)

Operation and maintenance	$	594	$	500	$	94		19	%
Depreciation	179		187		(8		)	(4	)
Taxes other than income taxes	198		200		(2		)	(1	)
Total	$	971	$	887	$	84		9

Operation and Maintenance

The 19 percent increase in Operation and maintenance expense was primarily due to the following factors:

• Costs primarily associated with employee labor and benefits increased approximately $28 million;

• Maintenance expenses, primarily production and distribution related, were higher by approximately $21 million;

• An approximate $9 million of costs incurred in 2004 related to a continuous improvement initiative; and

• Higher transmission costs of approximately $9 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year.

Partially offsetting these increases was the recognition of approximately $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.

Depreciation

The four percent decrease in Depreciation expense was primarily due to longer estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003, which resulted in a decrease of approximately $15 million. This decrease was partially offset by an approximate $8 million increase due to the addition of depreciable plant primarily for pollution control equipment and the accelerated gas main replacement program.

Miscellaneous Income - Net

The 47 percent decrease in Miscellaneous Income — Net was primarily due to the following factors:

• A final reconciliation recorded in 2003 between CG&E and PSI due to a previous demutualization of a medical insurance carrier used by both companies; and

• A decline in the allowance for equity funds used during construction resulting from certain assets being placed into service and a decrease in the equity rate applied.

Interest Expense

The 21 percent decrease in Interest Expense was primarily due to the following factors:

• A decline in average long-term debt; and

• Charges recorded during 2003 associated with the refinancing of certain debt.

Cumulative Effect of Changes in Accounting Principles

In 2003, CG&E recognized a Cumulative effect of changes in accounting principles, net of tax gain of approximately $31 million as a result of the adoption of Statement 143 and the rescission of EITF 98-10. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.

MD&A - 2004 RESULTS OF OPERATIONS – PSI

2004 RESULTS OF OPERATIONS - PSI

Summary of Results

Net income for PSI for the years ended December 31, 2004, and 2003 were as follows:

	PSI
	2004		2003		Change		% Change
	(in millions)

Net income	$	165	$	133	$	32	24	%

The increase in net income was primarily due to the following factors:

• The impact of the PSI base retail electric rate increase in May 2004; and

• Growth in non-weather related demand.

These increases were partially offset by higher operating costs due, in part, to increases in costs for employee labor and benefits.

Electric Gross Margins

Gross margins for PSI for the years ended December 31, 2004, and 2003 were as follows:

	PSI
	2004		2003		Change		% Change
	(in millions)

Electric gross margin(1)	$	1,103	$	973	$	130	13	%

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

Cooling degree days and heating degree days in PSI’s service territory for the years ended December 31, 2004, and 2003 were as follows:

	PSI
	2004	2003	Change		% Change

Cooling degree days(1)	887	850	37		4	%
Heating degree days(2)	5,128	5,512	(384	)	(7	)

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

The change in degree days did not have a material effect on electric gross margins for the period. The 13 percent increase in PSI’s electric gross margins was primarily due to the following factors:

• An approximate $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and

• An approximate $16 million increase due to growth in non-weather related demand.

The following explanations correspond with the line items on the Statements of Income for PSI. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	PSI
	2004		2003		Change		% Change
	(in millions)

Operation and maintenance	$	475	$	449	$	26	6	%
Depreciation	222		164		58		35
Taxes other than income taxes	47		46		1		2
Total	$	744	$	659	$	85	13

Operation and Maintenance

The six percent increase in Operation and maintenance expense was primarily due to the following factors:

• Costs primarily associated with employee labor and benefits increased approximately $14 million;

• An approximate $8 million of costs incurred in 2004 related to a continuous improvement initiative;

• An increase in production related maintenance expense of approximately $7 million; and

• Higher transmission costs of approximately $6 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year.

Partially offsetting these increases was the recognition of approximately $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.

Depreciation

The 35 percent increase in Depreciation expense was primarily due to the following factors:

• An approximate $27 million increase due to the addition of depreciable plant primarily for pollution control equipment; and

Interest Expense

The seven percent increase in Interest Expense was primarily due to an increase in the effective interest rate on short-term debt and an increase in the average amount of short-term debt outstanding.

MD&A - 2004 RESULTS OF OPERATIONS – ULH&P

2004 RESULTS OF OPERATIONS - ULH&P

The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2004, in accordance with General Instruction I(2)(a).

Electric and gas gross margins and net income for ULH&P for the years ended December 31, 2004 and 2003, were as follows:

	ULH&P
	2004		2003		Change		% Change
	(in millions)

Electric gross margin(1)	$	68	$	68	$	—	—	%
Gas gross margin(2)	45		40		5		13
Net income	19		19		—		—

(1) Electric gross margin is calculated as Electric operating revenues less Electricity purchased from parent company for resale expense from the Statements of Income.

(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.

Electric gross margins for ULH&P remained flat as growth in non-weather related demand was offset by the cost of increased electricity purchases to meet that demand. The 13 percent increase in gas gross margins was due, in part, to an approximate $3 million increase in rate tariff adjustments associated with the gas main replacement program and the demand-side management program, which encourages efficient customer gas usage.

Net income remained flat as an approximate $2 million increase in operating costs, primarily related to increased transmission and distribution expenses, was partially offset by an approximate $1 million reduction in property taxes during 2004.

MD&A - 2003 RESULTS OF OPERATIONS - CINERGY

2003 RESULTS OF OPERATIONS - CINERGY

Summary of Results

Net income for Cinergy for the years ended December 31, 2003, and 2002 was as follows:

	Cinergy
	2003		2002		Change		% Change
	(in millions)

Net income	$	470	$	361	$	109	30	%

Cinergy’s increase in net income was primarily due to the following factors:

• Increases in gas gross margins as a result of an increase in base rates for Ohio customers, colder weather and increased volatility in gas prices in the first quarter of 2003, as compared to 2002, and an increase in natural gas sold from storage;

• Lower operating costs primarily resulting from the recognition of higher costs in 2002 associated with employee severance programs;

• Lower property taxes, primarily resulting from the change in property value assessment in the state of Indiana in 2003;

• The 2002 write-off of certain investments;

• A net gain recognized in 2003 resulting from the implementation of certain accounting changes;

• Gains realized in 2003 and losses incurred in 2002 from the disposal of discontinued operations; and

• Lower income taxes resulting primarily from tax credits associated with the production of synthetic fuel, which began in July 2002.

These increases were partially offset by:

• A decrease in electric gross margins primarily due to milder weather in 2003; and

• A decline in electric gross margins associated with Cinergy’s natural gas peaking assets.

Gross Margins

Given the dynamics of our business, which include regulatory revenues with directly offsetting expenses and commodity trading operations for which results are primarily reported on a net basis, we have concluded that a discussion of our results on a gross margin basis is most appropriate. Electric gross margins represent electric operating revenues less the related direct costs of fuel, emission allowances, and purchased power. Gas gross margins represent gas operating revenues less the related direct cost of gas purchased. Within each of these areas, we will discuss the key drivers of our results. Gross margins for Cinergy for Regulated and Commercial for the years ended December 31, 2003, and 2002 were as follows:

	Cinergy
	Regulated										Commercial
	2003		2002		Change			% Change		2003				2002				Change				% Change
	(in millions)

Electric gross margin(1)	$	1,469	$	1,571	$	(102	)	(6	)%		$	714	$			735	$		(21		)	(3	)%
Gas gross margin(2)	244		203		41			20			88		77				11					14
Total gross margin	$	1,713	$	1,774	$	(61	)	(3	)		$	802	$		812		$			(10	)	1

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.

	Cinergy
	2003	2002	Change		% Change

Cooling degree days(1)	831	1,357	(526	)	(39	)%
Heating degree days(2)	5,316	5,093	223		4

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

Regulated Gross Margins

The six percent decrease in Regulated’s electric gross margins was primarily due to a decline in retail electric margins mainly resulting from milder weather in 2003, compared to 2002. As noted in the table, cooling degree days were down 39 percent in Cinergy’s service territory. Partially offsetting this decrease was an increase in rate tariff adjustments associated with certain construction programs at PSI.

The 20 percent increase in Regulated’s gas gross margins was primarily due to the following factors:

• An increase in base rates, as approved by the Public Utilities Commission of Ohio (PUCO) in May 2002, and tariff adjustments associated with the gas main replacement program and Ohio excise taxes; and

• The colder weather in the first quarter of 2003, compared to 2002, which resulted in a greater amount of thousand cubic feet (mcf) delivered to customers.

Commercial

Gross Margins

The three percent decrease in Commercial’s electric gross margins was primarily due to a decline in margins associated with Commercial’s natural gas peaking assets in 2003, as compared to 2002. Partially offsetting this decrease were higher margins from physical and financial trading primarily in and around the midwest.

The 14 percent increase in Commercial’s gas gross margins was primarily due to the following factors:

• An increase in the volatility of natural gas prices in the first quarter of 2003, as compared to the same period in 2002; and

• An increase in natural gas sold out of storage in 2003. Cinergy Marketing & Trading, LP (Marketing & Trading) began engaging in significant storage activities at the end of the second quarter of 2002.

Other Operating Revenues and Costs of Fuel Resold

The 22 percent increase in Other Operating Revenues was primarily due to an increase in Commercial’s revenues from the sale of synthetic fuel, which began in July 2002. This increase was partially offset by a decline in Commercial’s revenues from coal origination.

Costs of fuel resold includes Commercial’s costs of coal origination activities and the production of synthetic fuel. In 2003, the costs of producing synthetic fuel increased and the costs of coal origination activities decreased, both of which are consistent with the changes in the associated revenues as previously discussed.

The following explanations correspond with the line items on the Statements of Income for Cinergy. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	Cinergy
	2003			2002			Change				% Change
	(in millions)

Operation and maintenance	$		1,119	$	1,202		$	(83		)	(7	)%
Depreciation	399			404			(5			)	(1	)
Taxes other than income taxes	250			263			(13			)	(5	)
Total	$	1,768		$		1,869	$		(101	)	(5	)

Operation and Maintenance

The seven percent decrease in Operation and maintenance expense was primarily due to the following factors:

• The recognition of higher costs associated with employee severance programs in 2002;

• Decreased transmission costs, largely the result of changes in the Midwest ISO operations; and

• A decrease in employee incentive costs.

These decreases were partially offset by:

• The charges associated with our resolution of claims with respect to the bankruptcy of Enron Corp.; and

• An increase in maintenance expense for our generating units and overhead lines.

Depreciation

The one percent decrease in Depreciation expense was primarily due to the following factors:

• An increase in estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003; and

• CG&E’s discontinuance of accruing costs of removal for generating assets (which was previously included as part of Depreciation expense) as a result of the adoption of Statement 143. See Note 1(j) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Prior periods were not restated for the adoption of Statement 143.

Partially offsetting these decreases was the addition of depreciable plant primarily including pollution control equipment, accelerated gas main replacement program assets, and equipment associated with the production of synthetic fuel.

Taxes Other Than Income Taxes

The five percent decrease in Taxes other than income taxes expense was primarily due to lower property taxes, which were partially offset by increased excise taxes. This decrease was primarily a result of a change in property value assessments in the state of Indiana in 2003.

Miscellaneous Income (Expense) - Net

The increase in Miscellaneous Income (Expense) - Net was primarily due to the following factors:

• 2002 write-offs of certain equipment and technology investments and costs accrued related to the termination of a contract for the construction of combustion turbines; and

• Interest income on the notes receivable of two newly consolidated subsidiaries in 2003. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.

Partially offsetting these increases were net gains realized in 2002 from the sale of equity investments in certain renewable energy projects.

Interest Expense

The 11 percent increase in Interest Expense was primarily due to the following factors:

• An increase in average long-term debt outstanding during the year ended December 31, 2003;

• Charges during 2003 associated with the re-financing of certain debt; and

• Additional debt recorded in July 2003 with the consolidation of two new entities and the recognition of a note payable to a trust resulting from the adoption of Interpretation 46. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.

These increases were partially offset by a decrease in short-term interest rates.

Preferred Dividend Requirement of Subsidiary Trust

The 50 percent decrease in Preferred Dividend Requirement of Subsidiary Trust was a result of the implementation of Interpretation 46. Effective July 1, 2003, the preferred trust securities and the related dividends are no longer reported in Cinergy’s financial statements. However, interest expense is still being incurred on a note payable to this trust as previously discussed. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.

Income Taxes

The decrease in the effective income tax rate was primarily due to tax credits associated with the production and sale of synthetic fuel, which began in July 2002. Cinergy’s effective tax rate for 2003 was approximately 25 percent.

Discontinued Operations

In 2002, Cinergy sold and/or classified as held for sale, several non-core investments, including renewable and international investments. During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the United States, and substantially sold or liquidated the assets of its energy trading operation in the Czech Republic. Pursuant to Statement 144, these investments have been classified as discontinued operations in our financial statements. See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.

The increase in discontinued operations in 2003 as compared to 2002 was due to the recognition of losses on disposal of foreign investments in 2002 and the recognition of gains on disposal in 2003.

Cumulative Effect of Changes in Accounting Principles

In 2002, Cinergy recognized a Cumulative effect of a change in accounting principle, net of tax loss of approximately $11 million as a result of implementation of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.

MD&A - 2003 RESULTS OF OPERATIONS – CG&E

2003 RESULTS OF OPERATIONS - CG&E

Summary of Results

Net income for CG&E for the years ended December 31, 2003, and 2002 were as follows:

	CG&E and subsidiaries
	2003		2002		Change		% Change
	(in millions)

Net income	$	331	$	264	$	67	25	%

CG&E’s increase in net income was primarily due to the following factors:

• Increases in gas gross margins due to an increase in base rates, as approved by the PUCO in May 2002, and colder weather in the first quarter of 2003 as compared to 2002;

• Lower operating costs primarily resulting from the recognition of higher costs in 2002 associated with employee severance programs; and

• A net gain recognized in 2003 resulting from the implementation of certain accounting changes.

Offsetting these increases was a decrease in electric gross margins primarily due to milder weather in 2003, as compared to 2002.

Gross Margins

Gross margins for CG&E for the years ended December 31, 2003, and 2002 were as follows:

	CG&E and subsidiaries
	2003		2002		Change			% Change
	(in millions)

Electric gross margin(1)	$	1,195	$	1,205	$	(10	)	(1	)%
Gas gross margin(2)	245		205		40			20

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.

Cooling degree days and heating degree days in CG&E’s service territory for the years ended December 31, 2003, and 2002 were as follows:

	CG&E and subsidiaries
	2003	2002	Change		% Change

Cooling degree days(1)	812	1,353	(541	)	(40	)%
Heating degree days(2)	5,119	4,926	193		4

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

Electric Gross Margins

The one percent decrease in CG&E’s electric gross margins was primarily due to a decline in retail electric margins mainly resulting from milder weather in 2003 as compared to 2002. As noted in the table, cooling degree days were down 40 percent in CG&E’s service territory. Higher margins from physical and financial trading partially offset this decrease.

Gas Gross Margins

The 20 percent increase in CG&E’s gas gross margins was primarily due to the following factors:

• An increase in base rates, as approved by the PUCO in May 2002, and tariff adjustments associated with the gas main replacement program and Ohio excise taxes; and

• The colder weather in the first quarter of 2003, compared to 2002, which resulted in a greater amount of mcf delivered to customers.

Other Operating Revenues and Costs of Fuel Resold

The 23 percent decrease in Other Operating Revenues was due to a decrease in revenues from coal origination.

Costs of fuel resold represents the costs of coal origination activities. These costs decreased in 2003, which is consistent with the decline in the associated revenues as previously discussed.

The following explanations correspond with the line items on the Statements of Income for CG&E. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	CG&E and subsidiaries
	2003		2002		Change			% Change
	(in millions)

Operation and maintenance	$	500	$	531	$	(31	)	(6	)%
Depreciation	187		197		(10		)	(5	)
Taxes other than income taxes	200		198		2			1
Total	$	887	$	926	$	(39	)	(4	)

Operation and Maintenance

The six percent decrease in Operation and maintenance expense was primarily due to the following factors:

• Decreased transmission costs largely the result of changes in the Midwest ISO operations;

• The recognition of higher costs associated with employee severance programs in 2002; and

• A decrease in employee incentive costs.

These decreases were partially offset by an increase in maintenance expense for our generating units and overhead lines.

Depreciation

The five percent decrease in Depreciation expense was primarily due to the following factors:

• An increase in the estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003; and

• The discontinuance of accruing costs of removal for generating assets (which was previously included as part of Depreciation expense) as a result of the adoption of Statement 143. See Note 1(j) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Prior periods were not restated for the adoption of Statement 143.

Miscellaneous Income - Net

The increase in Miscellaneous Income - Net was due, in part, to a final reconciliation with PSI of a previous demutualization of a medical insurance carrier used by both companies which was recorded in 2003.

Interest Expense

The 20 percent increase in Interest Expense was primarily due to the following factors:

• An increase in average long-term debt outstanding; and

• Charges during 2003 associated with the re-financing of certain debt.

Cumulative Effect of Changes in Accounting Principles

MD&A - 2003 RESULTS OF OPERATIONS – PSI

2003 RESULTS OF OPERATIONS - PSI

Summary of Results

Net income for PSI for the years ended December 31, 2003, and 2002 was as follows:

	PSI
	2003		2002		Change			% Change
	(in millions)

Net income	$	133	$	214	$	(81	)	(38	)%

PSI’s decrease in net income was primarily attributable to decreases in electric gross margins due to milder weather in 2003, as compared to 2002. This decrease was partially offset by the following factors:

• The recognition of higher operating costs in 2002 associated with employee severance programs; and

• Lower property taxes, primarily resulting from the change in property value assessment in the state of Indiana in 2003.

Electric Gross Margins

Gross margins for PSI for the years ended December 31, 2003, and 2002 were as follows:

	PSI
	2003		2002		Change			% Change
	(in millions)

Electric gross margin(1)	$	973	$	1,064	$	(91	)	(9	)%

(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.

Cooling degree days and heating degree days in PSI’s service territory for the years ended December 31, 2003, and 2002 were as follows:

	PSI
	2003	2002	Change		% Change

Cooling degree days(1)	850	1,360	(510	)	(38	)%
Heating degree days(2)	5,512	5,260	252		5

(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2) Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

The nine percent decrease in PSI’s electric gross margins was primarily due to a decline in retail electric margins resulting from milder weather in 2003, compared to 2002. As noted in the table, cooling degree days were down 38 percent in PSI’s service territory. An increase in rate tariff adjustments associated with certain construction programs partially offset these decreases.

The following explanations correspond with the line items on the Statements of Income for PSI. However, only the line items that varied significantly from prior periods are discussed.

Other Operating Expenses

	PSI
	2003		2002		Change			% Change
	(in millions)

Operation and maintenance	$	449	$	470	$	(21	)	(4	)%
Depreciation	164		155		9			6
Taxes other than income taxes	46		57		(11		)	(19	)
Total	$	659	$	682	$	(23	)	(3	)

Operation and Maintenance

The four percent decrease in Operation and maintenance expense was primarily due to the following factors:

• Recognition of higher costs associated with employee severance programs in 2002;

• Decreased transmission costs, largely the result of changes in the Midwest ISO operations; and

• A decrease in employee incentive costs.

These decreases were partially offset by an increase in maintenance expense for our generating units and overhead lines.

Depreciation

The six percent increase in Depreciation expense was primarily due to the following factors:

• The addition of depreciable plant resulting from PSI’s December 2002 purchase of two gas-fired peaking plants from non-regulated affiliates. See Note 19 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for more information; and

• The addition of other depreciable plant primarily reflecting pollution control equipment and the repowering of Noblesville Station.

Taxes Other Than Income Taxes

The 19 percent decrease in Taxes other than income taxes expense was primarily due to lower property taxes, which were partially offset by increased excise taxes. This decrease was primarily a result of a change in property value assessments in the state of Indiana in 2003.

Miscellaneous Income - Net

The 69 percent decrease in Miscellaneous Income - Net was primarily a result of a final reconciliation with CG&E of a previous demutualization of a medical insurance carrier used by both companies which was recorded in 2003.

Interest Expense

The 16 percent increase in Interest Expense was primarily a result of an increase in average long-term debt outstanding during the year ended December 31, 2003. This increase was partially offset by a decrease in short-term interest rates.

Income Taxes

The increase in the effective income tax rate was primarily due to an increase in the Indiana state income tax rate.

MD&A – LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flow Analysis From Continuing Operations

Operating Activities from Continuing Operations

For the years ended December 31, 2004, 2003, and 2002, our cash flows from operating activities from continuing operations were as follows:

Net Cash Provided by Operating Activities from Continuing Operations

	2004		2003		2002
	(in thousands)

Cinergy(1)	$	833,004	$	945,673	$	955,802
CG&E and subsidiaries	445,621		557,761		653,029
PSI	483,463		246,735		499,047
ULH&P	45,381		33,061		60,707

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

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

For the year ended December 31, 2004, Cinergy’s and CG&E’s decrease in net cash provided by operating activities was primarily due to unfavorable working capital fluctuations, including the build up of fuel and emission allowances inventory. PSI’s increase was due to an increase in earnings (after adjusting for non-cash items) and a difference in the timing of payables and income tax payments. ULH&P’s increase in net cash provided by operating activities was attributable to favorable working capital fluctuations.

For the year ended December 31, 2003, CG&E’s, PSI’s, and ULH&P’s net cash provided by operating activities decreased, as compared to 2002. CG&E’s decrease was primarily due to unfavorable working capital fluctuations. PSI’s decrease was largely due to a decrease in earnings (after adjusting for non-cash items) and a decrease in receivables sold under the receivables sale facility. A significant portion of ULH&P’s decrease was due to unfavorable working capital fluctuations and an increase in deferred costs under the gas cost recovery mechanism. Cinergy’s net cash provided by operating activities in 2003 was comparable to 2002, comprised of the decreases at CG&E and PSI discussed above offset by improved operating cash flows at our non-regulated subsidiaries.

Financing Activities from Continuing Operations

For the years ended December 31, 2004, 2003, and 2002, our cash flows from financing activities from continuing operations were as follows:

Net Cash Provided by (Used in) Financing Activities from Continuing Operations

	2004			2003			2002
	(in thousands)

Cinergy(1)	$	(233,881	)	$	(245,128	)	$	42,689
CG&E and subsidiaries	(172,782		)	(263,296		)	(293,445		)
PSI	(164,141		)	90,070			(43,817		)
ULH&P	(9,226		)	4,852			(22,026		)

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

For the year ended December 31, 2004, CG&E’s decrease in net cash used in financing activities was primarily due to a decrease in redemptions of long-term debt. PSI’s increase in net cash used in financing activities was attributable to the repayment of short-term debt in 2004 and capital contributions from Cinergy Corp. that were made in 2003. ULH&P’s increase in net cash used in financing activities was due to an increase in dividends on common stock. Cinergy’s net cash used in financing activities in 2004 was comparable to 2003.

For the year ended December 31, 2003, Cinergy’s net cash used in financing activities increased, as compared to 2002, primarily due to increases in redemptions of long-term debt. CG&E’s net cash used in financing activities decreased during 2003, as compared to 2002, primarily due to a net increase in short-term debt financing. PSI’s and ULH&P’s net cash provided by financing activities increased during 2003, as compared to 2002. PSI’s increase was primarily due to capital contributions from Cinergy Corp. ULH&P’s increase was primarily attributable to increases in short-term debt.

Investing Activities from Continuing Operations

For the years ended December 31, 2004, 2003, and 2002, our cash flows used in investing activities from continuing operations were as follows:

Net Cash Used in Investing Activities from Continuing Operations

	2004			2003			2002
	(in thousands)

Cinergy(1)	$	(603,702	)	$	(731,537	)	$	(885,636	)
CG&E and subsidiaries	(284,527		)	(323,959		)	(323,322		)
PSI	(315,093		)	(332,247		)	(454,810		)
ULH&P	(33,857		)	(39,940		)	(38,854		)

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

For the year ended December 31, 2004, Cinergy’s decrease in net cash used in investing activities was primarily due to decreases in capital expenditures related to energy-related investments. CG&E’s decrease in net cash used in investing activities was primarily due to a decrease in capital expenditures for ongoing environmental compliance programs and normal construction activity. PSI’s and ULH&P’s net cash used in investing activities in 2004 was comparable to 2003.

For the year ended December 31, 2003, Cinergy’s net cash used in investing activities decreased, as compared to 2002, primarily due to decreases in capital expenditures related to environmental compliance programs and other energy-related investments. Cinergy also purchased a synthetic fuel production facility during 2002. PSI’s decrease was primarily due to decreases in capital expenditures for ongoing environmental compliance programs and other construction projects. CG&E’s and ULH&P’s net cash used in 2003 investing activities was comparable to 2002.

Capital Requirements

Environmental Issues

Proposed Environmental Protection Agency Regulations

In December 2003, the United States EPA proposed the Clean Air Interstate Rule (CAIR), formerly the Interstate Air Quality Rule, which would require states to revise their State Implementation Plans (SIP) to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards for ozone and fine particulate matter. The proposed rule would establish a two-phase, regional cap and trade program for SO₂ and NO_X, affecting approximately 30 states, including Ohio, Indiana, and Kentucky, and would require SO₂ and NO_X emissions to be cut approximately 70 percent and 65 percent, respectively, by 2015. The EPA also issued draft regulations regarding required reductions in mercury emissions from coal-fired power plants (Clean Air Mercury Rule). The draft regulations include two possible alternatives to achieve emissions reductions: a mercury cap and trade program or source specific reductions achieved through a command and control approach. The cap and trade approach would provide a longer compliance horizon and provide more flexible compliance options for coal-fired generators, including the purchase of allowances in lieu of further capital expenditures with respect to these investments. This approach would require a reduction of approximately 30 percent by 2010 and 70 percent by 2018. The source specific reduction approach would require a reduction of approximately 30 percent by 2008. The EPA is expected to issue final rules on CAIR and the Clean Air Mercury Rule by March 2005.

Over the 2005-2009 time period, estimated capital costs associated with reducing mercury, SO₂, and NO_X in compliance with the currently proposed CAIR and Clean Air Mercury Rule are not expected to exceed approximately

$1.72 billion if the EPA approves the mercury cap and trade approach and approximately $2.15 billion if the EPA approves the source specific reduction approach without a cap and trade program. These estimates include estimated costs to comply at plants that we own but do not operate and could change when taking into consideration compliance plans of co-owners or operators involved. Moreover, as market conditions change, additional compliance options may become available and our plans will be adjusted accordingly. Approximately 60 percent of these estimated environmental costs would be incurred at PSI’s coal-fired plants, for which recovery would be pursued in accordance with regulatory statutes governing environmental cost recovery. CG&E would receive partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its recently approved RSP. See Note 11(b)(iii) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for more details.

In June 2004, the EPA made final state non-attainment area designations to implement the revised ozone standard. In January 2005, the EPA made final state non-attainment area designations to implement the new fine particulate standard. Several counties in which we operate have been designated as being in non-attainment with the new ozone standard and/or fine particulate standard. States with counties that are designated as being in non-attainment with the new ozone and/or fine particulate standards are required to develop a plan of compliance. Although the EPA has attempted to structure the CAIR to resolve purported utility contributions to ozone and fine particulate non-attainment, at this time, Cinergy cannot predict the effect of current or future non-attainment designations on its financial position or results of operations.

In May 2004, the EPA issued proposed revisions to its regional haze rules and implementing guidelines in response to a 2002 judicial ruling overturning key provisions of the original program. The regional haze program is aimed at reducing certain emissions impacting visibility in national parks and wilderness areas. The EPA is currently considering whether SO₂ and NO_X reductions under the CAIR regulation will also satisfy the reduction requirements under the regional haze rule. However, the regional haze rule, when finalized, could potentially require significant additional SO₂ and NO_X reductions necessitating the installation of pollution controls for certain generating units at Cinergy’s power plants. In light of the EPA’s ongoing rulemaking efforts and the fact that the states have yet to announce how they will implement the final rule, at this time it is not possible to predict whether the regional haze rule will have a material effect on our financial position or results of operations.

Clear Skies Legislation

President Bush has proposed environmental legislation that would combine a series of Clean Air Act (CAA) requirements, including the recently proposed regulations for mercury and particulate matter for coal-fired power plants with a legislative solution that includes trading and specific emissions reductions and timelines to meet those reductions. The President’s “Clear Skies Initiative” would seek an overall 70 percent reduction in emissions from power plants over a phased-in reduction schedule beginning in 2010 and continuing through 2018. When the Clear Skies Initiative was stalled in Congress, the EPA proposed the CAIR regulations to accomplish Clear Skies’ goals within the existing framework of the CAA. Clear Skies has been reintroduced in the Senate and could be considered in Committee over the next several weeks. However, at this time, we cannot predict whether this or any multi-emissions bill will achieve approval.

Energy Bill

The United States House of Representatives (House) passed the Energy Policy Act in April 2003. The legislation, as passed in the House, included the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), as well as tax incentives for gas and electric distribution lines, and combined heat and power and renewable energy projects. The United States Senate (Senate) Energy and Natural Resources Committee passed its version of comprehensive energy legislation in April 2003. A conference agreement which merged both the House and Senate versions passed in the House in October 2003, but failed to pass in the Senate. The legislation will be introduced again during the 109th Congress, however, it is anticipated that several changes will be made. At this time, it is not possible to predict whether a final energy bill will pass in 2005.

Environmental Lawsuits

We are currently involved in the following lawsuits which are discussed in more detail in Note 11(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”. An unfavorable outcome of any of these lawsuits could have a material impact on our liquidity and capital resources.

• CAA Lawsuit

• Carbon Dioxide (CO₂) Lawsuit

• Selective Catalytic Reduction Units at Gibson Generating Station

• Zimmer Generating Station Lawsuit

• Manufactured Gas Plant Sites

• Asbestos Claims Litigation

Capital and Investment Expenditures

Actual construction and other committed expenditures for 2004 and forecasted construction and other committed expenditures for 2005 and for the five-year period 2005-2009 (in nominal dollars) are presented in the table below:

Capital and Investment Expenditures

	Actual		Forecasted
	2004		2005		2005-2009
	(in millions)

Cinergy(1)	$	701	$	1,115	$	5,430
CG&E and subsidiaries	300		430		2,345
PSI	340		620		2,645
ULH&P	34		80		335

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

In 2004, we spent $203 million for NO_X and other environmental compliance projects. Forecasted expenditures for environmental compliance projects (in nominal dollars) are approximately $465 million for 2005 and $1.8 billion for the 2005-2009 period. The vast majority of this forecast includes our entire estimate of costs to comply with draft regulations requiring reductions in mercury, NO_X, and SO₂ emissions, assuming a cap and trade approach to mercury emissions. Approximately 60 percent of these estimated environmental costs would be incurred at PSI’s regulated coal-fired plants. See “Environmental Issues” for further discussion.

Contractual Cash Obligations

The following table presents Cinergy’s, CG&E’s, PSI’s, and ULH&P’s significant contractual cash obligations:

	Payments Due
												There-
Contractual Cash Obligations	2005			2006		2007		2008		2009		after		Total
	(in millions)

Cinergy(1)
Capital leases	$	7		$	7	$	7	$	10	$	10	$	24	$	65
Operating leases	43			36		28		18		14		27		166
Long-term debt(2)	220		(3)(4)	355		726		551		270		2,376		4,498
Fuel purchase contracts(5)	879			495		420		49		—		—		1,843
Other commodity purchase contracts(6)	28			7		3		1		—		—		39

UNION LIGHT HEAT & POWER CO 10-K