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, 2005

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	%

The Union Light, Heat and Power Company	None

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities 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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Cinergy Corp.	Yes	o	No	ý
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

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

	Large Accelerated Filer	Accelerated Filer	Non- Accelerated Filer
Cinergy Corp.	ý	o	o
The Cincinnati Gas & Electric Company	o	o	ý
PSI Energy, Inc.	o	o	ý
The Union Light, Heat and Power Company	o	o	ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

As of June 30, 2005, the aggregate market value of the common equity of Cinergy Corp. held by non-affiliates (shareholders who are not directors or executive officers) was $7.3 billion based on the closing sale price as reported on the New York Stock Exchange. 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, 2006, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares

Cinergy Corp.	Par value $.01 per share	199,809,709

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

Document		Parts Into Which Incorporated

Cinergy Proxy Statement for the 2006 Annual Meeting of Shareholders		Part III
PSI Information Statement for the 2006 Annual Meeting of Shareholders		Part III

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
	Merger
	Business Segments
	Midwest ISO
	Employees
	Environmental Matters
	Future Expectations/Trends
1A	Risk Factors
1B	Unresolved Staff Comments
2	Properties
	Regulated
	Commercial
	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
	Dunavan Waste Superfund Site
	Merger Lawsuit
	Ohio EPA Penalty on Cinergy Power Generation Services
	Ontario, Canada Lawsuit
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
	2005 Results of Operations – Cinergy
	2005 Results of Operations – CG&E
	2005 Results of Operations – PSI
	2005 Results of Operations – ULH&P
	2004 Results of Operations – Cinergy
	2004 Results of Operations – CG&E
	2004 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 including costs of compliance with existing and future environmental requirements.

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

• Financial or regulatory accounting principles.

• 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.

• The regulatory approval process for the Duke Energy Corporation and Cinergy pending merger could delay the consummation of the pending merger or impose conditions that could materially impact the combined company.

• Business uncertainties, contractual restrictions, and the potential inability to attract and retain key personnel.

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 (Exchange Act) 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).

As of January 1, 2006, The Union Light, Heat and Power Company (ULH&P) ceased to be subject to the reporting requirements of section 13(a) or 15(d) of the Exchange Act. ULH&P is considering discontinuing filing reports and other information under such sections.

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 well as Cinergy Investments (Investments), its non-regulated investment holding company.

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 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 transitioning out of a market development period for residential customers and is in the competitive retail electric market for non-residential customers. CG&E is also 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 ended December 31, 2005 for residential customers. At the end of these market development periods, CG&E did 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 cost recovery mechanism through 2008. See “CG&E Electric Rate Stabilization Plan” for additional information.

PSI, an Indiana corporation organized in 1942, is a vertically integrated and cost of service 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(1)	• Generation, transmission, and distribution 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	2,077,000

PSI	• Generation, transmission, and distribution of electricity	Bloomington, IN Carmel, IN Columbus, IN Kokomo, IN Lafayette, IN New Albany, IN Terre Haute, IN	2,307,000

ULH&P(1)	• Transmission and distribution of electricity • Sale and transportation of natural gas	Covington, KY Florence, KY Newport, KY	347,000

(1) See “Electric Industry – Kentucky” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) – Future Expectations/Trends” for further discussion of the transfer of certain generation assets in January 2006. Following the transfer of generating assets, generation will be provided to cities of Covington, KY; Florence, KY; and Newport, KY by ULH&P.

The following table presents further information related to the operations of our other principal subsidiaries, Cinergy Services, Inc. (Services) and Investments:

		Principal Services and Line(s) of Business

Services(1)		• Administrative services
		• Management services
		• Support services

Investments		• Cogeneration and energy efficiency investments
		• Natural gas marketing and trading operations(2)

(1) Services provides the noted services to our subsidiaries.

(2) Natural gas marketing and trading operations are primarily conducted through Cinergy Marketing & Trading, LP (Marketing & Trading), one of Cinergy’s subsidiaries.

MERGER

On May 8, 2005, Cinergy Corp. entered into an agreement and plan of merger with Duke Energy Corporation (Duke), a North Carolina corporation, whereby Cinergy Corp. will be merged with Duke. Under the merger agreement, each share of Cinergy Corp. common stock will be converted into 1.56 shares of the newly formed company, Duke Energy Holding Corp (Duke Energy Holding).

The merger agreement has been approved by both companies’ Boards of Directors. Consummation of the merger is subject to customary conditions, including, among others, the approval of the shareholders of both companies and the approvals of various regulatory authorities.

Immediately following consummation of the merger, former Cinergy shareholders will own approximately 24 percent of Duke Energy Holding’s common stock. Paul Anderson, Duke’s CEO and Chairman of the Board will remain Chairman of the combined company and Jim Rogers, Cinergy’s CEO and Chairman of the Board, will become the President and CEO of the combined company. The new Duke Energy Holding board will be comprised of 10 members appointed by Duke and five members appointed by Cinergy.

The merger will be recorded using the purchase method of accounting whereby the total purchase price of approximately $9 billion will be allocated to Cinergy’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the closing of the merger.

The merger is expected to close in the first half of 2006. However, the actual timing is contingent on the receipt of several approvals including: The Federal Energy Regulatory Commission (FERC), Federal Communications Commission (FCC), Nuclear Regulatory Commission (NRC), state regulatory commissions of Ohio, Indiana, Kentucky, North Carolina, and South Carolina, and shareholders of each company. The status of these matters is as follows:

Completed:

• On August 11, 2005, the United States Department of Justice and the Federal Trade Commission granted early termination of the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

• In November 2005, the Kentucky Public Service Commission (KPSC) approved Duke’s and Cinergy’s application seeking approval of a transfer and acquisition of control of ULH&P.

• In November 2005, the state utility regulatory agency in South Carolina approved Duke’s application requesting authorization to enter into a business combination.

• In December 2005, the PUCO approved Cinergy’s application of a change in control with respect to CG&E. The PUCO affirmed the approval in February 2006.

• In December 2005, the FERC approved Duke’s and Cinergy’s application requesting approval of the merger and the subsequent internal restructuring and consolidation of the merged company.

• In February 2006, the NRC approved Duke’s application requesting approval of the merger.

• The FCC has approved assignment of all eight Cinergy wireless telecommunications licenses.

• In light of the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935), as amended, effective February 2006, the merger will no longer require SEC authorization under the PUHCA 1935.

Pending:

• In June 2005, PSI filed a petition with the Indiana Utility Regulatory Commission (IURC) concerning, among other things, certain merger-related affiliate agreements, the sharing of merger-related benefits with customers, and deferred accounting of certain merger-related costs. On December 15, 2005, PSI filed with the IURC a settlement agreement reached with the staff of the IURC, the Indiana Office of Utilities Consumer Counsel and the PSI Industrial Group. Settlement hearings were held in January 2006 and a final order is expected in March 2006.

• In July 2005, Duke filed an application with the state utility regulatory agency in North Carolina. The application requests both the authorization to enter into a business combination transaction and the approval of various affiliate agreements. Hearings were held in January 2006 and a final order is expected in March 2006.

• Special meetings of shareholders of both companies for the purpose of voting on the merger will be held on March 10, 2006.

The merger agreement also provides that Duke and Cinergy will use their reasonable best efforts to transfer five generating stations located in the midwest from Duke to CG&E. This transfer will require regulatory approval by the FERC and, with respect to one plant located in Indiana the IURC. The FERC approved this transaction in December 2005. CG&E and the Duke affiliate that owns the interest in the Indiana plant filed an application with the IURC requesting approval for the transfer (as well as the declination by the IURC of jurisdiction over CG&E following the transfer) in October 2005. A final order approving the transfer and the IURC’s declination of jurisdiction over CG&E was received in February 2006. Duke and Cinergy intend to effectuate the transfer as an equity infusion into CG&E at book value. In conjunction with the transfer, Duke Capital LLC, a subsidiary of Duke, and CG&E intend to enter into a financial arrangement covering a multi-year period, to eliminate any potential cash shortfalls that may result from CG&E owning and operating the five stations. At this time, we cannot predict the outcome of this matter.

The merger agreement contains certain termination rights for both Duke and Cinergy, and further provides that, upon termination of the merger agreement under specified circumstances, a party would be required to pay the other party’s fees and expenses in an amount not to exceed $35 million and/or a termination fee of $300 million in the case of a fee payable by Cinergy to Duke or a termination fee of $500 million in the case of a fee payable by Duke to Cinergy. Any termination fee would be reduced by the amount of any fees and expenses previously reimbursed by the party required to pay the termination fee.

Although Management believes that the merger should close in the first half of 2006, the actual timing of the transaction could be delayed or the merger could be abandoned by the parties in the event of the inability to obtain one or more of the required regulatory approvals on acceptable terms.

BUSINESS SEGMENTS

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

• Regulated Business Unit (Regulated);

• Commercial Business Unit (Commercial); 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, 2005.

See Note 18 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for financial information by business segment.

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 ratemaking 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 57,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.6 million customers as of December 31, 2005. Regulated operated approximately 10,062 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 511,000 customers as of December 31, 2005. 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 this responsibility; and

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

Generation – Fuel Supply and Emission Allowances

As of December 31, 2005, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Regulated’s generating plants was 7,543 megawatt (MW). Approximately 73 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, Kentucky and Illinois. The price of coal has increased significantly in 2005 and 2004 as compared to prior years. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, which has increased reliance on coal-fired generation, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, we have 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 substantially all of our expected 2006 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 – Liquidity and Capital Resources” 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 1,751 MW, including the 488 MW Wheatland facility acquired in May 2005. For more information on the Wheatland acquisition, see “Electric Industry – Indiana” in “Item 7. MD&A – Future Expectations/Trends.” 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 “Item 7. MD&A – Market Risk Sensitive Instruments.”

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 FERC and the KPSC. This five-year agreement is a negotiated fixed-rate contract with CG&E.

The KPSC has approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E. Under this new plan, CG&E transferred ownership of approximately 1,100 MWs of electric generating capacity to ULH&P in January 2006. This capacity was used to service the aforementioned ULH&P power supply contract. The assets were acquired at net book value and will not affect electric rates for ULH&P’s customers in 2006. See “Electric Industry – Kentucky” in “Item 7. MD&A – Future Expectations/Trends” for additional information.

Cinergy is studying the feasibility of constructing an integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would be a majority owner of the facility and operate it. An IGCC plant turns coal to gas, removing most of the sulfur dioxide (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 upstream of the combustion process at a lower cost than conventional plants. In August 2005, PSI and Vectren Energy Delivery of Indiana, Inc. filed a joint petition at the IURC seeking cost recovery of the feasibility study as well as engineering and preconstruction costs associated with the consideration and exploration of constructing an IGCC plant. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the 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 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 nitrogen oxides (NOX) in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with SO2 and NOX emission reduction requirements. In 2005, the average market prices of SO2 allowances rose more than 100 percent from 2004 and more than 400 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 provide for reliability of regional bulk power supply. Beginning January 1, 2006, ReliabilityFirst will assume the functions of ECAR. ReliabilityFirst is designed to create a single regional reliability council under the North American Electric Reliability Council structure to include member companies from the ECAR, Mid-America Interconnected Network, Inc., and Mid-Atlantic Area Council Regional Reliability Councils. ReliabilityFirst’s purpose is to create a uniform set of reliability standards for the combined regions, with a goal of preserving and enhancing electric service reliability and security for the interconnected electric systems within the region. Cinergy has joined ReliabilityFirst as a Transmission Company.

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. In 2005, the Midwest ISO began administering an energy market within its footprint.

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 administers energy markets utilizing Locational Marginal Pricing (LMP) (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. See “Midwest ISO” for further detail regarding the Midwest ISO energy markets.

Transmission and Distribution Cost Recovery

A transmission cost recovery mechanism was established under CG&E’s RSP to permit CG&E to recover Midwest ISO charges. CG&E filed a distribution base rate case to recover certain distribution costs, effective January 1, 2006 and we have deferred certain costs in 2004 and 2005 pursuant to its RSP. The parties to the proceeding have agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $51 million. See “CG&E Electric Rate Stabilization Plan” for additional information.

PSI has received IURC approval for the recovery of Midwest ISO 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. However, due to market conditions in the spring of 2005, a greater portion of firm supply was acquired for the summer. In 2005, firm supply purchase commitment agreements provided approximately 98 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 25-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements up to 3 years in advance of the delivery month. 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, 2005, CG&E and ULH&P, combined, had hedged approximately 55 percent of their winter 2005/2006 base load requirements. See the “Gas Industry” section of “Item 7. MD&A – Future Expectations/Trends” 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.

Natural gas prices remained in the $8 - $9 per thousand cubic feet (Mcf) range through most of the summer due primarily to the warmer than normal summer and the increased use of gas to fire electric generation peaking units. Extensive damage to the natural gas infrastructure along the Gulf Coast caused by Hurricanes Katrina and Rita pushed the price of natural gas into the
$12 - $14 per Mcf range by late September. Natural gas prices remained in the $12 per Mcf range for the remainder of 2005. Winter delivery prices for early 2006 remained in the $11 - $12 per Mcf range in the midwest or about 40 percent greater than last winter. Forward prices for the remainder of 2006 have now fallen below $10 per Mcf as more of the damaged Gulf Coast infrastructure comes online. Price movement is usually driven by the effects of weather conditions, availability of supply, and changes in demand and storage inventories. Currently, neither CG&E’s nor ULH&P’s gas delivery operations profit from changes in the cost of natural gas because natural gas purchase costs are passed directly to the customer dollar-for-dollar under the gas cost recovery mechanism that is mandated under state law.

Revenue Data and Customer Base

Regulated’s revenue is derived from the sale of gas and power to its customers, which are primarily retail. 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	2005				2004				2003
	Electric		Gas		Electric		Gas		Electric		Gas

Cinergy	77	%	23	%	76	%	24	%	76	%	24	%
CG&E and subsidiaries	44		56		45		55		46		54
PSI	100		—		100		—		100		—
ULH&P	62		38		65		35		67		33

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.

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 – Ohio” in “Item 7. MD&A – Future Expectations/Trends” for further detail of key elements of Ohio deregulation. Commercial also performs energy risk management activities, provides customized energy solutions and is responsible for our limited international operations. See “Item 7. MD&A – Market Risk Sensitive Instruments” 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 various cost recovery mechanisms;

• Portfolio Optimization – Describes Commercial’s efforts to optimize its non-regulated generation portfolio;

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

• CG&E Electric Rate Stabilization Plan – Describes CG&E’s RSP as approved by the PUCO in 2004;

• 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;

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

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

Generation – Fuel Supply and Emission Allowances

As of December 31, 2005, 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 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, Wyoming, and Colorado. In 2005 CG&E began purchasing low-sulfur coal produced in Wyoming’s Powder River Basin to reduce fuel costs and further reduce sulfur dioxide emissions compared to other coal sources. The price of coal has increased significantly in 2005 and 2004 as compared to prior years. Contributing to the rise in the price of coal are (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, which has increased reliance on coal-fired generation, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, we have 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 substantially all of our expected 2006 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 – Liquidity and Capital Resources” 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 “Item 7. MD&A – Market Risk Sensitive Instruments.”

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 SO2 and NOX in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with SO2 and NOX emission reduction requirements. In 2005, the average market prices of SO2 allowances rose more than 100 percent from 2004 and more than 400 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 RSP, retail fuel and emission allowance costs are recovered through a cost recovery 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 (POLR) charge from non-residential customers from 2005 through 2008 and from residential customers from 2006 through 2008. See “CG&E Electric Rate Stabilization Plan” as previously discussed.

The KPSC has approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E. Under this new plan, CG&E transferred ownership of approximately 1,100 MWs of electric generating capacity to ULH&P in January 2006, which was previously part of CG&E’s capacity used to service ULH&P under the previous power supply contract. The assets were acquired at net book value.

Portfolio Optimization

Commercial attempts to optimize the value of its non-regulated generation portfolio, which includes generation assets (power and capacity), fuel, and emission allowances. The portfolio is managed through a mix of real-time and forward sales of power and the corresponding purchase of fuel (primarily coal) and emission allowances.

When power is sold forward, we typically purchase the fuel and emission allowances required to produce the power, thereby locking in our eventual margin at the time of delivery. The market values of these commodities change independently over time. At times, the value of the fuel and emission allowances becomes greater than that of the output of electricity. In these instances, we will purchase forward power to be used to deliver against forward power sales, and in turn sell the fuel and/or emission allowances.

Emission allowances and the majority of fuel contracts typically follow the accrual method of accounting. However, generally accepted accounting principles (GAAP) requires that certain forward purchases of coal and forward sales of power (those classified as derivatives) use the mark-to-market (MTM) method of accounting. This differing accounting treatment for the various components of the generation portfolio can lead to volatility in reported earnings. Based on projected generation, we have sufficient fuel and emission allowances to meet our

non-retail forward power sales commitments over the next several years, and we will continue to evaluate and optimize our generation resources to produce the best economic returns for these assets.

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.

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, 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 sell and purchase natural gas at wholesale and engage in the trading of derivative commodity instruments.

Marketing & Trading also enters into contracts to store natural gas and deliver in future periods with higher prices (typically winter). These contracts follow the accrual method of accounting, however, the derivative contracts hedging the gas are required, under GAAP, to be accounted for under the MTM method of accounting. These differing accounting treatments can lead to volatility in reported earnings.

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

CG&E Electric Rate Stabilization Plan

CG&E operates under a RSP which was approved by the PUCO in November 2004, and which expires December 31, 2008. The major features of the RSP are as follows:

• POLR Charge: CG&E collects a POLR charge from non-residential customers effective January 1, 2005, and from residential customers effective January 1, 2006. The POLR charge consists of the following discrete charges:

• Annually Adjusted Component - intended to provide cost recovery primarily for environmental compliance expenditures. Approximately $16 million was collected in 2005 and approximately $54 million is anticipated for 2006 collections.

• Infrastructure Maintenance Fund Charge – intended to compensate CG&E for committing its physical capacity. Approximately $20 million was collected in 2005 and approximately $33 million is anticipated for 2006.

• System Reliability Tracker – intended to provide actual cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs.

• Generation Rates and Fuel Recovery: A market rate has been established for generation service. A component of the market rate is a fuel cost recovery mechanism that is adjusted quarterly for fuel, emission allowances, and certain purchased power costs, that exceed the amount originally included in the rates frozen in the CG&E transition plan. These new rates were applied to non-residential customers beginning January 1, 2005 and to residential customers beginning January 1, 2006. See “CG&E Electric Rate Filing” in “Item 7. MD&A – Future Expectations/Trends” for more information.

• Transmission Cost Recovery: A transmission cost recovery mechanism was established beginning January 1, 2005 for non-residential customers and beginning January 1, 2006 for residential customers. The transmission cost recovery mechanism is designed to permit CG&E to recover Midwest ISO charges, all FERC approved transmission costs, and all congestion costs allocable to retail ratepayers that are provided service by CG&E.

Energy Services

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

Commercial, through Cinergy Capital & Trading, Inc. (Capital & Trading), owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. As of December 31, 2005, Cinergy has produced and sold approximately 12 million tons of synthetic fuel at these facilities. The synthetic fuel produced at these facilities qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29/45K 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 “Synthetic Fuel Production” in “Future Expectations/Trends.”

International

As of December 31, 2005, we had minority ownership interests in (1) a generation asset located in Kenya capable of producing approximately 18 MW of electricity and 460 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in Greece and Zambia, 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.

Competition

Commercial primarily 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.

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. While generation rates remained frozen for residential customers in 2005, non-residential customers began paying generation rates and charges established in CG&E’s RSP. Under the RSP, CG&E’s non-residential retail customers that choose to receive their electric generation from another certified supplier may avoid CG&E generation and fuel charges, as well as a number of the discrete riders that comprise its POLR charge. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:

	MW at December 31(1)		MWhs For the Years Ended December 31(2)		Switching Percentage at December 31(3)
Revenue Class	2005	2004	2005	2004	2005		2004

Residential	53	75	269,654	334,224	2.73	%	4.07	%
Commercial	94	339	1,497,591	1,722,822	6.27	%	19.17	%
Industrial	18	226	1,133,026	1,376,210	2.57	%	17.89	%
Other Public Authorities	22	89	244,661	284,214	9.64	%	19.09	%
Total	187	729	3,144,932	3,717,470

(1) Represents the summation of each switched customer’s peak demand during the past year.

(2) Megawatt hours (MWhs) are total CG&E MWhs transported for all customers.

(3) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand. The decreases in switching percentages represent returning customers.

Commercial’s operating revenue is also derived by selling excess generation to wholesale customers in the midwest region of the United States. In addition, Commercial markets and trades electricity and natural gas primarily to 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.

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, including offering broadband over power line services.

MIDWEST ISO

The Midwest ISO is a regional transmission organization established in 1998 as a non-profit organization which maintains functional control over the combined transmission systems of its members, including Cinergy. In March 2004, the Midwest ISO filed with the FERC proposed changes to its existing transmission tariff to add terms and conditions to implement a centralized economic dispatch platform supported by a Day-Ahead and Real-Time Energy Market design, including LMP and Financial Transmission Rights (FTRs) (Energy Markets Tariff). The FERC has issued orders that, among other things, approved the start-up of the Energy Markets Tariff which occurred April 1, 2005. The FERC issued orders in response to requests for rehearing on certain matters in the FERC’s original orders. Cinergy has appealed the FERC orders to a Federal appeals court.

Specifically, the Energy Markets Tariff manages system reliability through the use of a market-based congestion management system and includes a centralized dispatch platform, the intent of which is to dispatch the most economic resources to meet load requirements reliably and efficiently in the Midwest ISO region, which covers a large portion of 15 midwestern states and one Canadian province. The Energy Markets Tariff uses LMP (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses), and the allocation or auction of FTRs, which are instruments that hedge against congestion costs occurring in the Day-Ahead market. The Energy Markets Tariff also includes market monitoring and mitigation measures as well as a resource adequacy proposal, that proposes both an interim solution for participants providing and having access to adequate generation resources and a proposal to develop a long-term solution to resource adequacy concerns. The Midwest ISO performs a day-ahead unit commitment and dispatch forecast for all resources in its market and also performs the real-time resource dispatch for resources under its control on a five minute basis. CG&E and PSI are recovering costs that they incur related to the Energy Markets Tariff through various cost recovery mechanisms. ULH&P is currently under a rate freeze and cannot recover incremental costs attributable to its participation in the Midwest ISO in 2006; however, ULH&P is under an order from the KPSC to file a rate case in 2006 and will request, among other things, recovery of Midwest ISO related costs beginning in January 2007. We continue to work with the Midwest ISO to monitor the implementation of the new market and at this time we do not believe it will have a material impact on our results of operations or financial position.

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, 2006:

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

IBEW(1)	1,027	1,259	66	194
USWA(2)	293	—	80	65
UWUA(3)	388	—	58	323
Various Union Organizations	—	—	—	83
Non-Bargaining	193	348	17	2,881
	1,901	1,607	221	3,546

(1) IBEW #1347 contract will expire on April 1, 2006, IBEW #1393 contract expired on April 30, 2005 and was renegotiated and is now set to expire on April 30, 2010 and IBEW #352 contract expired on February 5, 2005 and was renegotiated and is now set to expire on February 5, 2008.

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

(3) UWUA, IUU Local 600 Contract expired on March 31, 2005 and was replaced with a new contract set to expire on April 1, 2008.

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

(5) Includes 2,990 Services’ employees who provide services to our operating utilities and other non-regulated companies. In conjunction with the pending merger, there is an anticipated reduction of approximately 1,500 employees of the combined company’s approximate 29,350 employees, as of the May 2005 merger announcement, in various departments leading up to and following consummation of the merger.

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, NOX, and SO2 emissions. Cinergy is able to recover certain costs of this environmental compliance through various trackers set up with Cinergy’s respective state regulatory agencies. In 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule and the Clean Air Mercury Rule, which will require additional environmental compliance costs. See the “Environmental Issues” section in “Item 7. MD&A – Liquidity and Capital Resources” 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 – Future Expectations/Trends” for the following discussions:

• Regulatory Outlook and Significant Rate Developments;

• FERC;

• Gas Industry; and

• Other Matters.

RISK FACTORS

ITEM 1A. RISK FACTORS

RISK FACTORS

The risk factors described below should be carefully considered.

Risks Relating to Our Business

Our Regulated’s revenues, earnings, and results are dependent on state legislation and regulation that affect electric generation, distribution, and related activities, which may limit our ability to recover costs.

Our Regulated business unit is regulated on a cost-of-service/rate-of-return basis subject to the statutes and regulatory commission rules and procedures of Kentucky, Indiana, and Ohio. If our earnings exceed the returns established by our state regulatory commissions, our retail electric rates may be subject to review by the commissions and possible reduction, which may decrease our future earnings.

Our sales may decrease if we are unable to gain adequate, reliable, and affordable access to transmission and distribution assets.

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell to the wholesale market, as well as the natural gas we purchase to supply to our gas customers. FERC’s power transmission regulations require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis; however, not all markets are as open and accessible as needed. If transmission is disrupted, or if transmission capacity is inadequate, our ability to sell and deliver products may be hindered. Such disruptions could also hinder our providing electricity or natural gas to our retail electric and gas customers and may materially adversely affect our business.

The different regional power markets have changing regulatory structures, which could affect our growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets, such as California, have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of our wholesale power marketing and trading business.

Competition in the unregulated markets in which we operate may adversely affect the growth and profitability of our business.

We may not be able to respond in a timely or effective manner to the many changes designed to increase competition in the electric industry. To the extent competitive pressures increase, the economics of our business may come under long-term pressure.

In addition, regulatory changes have been proposed to increase access to electricity transmission grids by utility and non-utility purchasers and sellers of electricity. These changes could continue the disaggregation of many vertically integrated utilities into separate generation, transmission, distribution, and retail businesses. As a result, a

significant number of additional competitors could become active in the wholesale power generation segment of our industry.

We may also face competition from new competitors that have greater financial resources than we do, seeking attractive opportunities to acquire or develop energy assets or energy trading operations in the United States. These new competitors may include sophisticated financial institutions, some of which are already entering the energy trading and marketing sector, and international energy players, which may enter regulated or unregulated energy businesses. This competition may adversely affect our ability to make investments or acquisitions.

We rely on access to short-term money markets and longer-term capital markets to finance our capital requirements and support our liquidity needs, and our access to those markets can be adversely affected by a number of conditions, many of which are beyond our control.

Our business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from our assets. Accordingly, we rely on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from our operations and to fund investments originally financed through debt instruments with disparate maturities. If we are not able to access capital at competitive rates, our ability to finance our operations and implement our strategy will be adversely affected.

Market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity, gas, and natural gas liquids; terrorist attacks or threatened attacks on our facilities or unrelated energy companies; or the overall health of the energy industry. Restrictions on our ability to access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth.

We maintain revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other of our affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements.

We will be exposed to market risk and may incur losses from the trading operations and/or activities we take to mitigate our commodity exposure.

We have trading operations that primarily consist of contracts to buy and sell commodities, including contracts for electricity, natural gas, and other commodities that are settled by the delivery of the commodity or cash. Our trading portfolios also include financial derivatives, including swaps, futures, and options. If the values of these contracts or derivatives change in a direction or manner that we do not anticipate, we could realize material losses from our trading activities.

In order to manage our financial exposure related to commodity price fluctuations, primarily with respect to power and natural gas, coal, and emission allowances, our risk management operations routinely enter into contracts to hedge the value of our assets and operations, including fixed-price, forward, physical purchase and sales contracts, futures, financial swaps, and option contracts traded in over-the-counter markets or on exchanges.

Our risk management systems, however, may not always be implemented properly or may not always function as planned. In particular, if prices of commodities significantly deviate from historical prices or if the price volatility or distribution of those changes deviates from historical norms, our risk management systems may not protect us from significant losses. To the extent we have unhedged positions or our hedging strategies do not work as planned, fluctuating commodity prices could cause our sales, purchases, and net income to be volatile. In

addition, certain types of economic hedging activity may not qualify for hedge accounting under generally accepted accounting principles, resulting in increased volatility in net income.

We are exposed to credit risk of counterparties with whom we do business.

Adverse economic conditions affecting, or financial difficulties of, counterparties we do business with could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial condition, or results of operations.

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.

Our costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions made to the plans. While we comply with the funding requirements under the Employee Retirement Income Security Act of 1974, as of September 30, 2005, the latest valuation date for our pension plan obligations exceeded the value of plan assets by approximately $582 million. See “Pension and Other Postretirement Benefits” in “Item 7. MD&A – Liquidity and Capital Resources” and Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information. Without sustained growth in the pension investments over time to increase the value of our plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing our cash flows and could negatively affect our results of operations.

Under Cinergy’s holding company structure, the payment of dividends to shareholders is subject to the ability of its subsidiaries to pay dividends to it.

Cinergy is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Cinergy’s ability to pay dividends on its common stock will depend on the payment to it of dividends by its operating subsidiaries. These subsidiaries’ payments of dividends, in turn, depend on their results of operations, cash flows, and federal and state regulatory constraints. In addition, until consummation or termination of the merger with Duke, Cinergy is prohibited from paying dividends in excess of its historical levels without the prior consent of Duke.

We could incur a significant tax liability and our results of operations and cash flows may be negatively affected if the Internal Revenue Service denies or otherwise makes unusable certain tax credits related to our coal and synthetic fuel business or if such credits are phased out based on crude oil prices.

Cinergy’s sale of synthetic fuel intended to qualify for tax credits in accordance with Section 29/45K of the Internal Revenue Code has generated $339 million in tax credits through December 31, 2005. The Internal Revenue Service (IRS) is currently auditing Cinergy for the 2002, 2003 and 2004 tax years. If the IRS were to successfully challenge Cinergy’s Section 29/45K tax credits related to synthetic fuel, and such challenges are successful, this could result in the disallowance of up to all $339 million in previously claimed Section 29/45K tax credits and a loss of our ability to claim future Section 29/45K tax credits for synthetic fuel produced by such facilities.

estimates of crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007 the amount of the tax credits could be reduced.

We are currently involved in litigation with the United States and several states and environmental groups regarding certain environmental matters.

Cinergy is currently involved in litigation in which the Environmental Protection Agency (EPA) is alleging various violations of the Clean Air Act (CAA). Specifically, the lawsuit against Cinergy alleges that Cinergy violated the CAA by not obtaining permits for various projects at its owned and co-owned generating stations. Additionally, the Cinergy suit claims that Cinergy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s state implementation plan provisions governing particulate matter at one of its generating stations. Three northeast states and two environmental groups have intervened in the Cinergy case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal and set a briefing schedule. As a result, the district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. There are a number of other legal issues currently before the district court judge, and the case is currently in discovery. A second lawsuit being defended by one of Cinergy’s co-owners involves similar allegations and is also pending.

We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and which may impact or limit our business plans, or expose us to environmental liabilities.

We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions (such as controlling greenhouse-gas emissions), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations, and litigation may arise the outcome of which we cannot predict.

For example, the EPA recently issued the Clean Air Interstate Rule, formerly the Interstate Air Quality Rule, which requires reductions in SO2 and NOX emissions in order to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards and established a two-phase, regional cap and trade program for SO2 and NOX and issued the Clean Air Mercury Rule, which requires reductions in mercury emissions from coal-fired power plants through a similar two phase cap and trade program. Over the 2006-2010 time period, Cinergy expects to spend approximately $1.4 billion to reduce mercury, SO2, and NOX emissions. These projected expenditures 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. Although we believe that we are legally entitled to recover these costs, if we cannot recover these costs in a timely manner, or in an amount sufficient to cover our actual costs, our financial conditions and results of operations could be materially and adversely impacted. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations, or cash flows and our utilities’ businesses.

Increased competition resulting from deregulation or restructuring efforts, including from the recently enacted Energy Policy Act of 2005, could have a significant adverse financial impact on us and our utility subsidiaries and consequently on our results of operations and cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins, or increased costs of capital. We cannot predict the extent and timing of entry by additional competitors into the electric markets. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial condition, results of operations, or cash flows.

Ohio has enacted electric generation deregulation legislation. Our Ohio residential and non-residential customers are served under a recently approved RSP, that runs through December 31, 2008. At this time, it is difficult to predict how the regulatory environment will look after the RSP ends.

Efforts associated with completing the merger with Duke are complex and may divert management’s focus and resources from other strategic opportunities.

Risks Related to the Industry

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond our control.

Sustained downturns or sluggishness in the economy generally affect the markets in which we operate and negatively influence our energy operations. Declines in demand for electricity and gas as a result of economic downturns in our franchised electric and gas service territories will reduce overall electricity and gas sales and lessen our cash flows, especially as our industrial customers reduce production and, therefore, consumption of electricity and gas. Although Regulated’s business is subject to regulated allowable rates of return and recovery of fuel and emission allowance costs, and our gas transmission business is subject to mandated tariff rates, overall declines in electricity sold or the volume of gas shipped as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.

We also sell electricity into the wholesale market under both short-term and long-term contracts and enter into contracts to purchase and sell electricity, natural gas, and natural gas liquids as part of our energy marketing and trading operations. With respect to such transactions, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power, natural gas, coal, and emission allowances in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time and could reduce our revenues and margins and thereby diminish our results of operations.

Lower demand for the electricity we sell and varying prices for electricity, natural gas, coal, and emission allowances result from multiple factors that affect the markets where we sell electricity including:

• weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively;

• supply of and demand for energy commodities;

• illiquid markets including reductions in trading volumes, which result in lower revenues and earnings;

• general economic conditions which impact energy consumption particularly in which sales to industrial or large commercial customers comprise a significant portion of total sales;

• transmission or transportation constraints or inefficiencies, which impact our merchant energy operations;

• availability of competitively-priced alternative energy sources, which are preferred by some customers over electricity produced from coal or gas plants, and of energy-efficient equipment which reduces energy demand;

• electric generation capacity surpluses which cause our merchant energy plants to generate and sell less electricity at lower prices and may cause some plants to become non-economical to operate;

• capacity and transmission service into, or out of, our markets;

• natural disasters, acts of terrorism, wars, embargoes, and other catastrophic events to the extent they affect our operations and markets; and

• federal and state energy and environmental regulation and legislation.

Our business is subject to extensive regulation that will affect our operations and costs.

We are subject to regulation by FERC, by federal, state, and local authorities under environmental laws and by state public utility commissions under laws regulating our businesses. Regulation affects almost every aspect of our businesses, including, among other things, our ability to: take fundamental business management actions; determine the terms and rates of our transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; engage in transactions between our utilities and other subsidiaries and affiliates; and pay dividends. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. However,

changes in regulation (including re-regulating previously deregulated markets) can cause delays in or affect business planning and transactions and can substantially increase our costs.

Certain events in the energy markets beyond our control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets which could have a negative impact on our financial condition or results of operations or access to capital.

Due to certain events in the energy markets, regulated energy companies have been under increased scrutiny by regulatory bodies, capital markets, and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including new accounting standards that could change the way we are required to record revenues, expenses, assets, and liabilities. These types of regulations could have a negative impact on our financial condition or results of operations or access to capital.

Potential terrorist activities or military or other actions could adversely affect our business.

The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic, and financial market instability and volatility in prices for natural gas and oil which could affect the market for our gas operations and may materially adversely affect us in ways we cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the United States and its allies could be directed against companies in our industry operating in the United States.

Increased environmental regulation and liabilities could subject us to significant compliance and remediation costs that adversely affect our results of operations.

Our operations are subject to extensive environmental regulation pursuant to a variety of United States, and other federal, provincial, state, and municipal laws and regulations. Such environmental regulation imposes, among other things, restrictions, liabilities, obligations, and potential enforcement in connection with the generation, handling, use, storage, transportation, treatment, and disposal of hazardous substances and waste, and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites, and other properties associated with our operations be operated, maintained, and reclaimed to the satisfaction of applicable regulatory authorities.

Compliance with environmental regulations can require significant expenditures, including expenditures for cleanup costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines and penalties. The steps we take to ensure our facilities are in compliance could be prohibitively expensive, and we may be required to shut down or alter the operation of our facilities, which may cause us to incur losses. Further, our regulatory rate structure and our contracts with clients may not necessarily allow us to recover capital costs we incur to comply with new environmental regulations. Also, we may not be able to obtain or maintain, from time to time, all required environmental regulatory approvals for our development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain and comply with them, or if environmental regulations change and become more stringent, the operation of our facilities or the development of new facilities could be prevented, delayed, or become subject to additional costs. Should we fail to comply with all applicable environmental laws, we may be subject to penalties and fines imposed against us by regulatory authorities. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

In addition, we are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of our power generation facilities and natural gas assets which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against some environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses.

UNRESOLVED STAFF COMMENTS

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

PROPERTIES

ITEM 2. PROPERTIES

REGULATED

Electric

Domestic Power Generation

Regulated’s domestic power generating stations’ total capacity, reflected in MW’s, as of December 31, 2005, is 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

1,751

259

7,543

(1) This table includes only our portion of the total capacity for the jointly-owned plants and does not include certain generating capacity transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry – Kentucky” in “Item 7. MD&A – Future Expectations/Trends.” The transferred generating assets became Regulated assets upon transfer.

During 2005, Regulated’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 75 percent and a utilization factor of 86 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 88 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(1)
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
12	Wheatland	Gas	488
		Total	7,543

(1) This map does not include certain generating assets that were transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry – Kentucky” in “Item 7. MD&A – Future Expectations/Trends.”

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(1)	Systems(1)		Capacity
	(circuit miles)	(circuit miles)		(kilovolt-amperes)(2)

CG&E and subsidiaries
CG&E	1,567	16,964		21,616,788
ULH&P	106	2,943		1,464,678
Other subsidiaries	40	—		—
Total CG&E and subsidiaries	1,713	19,907		23,081,466
PSI	5,369	29,694	(3)	31,014,814

Total	7,082	49,601		54,096,280

(1) Circuit Miles include only our proportionate share for the jointly-owned lines.

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

(3) Prior to 2005, PSI did not include secondary lines as part of their Distribution System Circuit Miles. As of December 31, 2005, 8,317 circuit miles of secondary lines were included consistent with other registrants.

At the end of 2005, 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 ISO holds functional control of Regulated’s transmission systems.

Gas

As of December 31, 2005, the natural gas transmission and distribution systems of Cinergy and CG&E and its subsidiaries had approximately 10,062 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 belong to CG&E, including 7.5 million gallons belonging to ULH&P). As of December 31, 2005, Cinergy had 15.1 million gallons of liquid propane in storage (of which 12.4 million gallons belong to CG&E, including 5.4 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.

COMMERCIAL

Electric

Domestic Power Generation

Commercial’s domestic power generating stations’ total electric capacity, reflected in MW, as of December 31, 2005, is 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

CG&E	9	4,186	736	324	5,246
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. The table also includes certain generating capacity transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry – Kentucky” in “Item 7. MD&A – Future Expectations/Trends.” The transferred generating assets became Regulated assets upon transfer.

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

During 2005, Commercial’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 72 percent and a utilization factor of 86 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 85 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(2)	Gas	564
3	Miami Fort(2)	Coal/Oil	962
4	East Bend(2)	Coal	414
5	W. C. Beckjord	Coal/Oil	1,107
6	W.M. 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.
(2)	All of Woodsdale and East Bend and a portion of Miami Fort (163 MW) were transferred to Regulated in January 2006. See “Electric Industry – Kentucky” in “Item 7. MD&A – Future Expectations/Trends.”

Cogeneration

As of December 31, 2005, Cinergy had ownership interests in and/or operated 28 domestic cogeneration facilities capable of producing 5,335 MW of electricity, 4,117 MW equivalents of steam and 297 MW equivalents of chilled water. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.

Synthetic Fuel

Capital & Trading owns two coal-based synthetic fuel production facilities, which convert coal into synthetic fuel for sale to a third party. See “Other Matters – Synthetic Fuel Production” in “Item 7. MD&A – Future Expectations/Trends” for additional information regarding this business initiative.

International

PEAK LOAD

In July 2005, we experienced record peak loads of 12,001 MW, 5,607 MW, and 6,409 MW for Cinergy, CG&E, and PSI, respectively.

LEGAL PROCEEDINGS

ITEM 3. LEGAL PROCEEDINGS

CLEAN AIR ACT 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 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 Plan (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 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 Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’s Cayuga, Gallagher, Wabash River, and Gibson Stations, 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. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal and set oral arguments for May 2006. In February 2006, the district court ruled that in carrying its burden of proof, the defendant can look to industry practice in proving a particular project was routine. The district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. Not withstanding the appeal, there are a number of other legal issues currently before the district court judge.

In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio 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 United States District Court for the Southern District of Ohio 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. This matter was heard in trial in July 2005. A decision is pending.

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 station operated by DP&L and jointly-owned by DP&L, CSP, and 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 CG&E, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.

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 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. The plaintiffs are seeking an injunction requiring each defendant to cap its CO2 emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. 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 NOX SIP Call. In June and July 2004, Gibson Station temporarily shut down the equipment on these units due to a concern that portions of the plume from those units’ stacks appeared to break apart and descend to ground level, at certain times, under certain weather conditions. After we developed a protocol with several other parties regarding the use of control equipment, one of the parties sought a court preliminary injunction to enforce the protocol. The court initially granted the preliminary injunction, but on appeal the preliminary injunction was dissolved and the case was dismissed.

In April 2005, we completed the installation of a permanent control system to address this issue. The new control system will support all five Gibson Station generating units. 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, and Ohio laws against nuisance and common law nuisance. The plaintiffs have filed a number of additional notices of intent to sue and two lawsuits raising claims similar to those in the original claim. One lawsuit was dismissed on procedural grounds and the remaining two have been consolidated. The plaintiff filed a motion for class certification, which is fully briefed and pending decision. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or results of operations. We intend to defend this lawsuit vigorously in court.

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. 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 nine sites. The Indiana Department of Environmental Management oversees investigation and cleanup of all of these 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. PSI settled, in principle, 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 has appealed this decision. At the present time, PSI cannot predict the outcome of this litigation, including the outcome of the appeal.

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 CLAIMS LITIGATION

PSI and CG&E have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are PSI cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors in the construction and maintenance of 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. 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 on a negligence claim and a verdict for PSI on punitive damages. PSI appealed this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. PSI paid the judgment of approximately $630,000 in the fourth quarter. In addition, PSI has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of PSI generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, PSI estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.

CG&E has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, CG&E is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to CG&E.

DUNAVAN WASTE SUPERFUND SITE

In July and October 2005, PSI received notices from the EPA that it has been identified as a de minimus potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act at the Dunavan Waste Oil Site in Oakwood, Vermilion County, Illinois. At this time, PSI does not have any further information regarding the scope of potential liability associated with this matter.

MERGER LAWSUIT

In May 2005, a purported shareholder class action was filed in the Court of Common Pleas in Hamilton County, Ohio against Cinergy and each of the members of the Board of Directors. The lawsuit alleged that the defendants breached their duties of due care and loyalty to shareholders by agreeing to the merger agreement between Duke and Cinergy and was seeking to either enjoin or amend the terms of the merger. Cinergy and the individual defendants filed a motion to dismiss this lawsuit in July 2005, which was granted in November of 2005. An appeal was not filed by the plaintiffs and the case is closed.

OHIO EPA PENALTY ON CINERGY POWER GENERATION SERVICES

In October 2005, the Ohio EPA proposed a civil penalty of $102,000 on Cinergy Power Generation Services to settle multiple, unrelated alleged violations occurring at multiple CG&E generating stations over the past several years. In December 2005, CG&E settled these allegations for an aggregate of $53,000.

ONTARIO, CANADA LAWSUIT

We understand through newspaper reports that a class action lawsuit was filed in Superior Court in Ontario, Canada against us and approximately 20 other utility and power generation companies alleging various claims relating to environmental emissions from coal-fired power generation facilities in the United States and Canada and damages of approximately $50 billion, with continuing damages in the amount of approximately $4 billion annually. We understand that the lawsuit also claims entitlement to punitive and exemplary damages in the amount of $1 billion. We have not yet been served in this lawsuit, however, if served, we intend to defend this lawsuit vigorously in court. We are not able to predict whether resolution of this matter would have a material effect on our financial position or results of operations.

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 2005.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

PART II

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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
2005
First Quarter	$	41.70	$	39.05
Second Quarter	45.30		38.75
Third Quarter	45.95		41.41
Fourth Quarter	44.60		38.19

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

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, 2006, Cinergy Corp. had 42,705 shareholders of record.

Cinergy Corp. declared dividends on its common stock of $.48 and $.47 per share for each quarter of 2005 and 2004, 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	2005		2004
		(in thousands)

CG&E	First	$	38,296	$	54,926
	Second	65,765		55,612
	Third	65,397		57,971
	Fourth	80,628		67,249

PSI	First	$	51,853	$	28,957
	Second	29,415		28,913
	Third	29,977		26,839
	Fourth	15,000		17,879

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

On January 16, 2006, the Board of Directors of Cinergy Corp. declared dividends on its common stock of $.48 per share, payable February 15, 2006, to shareholders of record at the close of business on February 1, 2006.

See “Dividend Restrictions” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” 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	—	$	—	N/A	N/A
November 1 – November 30	6,782	$	39.75	N/A	N/A
December 1 – December 31	—	$	—	N/A	N/A

SELECTED FINANCIAL DATA

ITEM 6. SELECTED FINANCIAL DATA

	2005			2004			2003			2002			2001
	(in millions, except per share amounts)

Cinergy(1)
Results of Operations:
Operating revenues	$	5,410		$	4,628		$	4,364		$	4,001		$	3,883
Income before discontinued operations and cumulative effect of changes in accounting principles	490			411			438			401			455
Discontinued operations, net of tax(2)	3			(10		)	6			(36		)	(13		)
Cumulative effect of changes in accounting principles, net of tax(3)	(3		)	—			26			(4		)	—
Net income	490			401			470			361			442

Per Share Data:
Earnings per common share (EPS) - basic:
Income before discontinued operations and cumulative effect of changes in accounting principles	2.47			2.27			2.47			2.40			2.86
Discontinued operations, net of tax(2)	0.01			(0.05		)	0.04			(0.22		)	(0.08		)
Cumulative effect of changes in accounting principles, net of tax(3)	(0.01		)	—			0.15			(0.02		)	—
Net income	2.47			2.22			2.66			2.16			2.78
EPS - diluted:
Income before discontinued operations and cumulative effect of changes in accounting principles	2.46			2.23			2.45			2.37			2.83
Discontinued operations, net of tax(2)	0.01			(0.05		)	0.03			(0.22		)	(0.08		)
Cumulative effect of changes in accounting principles, net of tax(3)	(0.01		)	—			0.15			(0.02		)	—
Net income	2.46			2.18			2.63			2.13			2.75
Cash dividends declared per share	1.92			1.88			1.84			1.80			1.80

Balance Sheet Data (at end of period):
Total assets from continuing operations	17,120			14,818			13,950			13,518			12,422
Total assets from discontinued operations	34			164			169			314			370
	17,154			14,982			14,119			13,832			12,792
Long-term debt (including amounts due within one year)	4,746			4,448			4,969			4,188			3,656

CG&E
Results of Operations:
Operating revenues	$	3,061		$	2,511		$	2,382		$	2,137		$	2,247
Income before cumulative effect of changes in accounting principles	301			257			300			264			327
Cumulative effect of changes in accounting principles, net of tax(4)	(3		)	—			31			—			—
Net income	298			257			331			264			327

Balance Sheet Data (at end of period):
Total assets	7,234			6,232			5,809			5,751			5,559
Long-term debt (including amounts due within one year)	1,595			1,594			1,569			1,690			1,205

PSI
Results of Operations:
Operating revenues	$	1,975		$	1,754		$	1,603		$	1,611		$	1,574
Income before cumulative effect of a change in accounting principle	198			165			134			214			162
Cumulative effect of a change in accounting principle, net of tax(5)	—			—			(1		)	—			—
Net income	198			165			133			214			162

Balance Sheet Data (at end of period):
Total assets	6,242			5,450			5,140			4,539			4,864
Long-term debt (including amounts due within one year)	2,194			1,874			1,720			1,372			1,348

(1)	The results of Cinergy also include amounts related to non-registrants.
(2)	See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further explanation.
(3)	In 2005, Cinergy recognized a gain/(loss) on cumulative effect of a change in accounting principal of $(3) million (net of tax) as a result of the recognition of conditional asset retirement obligations. 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 $(4) million (net of tax) as a result of an impairment charge for goodwill related to certain of our international assets.
(4)	In 2005, CG&E recognized a gain/(loss) on cumulative effect of a change in accounting principle of $(3) million (net of tax) as a result of the recognition of conditional asset retirement obligations. 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, 2005, and 2004 was as follows:

	Cinergy
	2005		2004		Change		% Change
	(in millions)

Net income	$	490	$	401	$	89	22	%

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

• Increased gross margins resulting from PSI’s May 2004 base retail electric rate increase and the implementation of CG&E’s rate stabilization plan (RSP) in January 2005;

• Increased non-retail gross margins related to our generation portfolio, including the sale of emission allowances;

• Increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004; and

• Increased Miscellaneous Income (Expense) – Net primarily due to impairment and disposal charges recognized in 2004 on certain investments in the Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure).

These increases were partially offset by:

• Increased fuel, emission allowance, and purchased power costs attributable to CG&E’s fixed price residential customers;

• Timing differences in revenue recognition between certain components of our generation portfolio;

• Decreases in Commercial gas gross margins, primarily due to trading results in the second quarter of 2005;

• Increased Operation and maintenance expense primarily due to regulatory asset amortization, synthetic fuel production costs, and expenses associated with the pending Duke Energy Corporation (Duke)-Cinergy merger; and

• Increased Depreciation expense due to increased depreciation rates and the addition of depreciable plant.

For further information, see “2005 Results of Operations – Cinergy”.

Forward-looking Challenges and Risks

Merger Challenges and Risks

The pending merger between Duke and Cinergy presents significant challenges. The integration of the two companies will be complex and time-consuming, due to the size and complexity of each organization. The principal challenges will be integrating the combined regulated electric utility operations and combining the unregulated wholesale power generation businesses. All of these businesses are complex, and some of the business units are dispersed. Such efforts could also divert management’s focus and resources from other strategic opportunities during the integration process. The pending merger is subject to approvals of numerous governmental agencies and approval of the shareholders of both companies, all of which are discussed in more detail in “Item 1. Business – Pending Merger.” The approval process could delay consummation of the pending merger, impose conditions that could materially impact the combined company, or cause the merger to be abandoned. Both companies will incur significant transaction and merger-related integration costs. Additionally, we will be subject to business uncertainties and contractual restrictions while the merger is pending which could adversely affect our businesses. Although both companies are taking steps to reduce any adverse effects, these uncertainties may impair our ability to attract and retain key personnel until the merger is consummated and for a period of time thereafter, and could cause customers, suppliers, and others to seek to change their existing business relationships with us.

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 March 2005, the Environmental Protection Agency (EPA) finalized two rulemakings that will require significant reductions in sulfur dioxide (SO2), nitrogen oxides (NOX), and mercury emissions from power plants. Numerous states, environmental organizations, industry groups, including some of which Cinergy is a member, and individual companies have challenged various portions of both rules. Additionally, multi-emissions reductions legislation is still being discussed in the Senate, although the outcome of these discussions is still highly uncertain at this time. Presently, greenhouse gas (GHG) emissions, which principally consist of carbon dioxide (CO2), are not regulated, and while several legislative proposals have been introduced in Congress to reduce utility GHG emissions, none have been passed. Nevertheless, we anticipate a mandatory program to reduce GHG emissions will exist in the future. In 2004, Cinergy’s utility operating companies began an environmental construction program to reduce overall plant regulated emissions that is estimated to cost approximately $1.8 billion over 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.

Rising Coal and Emission Allowance Prices

The prices of coal and SO2 emission allowances increased dramatically in 2004, as compared to 2003, and have continued to increase in 2005. Contributing to the increases in coal and SO2 prices have been (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. CG&E’s RSP allows for recovery of fuel and emission allowance expenses effective January 1, 2005 for retail non-residential customers in Ohio and January 1, 2006 for residential customers. We continue to recover these costs from PSI retail customers through previously established rate recovery mechanisms. ULH&P’s rates are frozen through January 1, 2007, the date at which new rates are expected to be implemented. To the extent that these increased fuel and SO2 prices are not offset by regulatory recovery or increases in the market price of power for wholesale transactions, they will negatively impact

ongoing earnings for Cinergy’s utility companies. The impact of these price increases on earnings is discussed in more detail in “2005 Results of Operations” and “2004 Results of Operations.”

Synthetic Fuel

Cinergy produces synthetic fuel that qualifies for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code (IRC) if certain requirements are satisfied. Cinergy currently faces two major uncertainties that could impact our ability to continue to recognize the previous and/or future credits. The Internal Revenue Service (IRS) is currently auditing Cinergy for the 2002, 2003, and 2004 tax years and could challenge Cinergy’s credits. If the IRS were to successfully challenge our credits, this could result in the disallowance of up to all previously claimed and future Section 29/45K tax credits for Cinergy’s facilities. We believe that we operate in conformity with all the necessary requirements to qualify for tax credits under Section 29/45K.

Section 29/45K also provides for a phase-out of the credit based on the average price of crude oil during a calendar year. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007, the amount of the tax credits could be reduced. If oil prices are high enough, we will idle the plants, as the value of the credits would not exceed the net costs to produce the synthetic fuel. Net income related to these facilities for the twelve months ended December 31, 2005 was approximately $58 million. The net book value of our plants at December 31, 2005 was approximately $47 million.

MD&A – 2005 RESULTS OF OPERATIONS - CINERGY

2005 RESULTS OF OPERATIONS – CINERGY

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 the Commercial Business Unit (Commercial) for the years ended December 31, 2005, and 2004 were as follows:

	Cinergy
	Regulated								Commercial
	2005		2004		Change		% Change		2005		2004		Change			% Change
	(in millions)

Electric gross margin(1)	$	1,811	$	1,662	$	149	9	%	$	725	$	616	$	109		18	%
Gas gross margin(2)	263		263		—		—		40		92		(52		)	(57	)

(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, 2005, and 2004 were as follows:

	Cinergy
	2005	2004	Change	% Change

Cooling degree days(1)	1,285	888	397	45	%
Heating degree days(2)(3)	3,846	3,740	106	3

(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 59 degrees, assuming the average temperature is less than 59 degrees.

(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.

Regulated

Gross Margins

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

• A $71 million increase resulting from a higher price received per megawatt hour (MWh), primarily due to PSI’s May 2004 base retail electric rate increase;

• A $45 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and

• A $30 million increase due to growth in non-weather related demand.

These increases were partially offset by a decline of $18 million reflecting rate reductions associated with a property tax adjustment for PSI.

Commercial

Gross Margins

The 18 percent increase in Commercial’s electric gross margins was primarily due to:

• A $46 million increase in margins from power marketing and trading contracts, primarily due to an increase in margins within the midwest market.

• Higher retail margins of $37 million reflecting:

• A $77 million increase in rate tariff adjustments resulting from implementation of CG&E’s RSP in January 2005 (a portion of the total CG&E RSP rate tariff adjustments is reflected in Regulated gross margins);

• A $12 million increase resulting from growth in non-weather related demand, due in part to the return of certain CG&E retail customers to full electric service; and

• A $9 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004.

Partially offsetting these increases was a $53 million increase in fuel, emission allowance, and purchased power costs attributable to CG&E’s fixed price residential customers.

• A $26 million increase in non-retail margins reflecting:

• A $121 million increase resulting from selling emission allowances which were no longer needed to meet our non-retail forward power sales commitments. This gain reflects significant increases in prices of SO2 emission allowances throughout much of 2004 and 2005.

• A $45 million decrease due to timing differences in revenue recognition between certain components of our generation portfolio. Our gross margins reflect $54 million of losses in 2005 and $9 million of losses in 2004 (representing a $45 million change period to period) as a result of forward purchases of coal and forward sales of power and the use of mark-to-market (MTM) accounting. A substantial portion of these losses is expected to reverse in the first quarter of 2006.

• A $33 million decrease due to higher fuel prices.

The 57 percent decrease in Commercial’s gas gross margins was primarily due to the following factors:

• A $41 million decline in financial trading margins, primarily from trading results in the second quarter of 2005; and

• A $23 million decrease due to timing differences in revenue recognition between physical storage activities and the associated derivative contracts that hedge the physical storage. Our year-to-date gross margins reflect $8 million of losses in 2005 and $15 million of gains in 2004 (representing a $23 million change period to period) as a result of derivative contracts and the use of MTM accounting.

Partially offsetting these decreases was a $15 million increase in physical trading margins, primarily from trading results in the third quarter of 2005.

Other Operating Revenues and Costs of Fuel Resold

The 56 percent increase in Other Operating Revenues was primarily due to the following factors:

• A $129 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and tons of coal sold; and

• A $64 million increase in Commercial’s revenues from the sale of synthetic fuel, primarily reflecting revenues from a new facility purchased in the second quarter of 2005.

Costs of fuel resold include Commercial’s costs of coal origination activities and the production of synthetic fuel. These costs have increased in 2005, 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
	2005		2004		Change		% Change
	(in millions)

Operation and maintenance	$	1,349	$	1,231	$	118	10	%
Depreciation	510		454		56		12
Taxes other than income taxes	272		254		18		7

Operation and Maintenance

The 10 percent increase in Operation and maintenance expense was primarily due to the following factors:

• Increased regulatory asset amortization of $45 million related to CG&E’s Regulatory Transition Charge (RTC). This increase reflects accelerated recovery of the regulatory asset due to both (a) the cessation of deferrals for non-residential customers due to the end of the market development period for those customers at the end of 2004 and (b) a reduction in revenues lost from switched customers, which is also recovered through the RTC;

• An increase of $31 million in costs at our synthetic fuel facilities, primarily related to production costs at a new facility purchased in the second quarter of 2005;

• Increased costs of $19 million, primarily associated with the sales of accounts receivable to an unconsolidated affiliate primarily due to increased fees charged by the buyer of the receivables and an increase in the volume of receivables sold;

• Expenses of $12 million related to outside services costs for the pending Duke-Cinergy merger; and

• Increased labor costs, primarily due to severance payments of $14 million and merger related employee retention incentives of $5 million.

These increases were partially offset by decreased outside service and labor costs totaling $13 million related to our continuous improvement initiative in 2004 and decreased employee incentive costs of $6 million.

Depreciation

The 12 percent increase in Depreciation expense was primarily due to (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal, (b) recovery of deferred depreciation costs, and (c) the addition of depreciable plant for pollution control equipment, all of which are recovered from ratepayers.

Taxes Other Than Income Taxes

The seven percent increase in Taxes other than income taxes was primarily due to a $10 million increase in property taxes, $5 million increase in other state taxes, and a $4 million increase in gross receipts tax.

Equity in Earnings of Unconsolidated Subsidiaries

The 30 percent decrease in Equity in Earnings of Unconsolidated Subsidiaries is primarily due to a gain recognized in 2004 relating to the sale of most of the assets by a company in which Power Technology and Infrastructure held an investment interest.

Miscellaneous Income (Expense) – Net

The increase in Miscellaneous Income (Expense) - Net was primarily due to $56 million in impairment and disposal charges recognized in 2004 on certain investments in Power Technology and Infrastructure.

Income Taxes

The effective income tax rate decreased for 2005, as compared to 2004. The decrease was primarily a result of an increase in tax credits associated with the production and sale of synthetic fuel. Cinergy’s 2005 effective tax rate is approximately 16 percent.

Discontinued Operations

During 2005, Cinergy completed the sale of a wholly-owned subsidiary in the Czech Republic that was engaged in the generation and sale of heat and electricity. Cinergy also began taking steps to sell its wholly owned North American energy management and energy performance contracting business. Pursuant to Statement of Financial Accounting Standards (SFAS) 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 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.

MD&A – 2005 RESULTS OF OPERATIONS – CG&E

2005 RESULTS OF OPERATIONS – CG&E

Summary of Results

Net income for CG&E for the years ended December 31, 2005, and 2004 was as follows:

	CG&E and subsidiaries
	2005		2004		Change		% Change
	(in millions)

Net income	$	298	$	257	$	41	16	%

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

• Increased non-retail gross margins related to our generation portfolio, including the sale of emission allowances;

• Increased rate tariff adjustments resulting from implementation of the RSP in January 2005; and

• Increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004.

These increases were partially offset by:

• Increased fuel, emission allowance, and purchased power costs attributable to fixed price residential customers;

• Timing differences in revenue recognition between certain components of our generation portfolio; and

• Increased Operation and maintenance expense primarily due to regulatory asset amortization, incentive and severance labor costs, and costs associated with the sales of accounts receivable.

Gross Margins

Gross margins for CG&E for the years ended December 31, 2005, and 2004 were as follows:

	CG&E and subsidiaries
	2005		2004		Change		% Change
	(in millions)

Electric gross margin(1)	$	1,342	$	1,168	$	174	15	%
Gas gross margin(2)	266		263		3		1

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

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

Cooling degree days and heating degree days in CG&E’s service territory for the years ended December 31, 2005, and 2004 were as follows:

	CG&E and subsidiaries
	2005	2004	Change	% Change

Cooling degree days(1)	1,327	888	439	49	%
Heating degree days(2)(3)	3,678	3,624	54	1

(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 59 degrees, assuming the average temperature is less than 59 degrees.

Electric Gross Margins

The 15 percent increase in CG&E’s electric gross margins was primarily due to:

• Higher retail margins of $92 million reflecting:

• A $79 million increase in rate tariff adjustments resulting from implementation of the RSP in January 2005;

• A $30 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and

• A $24 million increase resulting from growth in non-weather related demand, due in part to the return of certain retail customers to full electric service.

Partially offsetting these increases was a $53 million increase in fuel, emission allowance, and purchased power costs attributable to fixed price residential customers.

• A $45 million increase in margins from power marketing and trading contracts, primarily due to an increase in margins within the midwest market.

• A $37 million increase in non-retail margins reflecting:

• A $45 million decrease due to timing differences in revenue recognition between certain components of our generation portfolio. Our gross margins reflect $54 million of losses in 2005 and $9 million of losses in 2004 (representing a $45 million change period to period) as a result of forward purchases of coal and forward sales of power and the use of MTM accounting. A substantial portion of these losses is expected to reverse in the first quarter of 2006.

• A $33 million decrease due to higher fuel prices.

Other Operating Revenues and Costs of Fuel Resold

The increase in Other Operating Revenues was due to a $108 million increase in revenues from coal origination resulting from increases in coal prices and tons of coal sold.

Costs of fuel resold represents the costs of coal origination activities. These costs have increased in 2005, 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
	2005		2004		Change		% Change
	(in millions)

Operation and maintenance	$	695	$	594	$	101	17	%
Depreciation	182		179		3		2
Taxes other than income taxes	214		198		16		8

Operation and Maintenance

The 17 percent increase in Operation and maintenance expense was primarily due to the following factors:

• Increased regulatory asset amortization of $45 million related to CG&E’s RTC. This increase reflects accelerated recovery of the regulatory asset due to both (a) the cessation of deferrals for non-residential customers due to the end of the market development period for those customers at the end of 2004 and (b) a reduction in revenues lost from switched customers, which is also recovered through the RTC;

• Increased labor expenses of $18 million, primarily resulting from employee incentive costs and severance payments;

• Increased costs of $14 million, primarily associated with the sales of accounts receivable to an unconsolidated affiliate primarily related to increased fees charged by the buyer of the receivables and an increase in the volume of receivables sold; and

• Expenses of $6 million related to outside service costs for the pending Duke-Cinergy merger.

These increases were partially offset by a decrease in outside service costs of $5 million related to our continuous improvement initiative in 2004.

Taxes Other Than Income Taxes

The eight percent increase in Taxes other than income taxes was primarily due to a $7 million increase in property taxes and a $6 million increase in gross receipts tax.

Interest Expense

The nine percent increase in Interest Expense was primarily due to an increase in average short-term and long-term debt outstanding and an increase in interest rates for our variable rate debt.

MD&A – 2005 RESULTS OF OPERATIONS – PSI

2005 RESULTS OF OPERATIONS – PSI

Summary of Results

Net income for PSI for the years ended December 31, 2005, and 2004 was as follows:

	PSI
	2005		2004		Change		% Change
	(in millions)

Net income	$	198	$	165	$	33	20	%

The increase in net income was primarily due to the impact of PSI’s May 2004 base retail electric rate increase and increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004.

These increases were partially offset by an increase in Depreciation expense due to increased depreciation rates and the addition of depreciable plant.

Electric Gross Margins

Gross margins for PSI for the years ended December 31, 2005, and 2004 were as follows:

	PSI
	2005		2004		Change		% Change
	(in millions)

Electric gross margin(1)	$	1,209	$	1,103	$	106	10	%

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

Cooling degree days and heating degree days in PSI’s service territory for the years ended December 31, 2005, and 2004 were as follows:

	PSI
	2005	2004	Change	% Change

Cooling degree days(1)	1,242	888	354	40	%
Heating degree days(2)(3)	4,013	3,856	157	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 59 degrees, assuming the average temperature is less than 59 degrees.

The 10 percent increase in PSI’s electric gross margins was primarily due to the following factors:

• A $71 million increase resulting from a higher price received per MWh, primarily due to PSI’s May 2004 base retail electric rate increase;

• A $24 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and

• An $18 million increase due to growth in non-weather related demand.

These increases were partially offset by a decline of $18 million reflecting rate reductions associated with a property tax adjustment.

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
	2005		2004		Change		% Change
	(in millions)

Operation and maintenance	$	480	$	475	$	5	1	%
Depreciation	266		222		44		20
Taxes other than income taxes	50		47		3		6

Operation and Maintenance

The one percent increase in Operation and maintenance expense was primarily due to various increases in operating costs and increased distribution system maintenance costs. Operating costs increased due to increased costs associated with the sales of accounts receivables to an unconsolidated affiliate and increased outside service costs. These increases were offset by a decrease in labor expense, primarily resulting from employee incentive costs, which were partially offset by merger and severance costs.

Depreciation

The 20 percent increase in Depreciation expense was primarily due to (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal, (b) recovery of deferred depreciation costs, and (c) the addition of depreciable plant for pollution control equipment, all of which are recovered from ratepayers.

Miscellaneous Income – Net

The increase in Miscellaneous Income – Net was primarily due to an increase in interest income on restricted deposits and an increase in the rate for allowance for funds used during construction.

Interest Expense

The 20 percent increase in Interest Expense was primarily due to an increase in average long-term debt outstanding and an increase in interest rates for our variable rate debt. This expense was partially offset by interest income received on restricted deposits obtained through these incremental borrowings, which was recorded in Miscellaneous Income – Net associated with the additional debt outstanding.

MD&A - 2005 RESULTS OF OPERATIONS – ULH&P

2005 RESULTS OF OPERATIONS – ULH&P

Summary of Results

The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2005, 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, 2005, and 2004 were as follows:

	ULH&P
	2005		2004		Change			% Change
	(in millions)

Electric gross margin(1)	$	72	$	68	$	4		6	%
Gas gross margin(2)	48		45		3			7
Net income	15		19		(4		)	(21	)

(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.

The six percent increase in electric gross margins was primarily due to increased demand caused by warmer weather in the third quarter of 2005, as compared to 2004. The seven percent increase in gas gross margins was primarily due to a base rate increase implemented in October 2005. Also contributing to gas gross margins was an increase in rate tariff adjustments associated with the gas main replacement program and the demand-side management program, which encourages efficient customer gas usage.

The 21 percent decrease in net income was partially due to higher Operation and maintenance costs associated with various increases in operating expenses including the transmission of electricity and increased costs associated with sales of accounts receivables to an unconsolidated affiliate. Also contributing to the decrease in net income were increased property taxes. There were also increases in Interest Expense related to an increase in average long-term debt outstanding. These decreases were partially offset by the increases in electric and gas gross margins as previously discussed.

MD&A – 2004 RESULTS OF OPERATIONS – CINERGY

2004 RESULTS OF OPERATIONS – CINERGY

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, 2004, and 2003 were as follows:

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

Electric gross margin(1)	$	1,662	$	1,503	$	159	11	%	$	616	$	667	$	(51	)	(8	)%
Gas gross margin(2)	263		244		19		8		92		88		4			5

(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
	2004	2003	Change		% Change

Cooling degree days(1)	888	880	8		1	%
Heating degree days(2)(3)	3,740	3,990	(250	)	(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 59 degrees, assuming the average temperature is less than 59 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 11 percent increase in Regulated’s electric gross margins was primarily due to the following factors:

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

• A $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 a $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was a $7 million decrease reflecting a decline in non-weather related demand.

Commercial

Gross Margins

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

• A $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

• A $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:

• A $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

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

Other Operating Revenues and Costs of Fuel Resold

The 45 percent increase in Other Operating Revenues was primarily due to the following factors:

• A $67 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts; and

• A $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	$	1,231	$	1,080	$	151	14	%
Depreciation	454		393		61		16
Taxes other than income taxes	254		250		4		2

Operation and Maintenance

The 14 percent increase in Operation and maintenance expense was primarily due to the following factors:

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

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

• Costs of $20 million incurred in 2004 related to a continuous improvement initiative;

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

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

• Costs of $12 million incurred in 2003 associated with the bankruptcy of Enron Corp.

Depreciation

The 16 percent increase in Depreciation expense was primarily due to the following factors:

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

• A $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 $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 $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 17(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 $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 $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:

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

• A $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 (FASB) 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.

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. The 2004 and 2003 Discontinued Operations have been restated for 2005 discontinued operations, as previously discussed in “MD&A – 2005 Results of Operations – Cinergy”. Pursuant to Statement 144, these investments have been classified as discontinued operations in our financial statements. See Note 16 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 $26 million. The cumulative effect of changes in accounting principles was a result of the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations (Statement 143) and the rescission of Emerging Issues Task Force Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). See Note 1(s)(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)	888	812	76		9	%
Heating degree days(2) (3)	3,624	3,817	(193	)	(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 59 degrees, assuming the average temperature is less than 59 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:

• A $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

• A $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:

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

• A $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 a $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was a $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 a $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	)

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 $28 million;

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

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

• Higher transmission costs of $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 $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 $15 million. This decrease was partially offset by an $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 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(s)(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 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)	888	947	(59	)	(6	)%
Heating degree days(2) (3)	3,856	4,162	(306	)	(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 59 degrees, assuming the average temperature is less than 59 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 $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and

• A $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

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 $14 million;

• Costs of $8 million incurred in 2004 related to a continuous improvement initiative;

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

• Higher transmission costs of $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 $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:

• A $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 – 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, 2005, 2004, and 2003, our cash flows from operating activities from continuing operations were as follows:

Net Cash Provided by Operating Activities from Continuing Operations

	2005		2004		2003
	(in thousands)

Cinergy(1)	$	667,905	$	822,607	$	930,560
CG&E and subsidiaries	719,054		445,621		557,761
PSI	105,488		483,463		246,735
ULH&P	44,257		45,381		33,061

(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, 2005, Cinergy’s and PSI’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. Cinergy’s and PSI’s decrease was also attributable to increased expenditures associated with fuel and purchased power that have not yet been expensed, until recovered from ratepayers. CG&E’s increase in net cash provided by operating activities was due to favorable working capital fluctuations, including increased net cash received as collateral associated with power transactions. ULH&P’s net cash provided by operating activities was comparable to 2004.

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.

Financing Activities from Continuing Operations

For the years ended December 31, 2005, 2004, and 2003, our cash flows from financing activities from continuing operations were as follows:

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

	2005			2004			2003
	(in thousands)

Cinergy(1)	$	179,206		$	(229,599	)	$	(232,942	)
CG&E and subsidiaries	(316,795		)	(172,782		)	(263,296		)
PSI	422,634			(164,141		)	90,070
ULH&P	8,566			(9,226		)	4,852

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

For the year ended December 31, 2005, Cinergy’s increase in net cash provided by financing activities was primarily attributable to the increased issuance of long-term debt and common stock and the decrease in redemptions of long-term debt in 2005. CG&E’s increase in net cash used in financing activities was primarily due to the repayment of short-term debt. PSI’s increase in net cash provided by financing activities was attributable to

the issuance of long-term debt and capital contributions received from Cinergy Corp. ULH&P’s decrease in net cash used in financing activities was due to an increase in short-term debt.

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.

Investing Activities from Continuing Operations

For the years ended December 31, 2005, 2004, and 2003, our cash flows used in investing activities from continuing operations were as follows:

Net Cash Used in Investing Activities from Continuing Operations

	2005			2004			2003
	(in thousands)

Cinergy(1)	$	(863,581	)	$	(597,513	)	$	(730,139	)
CG&E and subsidiaries	(396,739		)	(284,527		)	(323,959		)
PSI	(507,056		)	(315,093		)	(332,247		)
ULH&P	(47,144		)	(33,857		)	(39,940		)

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

For the year ended December 31, 2005, Cinergy’s, CG&E’s, and PSI’s increase in net cash used in investing activities was primarily due to increases in capital expenditures for ongoing environmental compliance programs and normal construction activity. Cinergy’s and PSI’s increase was also attributable to the acquisition of the Wheatland generating facility in May 2005. ULH&P’s increase in net cash used in investing activities was primarily due to increased capital expenditures related to normal construction activity.

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.

Capital Requirements

Environmental Issues

Environmental Protection Agency Regulations

In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR) which would require states to revise their State Implementation Plan (SIP) by September 2006 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards for ozone and fine particulate matter. The rule established a two-phase, regional cap and trade program for SO2 and NOX, affecting 28 states, including Ohio, Indiana, and Kentucky, and requires SO2 and NOX emissions to be cut 70 percent and 65 percent, respectively, by 2015. At the same time, the EPA issued the Clean Air Mercury Rule (CAMR) which requires national reductions in mercury emissions from coal-fired power plants beginning in 2010. Accompanying the CAMR publication in the Federal Register was the EPA’s determination that it was not appropriate and necessary to regulate mercury emissions from utilities under Section 112 of the Clean Air Act (CAA), requiring maximum achievable control technology, so that it would be possible to regulate those emissions under Section 111 of the CAA with the CAMR. The final regulation also adopts a two-phase cap and trade approach that requires mercury emissions to be cut by 70 percent by 2018. SIPs must comply with the prescribed reduction levels under CAIR and CAMR; however, the states have the ability to introduce more stringent requirements if desired. Under both CAIR and CAMR, companies have flexible

compliance options including installation of pollution controls on large plants where such controls are particularly efficient and utilization of emission allowances for smaller plants where controls are not cost effective.

In August 2005, the EPA proposed a Federal Implementation Plan (FIP), which would implement phase 1 of CAIR by 2009 and 2010 for NOX and SO2, respectively, for any state that does not develop a CAIR SIP in a timely manner. Numerous states, environmental organizations, industry groups, including some of which Cinergy is a member, and individual companies have challenged various portions of both rules. Those challenges are currently pending in the Federal Circuit Court for the District of Columbia. On October 21, 2005, the EPA agreed to reconsider certain aspects of the CAMR as well as the determination not to regulate mercury under Section 112 of the CAA. In December 2005 and again in January 2006, the EPA reconsidered portions of the CAIR, but did not propose any regulatory changes. At this time we cannot predict the outcome of these matters.

Over the 2006-2010 time period, we expect to spend approximately $1.4 billion to reduce mercury, SO2, and NOX emissions. These projected expenditures 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 53 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. See (b)(ii) for more details. CG&E receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its RSP. See (b)(iii) for more details.

The EPA made final state non-attainment area designations to implement the revised ozone standard and to implement the new fine particulate standard in June 2004 and April 2005, respectively. 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 by June 2007 and April 2008, respectively. Industrial sources in or near those counties are potentially subject to requirements for installation of additional pollution controls. In March 2005, various states, local governments, environmental groups, and industry groups, including some of which Cinergy is a member, filed petitions for review in the United States Court of Appeals for the D.C. Circuit to challenge the EPA’s particulate matter non-attainment designations. Although the EPA has attempted to structure 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.

Energy Policy Act of 2005

A comprehensive energy bill (the Energy Policy Act of 2005) passed Congress in July 2005 and was signed by President Bush on August 8, 2005. The bill, among other things:

• Repealed the Public Utility Holding Company Act of 1935 (PUHCA 1935) and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005) effective six months after the bill’s enactment (i.e., February 8, 2006);

• Amended certain provisions of the Federal Power Act, including new provisions related to consumer protection and enforcement and an expansion of the Federal Energy Regulatory Commission’s (FERC) authority to impose civil and criminal penalties for, among other things, reliability infractions and power trading irregularities;

• Revised the Public Utility Regulatory Policies Act of 1978, including the removal of restrictions on ownership by electric utilities of qualifying facilities and the removal of the utility’s requirement to purchase power from facilities under certain circumstances;

• Provided FERC with expanded authority in the electric industry to review mergers, acquisitions and asset dispositions, effective six months after the bill’s enactment;

• Provided FERC with authority to oversee and enforce, through the creation of a new Electric Reliability Organization, reliability standards, and promotes rules that provide incentives to enhance transmission facilities;

• Included tax incentives for the development of wind and other renewable technologies;

• Included tax incentives for integrated coal gasification combined cycle (IGCC) facilities; and

• Accelerated the tax depreciation rates for pollution control equipment on power plants built after 1975.

Under terms of the Energy Policy Act of 2005, Cinergy’s pending merger with Duke is grandfathered under existing FERC authority. In addition, the bill authorized a significant number of programs and grants that may be of help in, among other things, lowering the cost of adding IGCC facilities and furthering carbon sequestration activities. However, those authorizations must be appropriated by Congress in 2006. It is too early to determine if any of the programs will be appropriated dollars in order to carry them out, or if Cinergy will be a direct beneficiary of those programs. As noted, the Energy Policy Act of 2005, among other provisions, repealed the PUHCA 1935 and replaced it with the PUHCA 2005, effective February 8, 2006. See “FERC Public Utility Holding Company Act of 2005” in “MD&A Future Expectations/Trends” for additional information on the PUHCA 2005. At this time, it is too early to predict the overall impact the Energy Policy Act of 2005 will have on our financial position or results of operations.

Lawsuits

We are currently involved in the following lawsuits which are discussed in more detail in “Item 3. Legal Proceedings.” An unfavorable outcome of any of these lawsuits could have a material impact on our liquidity and capital resources.

• Clean Air Act Lawsuit

• Carbon Dioxide 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 2005 and forecasted construction and other committed expenditures for 2006 and for the five-year period 2006-2010 (in nominal dollars) are presented in the table below:

Capital and Investment Expenditures

	Actual		Forecasted
	2005		2006		2006-2010
	(in millions)

Cinergy(1)	$	1,158	$	1,377	$	5,539
CG&E and subsidiaries	434		660		2,482
PSI	634		657		2,872
ULH&P	47		67		292

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

In 2005, we spent $462 million for NOX and other environmental compliance projects. Forecasted expenditures for environmental compliance projects (in nominal dollars) are approximately $679 million for 2006 and $1.5 billion for the 2006-2010 period. The majority of this forecast includes our estimate of the total cost to comply with regulations requiring reductions in mercury, NOX, 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:

Contractual Cash Obligations(1)

Payments Due

2006

2007

2008

2009

2010

Thereafter

Total

(in millions)

Cinergy(2)

PART I

ITEM 1. BUSINESS

Generation – Fuel Supply and Emission Allowances

Transmission and Distribution

Gas Supply

Revenue Data and Customer Base

Generation – Fuel Supply and Emission Allowances

Trading Operations and Risk Management

CG&E Electric Rate Stabilization Plan

Energy Services

International

Revenue Data and Customer Base

• Other Matters.

ITEM 1A. RISK FACTORS

Our Regulated’s revenues, earnings, and results are dependent on state legislation and regulation that affect electric generation, distribution, and related activities, which may limit our ability to recover costs.

Our sales may decrease if we are unable to gain adequate, reliable, and affordable access to transmission and distribution assets.

Competition in the unregulated markets in which we operate may adversely affect the growth and profitability of our business.

We rely on access to short-term money markets and longer-term capital markets to finance our capital requirements and support our liquidity needs, and our access to those markets can be adversely affected by a number of conditions, many of which are beyond our control.

We will be exposed to market risk and may incur losses from the trading operations and/or activities we take to mitigate our commodity exposure.

We are exposed to credit risk of counterparties with whom we do business.

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.

Under Cinergy’s holding company structure, the payment of dividends to shareholders is subject to the ability of its subsidiaries to pay dividends to it.

We are currently involved in litigation with the United States and several states and environmental groups regarding certain environmental matters.

We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and which may impact or limit our business plans, or expose us to environmental liabilities.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations, or cash flows and our utilities’ businesses.

Efforts associated with completing the merger with Duke are complex and may divert management’s focus and resources from other strategic opportunities.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond our control.

Our business is subject to extensive regulation that will affect our operations and costs.

Certain events in the energy markets beyond our control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets which could have a negative impact on our financial condition or results of operations or access to capital.

Potential terrorist activities or military or other actions could adversely affect our business.

Increased environmental regulation and liabilities could subject us to significant compliance and remediation costs that adversely affect our results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2. PROPERTIES

REGULATED

Electric

Domestic Power Generation

Transmission and Distribution

Gas

COMMERCIAL

Electric

Domestic Power Generation

Cogeneration

Synthetic Fuel

International

PEAK LOAD

ITEM 3. LEGAL PROCEEDINGS

CLEAN AIR ACT LAWSUIT

CARBON DIOXIDE LAWSUIT

SELECTIVE CATALYTIC REDUCTION UNITS (SCR) AT GIBSON GENERATING STATION

ZIMMER GENERATING STATION (ZIMMER STATION) LAWSUIT

MANUFACTURED GAS PLANT (MGP) SITES

ASBESTOS CLAIMS LITIGATION

DUNAVAN WASTE SUPERFUND SITE

MERGER LAWSUIT

OHIO EPA PENALTY ON CINERGY POWER GENERATION SERVICES

ONTARIO, CANADA LAWSUIT

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

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

ITEM 6. SELECTED FINANCIAL DATA

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

EXECUTIVE SUMMARY

Financial Highlights

Forward-looking Challenges and Risks

Merger Challenges and Risks

Environmental Challenges

Rising Coal and Emission Allowance Prices

Synthetic Fuel

2005 RESULTS OF OPERATIONS – CINERGY

Regulated

Gross Margins

Commercial

Gross Margins

Other Operating Revenues and Costs of Fuel Resold

Other Operating Expenses

Operation and Maintenance

Depreciation

Taxes Other Than Income Taxes

Equity in Earnings of Unconsolidated Subsidiaries

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

UNION LIGHT HEAT & POWER CO 10-K