CLECO POWER LLC - 10-K Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
[X] ANNUAL REPORTS PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003
Or
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

     Cleco Power LLC 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.

     Indicate by check mark whether each of the registrants (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 the registrant was required to file such reports),  and (2) has been subject to such filing requirements for the past 90 days.  Yes  X   No     .

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each of the registrant's 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.[ X ]

     Indicate by check mark whether Cleco Corporation is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes  X   No     .

     Indicate by check mark whether Cleco Power LLC is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes      No   X  .

     The aggregate market value of the Cleco Corporation voting stock held by non-affiliates was $790,252,977 on June 30, 2003, based on a price of $17.32 per common share, the closing price of Cleco Corporation's common stock as reported on the New York Stock Exchange on such date.  Cleco Corporation's Cumulative Preferred Stock is not listed on any national securities exchange, nor are prices for the Cumulative Preferred Stock quoted on any national automated quotation system; therefore, its market value is not readily determinable and is not included in the foregoing amount.

This combined Form 10-K is separately filed by Cleco Corporation and Cleco Power LLC. Information contained herein relating to Cleco Power is filed by Cleco Corporation and separately by Cleco Power on its own behalf. Cleco Power makes no representation as to information relating to Cleco Corporation (except as it may relate to Cleco Power) or any other affiliate or subsidiary of Cleco Corporation.

This report should be read in its entirety as it pertains to each respective registrant. The Notes to the Financial Statements for the registrants are combined.

References in this filing to "the Company" or "Cleco" mean Cleco Corporation and its subsidiaries, including Cleco Power LLC, references to "Cleco Power" mean Cleco Power LLC and references to "the Registrants" mean both Cleco Corporation and Cleco Power, unless the context clearly indicates otherwise. Additional abbreviations or acronyms used in this filing are defined below:

This report includes "forward-looking statements" about future events, circumstances, and results. All statements other than statements of historical fact included in this report are forward-looking statements. Although the Registrants believe that the expectations reflected in such forward-looking statements are reasonable, such forward-looking statements are based on numerous assumptions (some of which may prove to be incorrect) and are subject to risks and uncertainties that could cause the actual results to differ materially from the Registrants' expectations. In addition to any assumptions and other factors referred to specifically in connection with these forward-looking statements, the following list identifies some of the factors that could cause the Registrants' actual results to differ materially from those contemplated in any of the Registrants' forward-looking statements:

All subsequent written and oral forward-looking statements attributable to the Registrants or persons acting on their behalf are expressly qualified in their entirety by the factors identified above.

The Registrants undertake no obligation to update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 1.     BUSINESS

General

          Cleco Corporation was incorporated on October 30, 1998, under the laws of the State of Louisiana.  In July 1999, Utility Group reorganized into a holding company structure.  This reorganization resulted in Cleco Corporation becoming a holding company.  Cleco Corporation holds investments in several subsidiaries, including Cleco Power (successor to Utility Group) and Midstream, which comprise separate operating business segments.  Cleco Corporation, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to Section 3(a)(1) of PUHCA.

          Cleco Power's predecessor was incorporated on January 2, 1935, under the laws of the State of Louisiana.  Cleco Power was organized on December 12, 2000, and succeeded to Utility Group's assets and liabilities pursuant to a merger of Utility Group into Cleco Power in December 2000.  Cleco Power is an electric utility regulated by the LPSC and the FERC, among other regulators, which determine the rates Cleco Power can charge its customers.  Cleco Power serves approximately 264,000 customers in 104 communities in central and southeastern Louisiana.  Cleco Power's operations are described below in the consolidated description of Cleco's business segments.

          Midstream, organized on September 4, 1998, under the laws of the State of Louisiana, is a merchant energy subsidiary with operations in Louisiana and Texas.  Midstream owns and operates merchant generation stations and merchant natural gas pipelines, invests in joint ventures that own and operate merchant generation stations, and engages in energy management activities.  On January 28, 2004, Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc.  As part of the sales process, Perryville and PEH, also a subsidiary of Midstream and the parent company of Perryville, filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code.  Perryville and PEH are debtors and debtors in possession, and are continuing to operate their business under the U.S. Bankruptcy Code.  For additional information on the bankruptcy filings and the pending sale of the Perryville facility, see Part II, Item 8, "Financial Statements and Supplementary Data - Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

          UTS is a discontinued business segment.  UTS was a utility line construction business originally organized in 1997.  In December 2000, Cleco decided to sell substantially all of the assets of UTS.  Revenue and expenses associated with UTS are netted and shown on Cleco's Consolidated Statements of Operations as a loss from discontinued operations.  For additional information on the sale of the UTS assets, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 17 - Discontinued Operations."

          At December 31, 2003, Cleco employed 1,203 people.  Cleco's mailing address is P.O. Box 5000, Pineville, Louisiana 71361-5000, and its telephone number is (318) 484-7400.  Cleco's homepage on the Internet's World Wide Web is located at http://www.cleco.com.  Cleco Corporation's and Cleco Power's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings with the SEC are available, free of charge, through Cleco's website, as soon as reasonably practicable after those reports or filings are electronically filed with or furnished to the SEC.  Cleco's corporate governance guidelines, code of business conduct and ethics and the charters of its board of directors' audit, compensation, qualified legal compliance and nominating/governance committees are available on its website and available in print to any shareholder who requests.  Cleco's filings also can be obtained at the SEC's Public Reference Room at 450 Fifth Street NW, Washington, DC 20549.  Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.  Cleco's electronically filed reports also can be obtained on the SEC's Internet site located at http://www.sec.gov.  Information on Cleco's website or any other website is not incorporated by reference into this Report and does not constitute a part of this Report.

          At December 31, 2003, Cleco Power employed 847 people.  Cleco Power's mailing address is P.O. Box 5000, Pineville, Louisiana, 71361-5000, and its telephone number is (318) 484-7400.

          Cleco Power meets the conditions specified in General Instructions I(1)(a) and (b) to Form 10-K and therefore is permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies.  Accordingly, Cleco Power has omitted from this Report the information called for by Item 4 (Submission of Matters to a Vote of Security Holders) of Part I of Form 10-K, the following Part II items of Form 10-K:  Item 6 (Selected Financial Data) and Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operations); and the following Part III items of Form 10-K:  Item 10 (Directors and Executive Officers), Item 11 (Executive Compensation), Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters), and Item 13 (Certain Relationships and Related Transactions).

Financial results of the Cleco Power segment for years 2003, 2002, and 2001 are presented below.

				2003				2002				2001
Revenue		(Thousands)
	Electric operations	$		676,002		$		568,102		$		592,253
	Energy trading, net			626				(752)				1,456
	Other operations			30,013				29,331				30,813
	Electric customer credits			(1,562)				(2,900)				(1,800)
Intersegment revenue				2,209				1,708				6,011
Total operating revenue		$		707,288		$		595,489		$		628,733

Depreciation expense			$		54,084		$		52,233		$		50,594
Interest charges			$		28,774		$		29,091		$		26,819
Interest income			$		1,335		$		933		$		6,498
Federal and state income taxes expense			$		29,846		$		32,172		$		31,290
Segment profit			$		57,008		$		59,574		$		59,138

Additions to long-lived assets			$		68,507		$		87,321		$		45,642
Segment assets		$		1,378,916		$		1,338,445		$		1,185,223

As an electric utility, Cleco Power is affected, to varying degrees, by a number of factors influencing the electric utility industry in general. These factors include, among others, an increasingly competitive business environment, the cost of compliance with environmental regulations, and changes in the federal and state regulation of the generation, transmission, and sale of electricity. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see "- Regulatory Matters, Industry Developments, and Franchises - Franchises" and Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring." For a discussion of significant factors affecting Cleco Power's financial condition and results of operations, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Cleco Power - Significant Factors Affecting Cleco Power."

Power Generation

Cleco Power operates and either owns or has an ownership interest in three steam electric generating stations and one gas turbine. As of December 31, 2003, Cleco Power's aggregate net electric generating capacity was 1,359 MW. The following table sets forth certain information with respect to Cleco Power's generating facilities:

The following table sets forth the amounts of power generated by Cleco Power for the years indicated.

Changes in fuel and purchased power expenses reflect fluctuations in fuel used for electric generation, fuel handling costs, availability of economical power for purchase, and deferral of expenses for recovery from customers in subsequent months through Cleco Power's fuel adjustment clause.

The following table sets forth the percentages of power generated from various fuels at Cleco Power's electric generating plants, the cost of fuel used per kWh attributable to each such fuel, and the weighted average fuel cost per kWh.

Power Purchases

When transmission capacity is available, Cleco Power purchases power from energy marketing companies, whose power is typically produced by exempt wholesale generators, or neighboring utilities when the price is more economical than self-generation of power or when Cleco Power needs power to supplement its own electric generation. These purchases are made from the wholesale power market in the form of generation capacity and/or energy. Portions of Cleco Power's capacity and power purchases are made at fixed prices, and the remainder is made at prevailing market prices based upon time of purchase.

          Cleco Power has three power contracts with two marketing companies, Williams Energy and Dynegy for a total of 705 MW of capacity in 2002 and 2003, increasing to 760 MW of capacity in 2004, and decreasing to 100 MW of capacity in 2005.  Cleco Power obtains approximately 32% of its annual capacity from these contracts with Williams Energy and Dynegy.  These contracts were approved by the LPSC in March 2000.  Cleco Power also has a long-term contract under which it purchases 20 MW of power from the Sabine River Authority, which operates a hydroelectric generating plant.  In addition, Cleco Power has wholesale power contracts with the City of Ruston (81 MW expiring May 2004) and the City of Natchitoches (51 MW expiring December 2006).

          Management expects to meet its native load demand through 2004 with Cleco Power's own generation capacity and the contracts with Williams Energy and Dynegy, but with a significant portion of the contracts expiring on December 31, 2004, Cleco Power currently is evaluating its short-term and long-term capacity and energy needs.  Cleco Power initiated a solicitation during the second quarter of 2003 to identify existing or new generation resources for 2005 and subsequent years, including new power purchase contracts, to replace the Williams Energy contracts and the Dynegy contract.  There were no winning proposals selected from the RFP; however, on January 30, 2004, Cleco Power agreed to terms for a one-year contract to purchase 500 MW of capacity from CES starting in January 2005.  Such one-year contracts are not subject to the LPSC's RFP general order requirements, but do remain subject to certification approval by the LPSC.  Cleco Power anticipates that this contract will be executed by late March 2004 and the 500 MW of capacity from CES is expected to fill the shortfall left by the Williams Energy and Dynegy contracts expiring at the end of 2004; however, Cleco Power continues to evaluate meeting capacity requirements in future periods.  Given transmission constraints in the area, this short-term power contract with CES minimizes risks associated with transmission constraints.

          During the third quarter of 2003, Cleco Power created an IRP team to evaluate generation supply options. IRP is a process to evaluate resources in order to provide a reliable and flexible service to electric customers at the lowest system cost.  A full range of options are being analyzed including power purchases, fuel conversion, repowering projects, asset acquisitions, cogeneration, renewables, energy conservation, plant retirements, and mothballing of existing assets.  The process takes into account necessary features for system operation, such as fuel diversity, reliability, ease of dispatch, environmental impact, and other factors of risk.  The IRP process also treats demand and supply resources on a consistent basis while taking into account such variables as fuel pricing, fuel deliverability, load growth, environmental impacts, capital expenditures, and operation and maintenance costs.  The IRP team presently is developing a framework for evaluating proposed actions to optimize reliable and least-cost electric service for Cleco's customers' needs and to reduce and stabilize their fuel cost without sacrificing reliability.  Cleco Power's transmission personnel are also evaluating additional transmission capacity alternatives as part of the IRP process.  Any viable generation alternative must then be validated through a LPSC-sanctioned solicitation process where Cleco Power would issue a RFP.  As part of the IRP effort, Cleco Power plans to issue a new RFP in mid-2004 to identify existing or additional generation resources.  For additional information on the IRP process and on Cleco Power's planned RFP, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Cleco Power - Significant Factors Affecting Cleco Power - Fuel and purchased power are primarily affected by the following factors."

          The following table sets forth the amounts of power purchased by Cleco Power on the wholesale market for the years indicated.

During 2003, 50% of Cleco Power's energy requirements were met with purchased power, up from 45% in 2002. The primary factor causing the increase in power purchases in 2003 as compared to 2002 was the lower price of purchased power compared to the incremental cost of Cleco Power's generation of power. For information on Cleco Power's ability to pass on to its customers substantially all of its fuel and purchased power expenses, see "Regulatory Matters, Industry Developments, and Franchises - Rates."

In February 1999, the LPSC approved the transfer of the existing CPS assets out of Cleco Power's LPSC-regulated rate base into Evangeline, an indirect wholly owned subsidiary of Cleco Corporation. The actual transfer occurred in November 1999. In return for the approval of the asset transfer, Cleco Power agreed to extend the terms of its 1996 rate settlement with the LPSC for an additional three years to September 30, 2004. See Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Retail Rates of Cleco Power" for more information about the LPSC settlement. This agreement also contains specific provisions designed to hold Cleco Power's customers harmless from negative impacts that might result from the removal of the CPS generating assets from its rate base. In return, Cleco Power completed the transfer of CPS generating and transmission assets to Evangeline at their net book value of approximately $9.8 million. This resulted in a 334-MW reduction in Cleco Power's generating capability.

Because of its location on the transmission grid, Cleco Power relies on one main supplier of electric transmission, and constraints sometimes limit the amount of purchased power it can import into its system. The power contracts described above may be affected by these transmission constraints.

Natural Gas Supply

During 2003, Cleco Power purchased a total of 26,754,000 MMBtu of natural gas for the generation of electricity. The annual and average per-day quantities of gas purchased by Cleco Power from each supplier are shown in the table below.

In June 2003, CLE Intrastate transferred its natural gas interconnections at Rodemacher and Teche power stations with Trunkline Gas Company, Louisiana Intrastate Pipeline Company, and ANR Pipeline Company to Cleco Power. The pipeline interconnections allow Cleco Power to access various additional natural gas supply markets, which helps to maintain a more economical fuel supply for Cleco Power's customers.

Natural gas was available without interruption throughout 2003, except during hurricane-related curtailments. Cleco Power expects to continue to meet its natural gas requirements with purchases on the spot market through daily, monthly, and seasonal contracts with various natural gas suppliers. However, future supplies to Cleco Power remain vulnerable to disruptions due to weather events and transportation delays. Cleco Power has access to multiple sources of natural gas at each plant and therefore access to diverse supplies. Nevertheless, large industrial users of natural gas, including electric utilities, generally have low priority among gas users in the event pipeline suppliers are forced to curtail deliveries due to inadequate supplies. As a result, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply interruptions. Such events, though rare, may require Cleco Power to shift its gas-fired generation to alternative fuel sources, such as fuel oil, to the extent it has the capability to burn alternative fuels. Currently, Cleco Power anticipates that its diverse supply options and alternative fuel capability, combined with its solid-fuel generation resources, are adequate to meet its fuel needs during any temporary interruption of natural gas supplies.

Cleco Power uses coal for generation at Rodemacher Unit 2. The majority of the coal for Rodemacher Unit 2 is purchased from mines in Wyoming. A contract, which includes fixed pricing through December 31, 2004, was negotiated in 2002 with Kennecott Energy Company (Kennecott). After purchasing a given annual quantity of base coal (approximately 500,000 tons), Cleco Power has the right to purchase additional coal from Kennecott or from third parties in the spot market through competitive bidding. Cleco Power elected to purchase additional coal under these terms of the Kennecott agreement, providing it with a total of 640,000 tons in 2004. This agreement provides the platform to govern future agreements with Kennecott. Renegotiations, which began in January 2004, are expected to be completed by July 2004. If renegotiation is not successful, Cleco Power expects to purchase coal from other suppliers. The coal is transported to the Rodemacher Unit 2 site under a long-term rail transportation contract in trains that are under various long-term leases to Cleco Power. This long-term rail transportation contract expires on December 31, 2005.

Cleco Power uses lignite for generation at Dolet Hills Unit 1. Substantially all of the lignite used to fuel Dolet Hills Unit 1 is obtained under two long-term agreements. Cleco Power and SWEPCO, each a 50% owner of Dolet Hills Unit 1, have entered into agreements pursuant to which each acquired an undivided 50% interest in the other's leased and owned lignite reserves in northwestern Louisiana. In May 2001, Cleco Power and SWEPCO entered into a long-term agreement with annual renewals through 2011 with Dolet Hills Lignite Company, LLC for the mining and delivery of such lignite reserves. These reserves are expected to provide a substantial portion of the fuel requirements throughout the life of the contract with Dolet Hills Lignite Company, LLC. The May 2001 agreement replaced a previous Lignite Mining Agreement that was terminated under a settlement agreement in connection with certain litigation relating to the previous Lignite Mining Agreement.

Additionally, Cleco Power and SWEPCO have entered into a long-term agreement which expires in 2011 with Red River Mining Company to purchase lignite. Cleco Power's minimum annual purchase requirement of lignite under this agreement is 550,000 tons. The lignite price under the contract is a base price per MMBtu, subject to escalation, plus certain "pass-through" costs. Dolet Hills Lignite Company provides all of the lignite in excess of the 550,000 tons base commitment.

The continuous supply of coal and lignite from the mining sources described above may be subject to interruption due to adverse weather conditions or other factors that may disrupt mining operations or transportation. At December 31, 2003, Cleco Power's coal inventory at Rodemacher Unit 2 was approximately 184,000 tons (about an 84-day supply), and Cleco Power's lignite inventory at Dolet Hills Unit 1 was approximately 139,000 tons (about a 22-day supply).

Cleco Power stores fuel oil as an alternative fuel source at Rodemacher and Teche power stations. The Rodemacher power station has storage capacity for an approximate 75-day supply and the Teche power station has storage capacity for an approximate 20-day supply. However, in accordance with Cleco Power's current fuel oil inventory practices, Cleco Power had approximately a 38-day total supply of fuel oil stored at these generating stations at

December 31, 2003. During 2003, approximately 3.1 million gallons of fuel oil was burned producing 40,000 MWh of energy.

Cleco Power is a public utility engaged principally in the generation, transmission, distribution, and sale of electricity within Louisiana. For further information regarding Cleco Power's generating stations and its transmission and distribution facilities, see "- Power Generation" above and Item 2, "Properties - Cleco Power."

Cleco Power's 2003 system peak demand was 1,990 MW, which occurred in August 2003, and its 2002 system peak demand was 1,937 MW, which occurred in July 2002. Sales and system peak demand are affected by weather and generally are highest during the summer air-conditioning and winter heating seasons. In 2003, Cleco Power experienced relatively normal summer weather and cooler than normal winter weather. For additional information on the effects of weather on demand, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Cleco Power - Significant Factors Affecting Cleco Power - Revenue is primarily affected by the following factors." For information on the financial effects of seasonal demand on Cleco Power's quarterly operating results, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 29 - Miscellaneous Financial Information (Unaudited)."

In 2003, Cleco Power was deemed to have met the capacity margin requirements of 12% established by the SPP. Capacity margin is the net capacity resources (either owned or purchased) less native load demand divided by net capacity resources. Each year members of the SPP submit forecasted native load demand and the forecasted mix of net capacity resources to meet this demand. If capacity margin requirements are not met, the SPP can require that more capacity be supplied in subsequent years. Cleco Power's actual capacity margin for 2003 was 13.0%, while in 2002, it was 16.5%. Cleco Power expects the system peak demand to decrease slightly as a result of the loss of one wholesale customer and one retail customer, and anticipates a 14.6% capacity margin for 2004. Cleco Power expects that its power purchase contracts with Williams Energy, Dynegy, and CES will allow it to meet capacity reserve margin requirements in 2004 and 2005. For additional information on Cleco Power's power contracts and its evaluation of other long-term supply options, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Generation RFP."

For information on energy trading and the decision to discontinue speculative trading activities within Cleco Power, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Cleco Power" and Item 7A, "Quantitative and Qualitative Disclosures About Market Risk - Cleco Power."

For additional information on Cleco Power's operations, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Cleco Power's Results of Operations - Year ended December 31, 2003, Compared to Year ended December 31, 2002," and "- Financial Condition - Cash Generation and Cash Requirements - Cleco Power Construction."

Financial results of the Midstream segment for years 2003, 2002, and 2001 are presented below.

Midstream wholly and directly owns seven limited liability companies that operate mainly in Louisiana and Texas:

The following table sets forth certain information with respect to Midstream's operating generating facilities.

Midstream competes against regional and national companies that own and operate merchant power stations. Cleco Energy competes against regional gas transportation and gas marketing companies. CLE Intrastate owns a natural gas interconnection. Prior to May 2003, Marketing & Trading competed against regional energy management and marketing companies.

Evangeline's capacity is dedicated to one customer, Williams Energy, which is the counterparty to the Evangeline Tolling Agreement. Acadia's capacity also is dedicated to one customer, CES, which is the counterparty to the Calpine Tolling Agreements. Prior to a restructuring of the tolling arrangement at Acadia that occurred in May 2003, Acadia's capacity was dedicated to CES and Aquila Energy. Each tolling agreement gives the tolling counterparty the right to own, dispatch and market all of the electric generation capacity of the respective facility. The Calpine Tolling Agreements expire in 2022 and the Evangeline Tolling Agreement expires in 2020. Under each tolling agreement, the tolling counterparty is responsible for providing its own natural gas to the facility and pays Evangeline and Acadia, respectively, a fixed fee and a variable fee for operating and maintaining the facility.

Prior to September 15, 2003, Perryville's capacity was dedicated to one customer, MAEM, which was the counterparty to the Perryville Tolling Agreement. However, on August 29, 2003, in connection with Mirant's Chapter 11 bankruptcy filing, MAEM rejected the Perryville Tolling Agreement effective September 15, 2003, and no longer has rights and obligations under the agreement. Perryville has asserted damage claims in the bankruptcy process against the Mirant Debtors as a result of the rejection of the Perryville Tolling Agreement. On January 28, 2004, Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. and entered into a power purchase agreement with Entergy Services, Inc. To facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. For additional information on the above tolling agreements and related transactions, risks and uncertainties, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Midstream - Significant Factors Affecting Midstream - Revenue is primarily affected by the following factors," and "- Financial Condition - Liquidity and Capital Resources - General Considerations and Credit-Related Risks." For additional information on the rejection of the Perryville Tolling Agreement, the pending sale of Perryville and the related bankruptcy, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville" and Note 30 - "Subsequent Events - Perryville."

Cleco Energy's revenue is primarily driven by natural gas throughput on its pipelines and the demand for natural gas, which in turn is influenced by the weather and the number of power stations, industrial plants, and commercial and residential customers who use natural gas within its region.

CLE Intrastate's revenue is primarily generated from a monthly reservation fee paid by Evangeline for access to the Columbia Gulf interconnect and from a commodity fee that varies depending on the amount of gas transported through the interconnect for use by Evangeline.

Prior to May 2003, Marketing & Trading primarily provided energy management services to several municipalities and, prior to the fourth quarter of 2002, marketed and traded wholesale natural gas and power. In 2002, Cleco assessed its speculative trading strategy and determined, in light of market conditions and other factors, that Marketing & Trading would discontinue speculative trading activities. As of September 4, 2003, Marketing & Trading had closed all forward trading positions.

At December 31, 2003, Midstream and its subsidiaries employed 66 people: 24 within Cleco Energy, 41 within Generation Services, and one at Midstream.

For additional information on Midstream's operations, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Midstream," and "- Financial Condition - Cash Generation and Cash Requirements - Midstream Construction and Investment in Subsidiaries."

In March 2001, Cleco sold substantially all of the assets of UTS to Quanta for approximately $3.1 million in cash and assumption of an operating lease for equipment of approximately $11.6 million. For more information about the discontinued operations, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 17 - Discontinued Operations."

Retail electric operations of Cleco Power are subject to the jurisdiction of the LPSC with respect to rates, standards of service, accounting and other matters. Cleco Power is also subject to the jurisdiction of the FERC with respect to certain aspects of its electric business, including rates for wholesale service, interconnections with other utilities, and the transmission of power. Periodically, Cleco Power has sought and received from both the LPSC and the FERC increases in base rates to cover increases in operating costs and costs associated with additions to generation, transmission, and distribution facilities.

Cleco Power's electric rates include a fuel and purchased power cost adjustment clause that enables it to adjust rates for monthly fluctuations in the cost of fuel and short-term purchased power. Revenue from certain off-system sales to other utilities and energy marketing companies are passed on to customers through a reduction in fuel cost adjustment billing factors. Fuel costs and fuel adjustment billing factors are approved by the LPSC and the FERC. These cost adjustments are based on costs from earlier periods that can result in over- or under-recovery for the period in which the adjustment is made. Any over- or under-recovery is corrected by an adjustment in later periods. In the second half of 2002, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit. For additional information on this fuel audit, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters - Fuel Audit."

For additional information on Cleco Power's retail rates, including Cleco Power's current and future rate stabilization plan, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Retail Rates of Cleco Power."

Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state regulation. These franchises are for fixed terms, which may vary from 10 years to 50 years or more. In the past, Cleco Power has been substantially successful in the timely renewal of franchises as each reached the end of its term.

Cleco Power's franchise with the town of Franklinton, and its approximately 1,850 customers, was up for renewal in April 2003. Cleco Power had made an offer to renew the franchise in October 2002 but was not successful in renewing the Franklinton franchise. Instead, a ten-year franchise was granted to a competing cooperative in December 2003. Cleco Power's next municipal franchise renewal is not due until 2008.

The LPSC is evaluating whether it has jurisdiction over municipal franchise agreements in the state. Should the LPSC so decide, Cleco Power's municipal franchises could become subject to the review and approval of the commission. Management does not believe such a jurisdictional change would adversely affect Cleco Power. Cleco Power had 66 municipal franchise agreements as of December 31, 2003.

A number of parishes (counties) have attempted in recent years to impose franchise fees on retail revenue earned within the unincorporated areas Cleco Power serves. If the parishes (counties) are ultimately successful, Cleco Power believes that the new franchise tax paid to the parishes (counties) would be billed to the affected customers and would not increase tax expense, based on current and proposed LPSC regulations.

For information on industry developments, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - - Market Restructuring."

For a discussion of wholesale electric competition, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring - Wholesale Electric Markets."

For a discussion of retail electric competition, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - - Market Restructuring - Retail Electric Markets."

Various federal and state legislative and regulatory bodies are considering a number of issues in addition to those discussed above that will shape the future of the electric utility industry. Such issues include, among others:

The Registrants are unable, at this time, to predict the outcome of such issues or effects on their financial position, results of operations, or cash flows.

For information on certain regulatory matters and regulatory accounting affecting Cleco, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters."

Environmental Matters

Cleco is subject to federal, state, and local laws and regulations governing the protection of the environment. Violations of these laws and regulations may result in substantial fines and penalties. Cleco has obtained all material environmental permits necessary for its operations, and management believes Cleco is in substantial

compliance with these permits, as well as all applicable environmental laws and regulations. Environmental requirements continue to increase as a result of new legislation, administrative actions, and judicial interpretations. Therefore, the precise future effects of existing and potential requirements are difficult to determine. During 2003, Cleco's capital expenditures related to environmental compliance were approximately $1.6 million, due largely to environmental capital additions at Cleco Power and Acadia. Expenditures related to environmental compliance are estimated to total $1.8 million in 2004. The following table lists capital expenditures for environmental matters by subsidiary.

On October 14, 2003, Cleco was notified by the Texas Commission on Environmental Quality (TCEQ) of its identification of the San Angelo Electric Service Company (SESCO) facility that may constitute endangerment to public health and safety of the environment. Based on the TCEQ's preliminary investigation of this facility's historical records, Cleco has been identified as being associated with the site operations and was requested to provide information concerning its relationship with this facility. A written response to the TCEQ was submitted on December 16, 2003, which stated that Cleco discovered no evidence that any waste materials or hazardous substances were sent by Cleco to SESCO and that SESCO provided very minimal service work for Cleco. Based on management's estimates, Cleco Power accrued a minimal amount for possible remediation of the facility site in November 2003.

The state of Louisiana regulates air emissions from each of Cleco's generating units through the Air Quality regulations of the LDEQ. In addition, the LDEQ implements certain programs initially established by the federal EPA. The LDEQ establishes standards of performance or requires permits for certain generating units in Louisiana. All of Cleco's generating units are subject to these requirements.

The federal Clean Air Act established a regulatory program to address the effects of acid rain and imposed restrictions on SO₂emissions from certain generating units. The Clean Air Act essentially requires that certain generation stations, such as those owned by Cleco Power, Evangeline, Acadia, and Perryville, must hold a regulatory "allowance" for each ton of SO₂emitted beginning in the year 2000. The EPA is required to allocate a set number of allowances to each affected unit based on its historic emissions. As of December 31, 2003, Cleco Power and Perryville have sufficient allowances for 2004 operations. Evangeline has allowances in excess of those required for 2004 compliance. Acadia will be required to obtain allowances in 2004 determined by the amount of generation from 2003.

The Clean Air Act requires the EPA to revise NOx emission limits for existing coal-fired boilers. In November 1996, the EPA finalized rules lowering the NOx emission rate for certain boilers, including Rodemacher Unit 2 and Dolet Hills Unit 1, which are partially owned by Cleco Power. Under this rule, Rodemacher Unit 2 and Dolet Hills Unit 1 would have had to meet this new emission rate by January 1, 2000. The rule also allowed an "early elect" option to achieve compliance with a less restrictive NOx limit beginning no later than January 1, 1997. Cleco Power exercised this option in December 1996. Early election protects Cleco Power from any further reductions in the NOx permitted emission rate until 2008. Rodemacher Unit 2 and Dolet Hills Unit 1 have been in compliance with the NOx early election limits since 1998 and are expected to continue to be in compliance in 2004 without undergoing significant capital improvements. Significant future reductions in NOx emission limits may require modification of burners or other capital improvements at one or both of the units.

NOx emissions from the Evangeline, Perryville, and Acadia generating units fall well within EPA limits, as the units use a combination of natural gas as a fuel, modern turbine technology, and selective catalytic reduction technology that reduces NOx emissions to minimal levels.

On December 15, 2003, EPA issued a proposed rule to set maximum achievable control technology standards for coal- and oil-fired electric utility steam generating units pursuant to Section 112 of the Clean Air Act. As an alternative to regulation under Section 112, EPA is proposing to revise its December 20, 2000, finding that regulation of coal- and oil-fired Electric Utility Steam Generating Units (EUSGUs) under Section 112 is "appropriate and necessary" and instead is proposing to set standards of performance for mercury for new and existing coal-fired EUSGUs and for nickel for new and existing oil-fired EUSGUs pursuant to Section 111 of the Clean Air Act (the New Source Performance Standards, NSPS). Under EPA's NSPS approach, mercury would be regulated via a cap and trade program. Regardless of which approach is ultimately undertaken, the EPA intends to require reductions in the emissions of mercury and nickel from coal- and oil-fired EUSGUs, respectively.

On December 17, 2003, EPA proposed the Interstate Air Quality Rule, which imposes obligations on states to address the interstate transport of pollutants. EPA has proposed to require certain upwind states, including Louisiana, to revise their State Implementation Plans to include control measures to reduce SO₂ and NOx. The first phase of emissions reductions would be implemented by 2010, with the second phase by 2015. According to the EPA, the proposed emission reduction requirements are based on controls that are known to be highly cost effective for electric generating units. Under the proposal, states could adopt a model cap and trade program for SO₂ and NOx to meet the proposed emission reduction requirements. The proposal includes only a conceptual overview of the model program; the program itself, in addition to other issues, will be addressed in greater detail in a future Supplemental Notice of Proposed Rulemaking to be issued by May 2004.

Cleco will monitor the development of these new regulatory requirements and their potential impacts to Cleco. While it is

unknown at this time what the final outcome of these regulations will be, any capital and operating costs of additional pollution control equipment that may be required could materially adversely affect future results of operations, cash flows, and possibly financial condition, unless such costs could be recovered through regulated rates or future market prices for energy.

Cleco has received from the EPA and LDEQ permits required under the Clean Water Act for water discharges from its six generating stations. Water discharge permits have fixed dates of expiration and Cleco applies for renewal of these permits within the applicable time periods. The LDEQ has been delegated the National Pollutant Discharge Elimination System (NPDES) program and issues a single Louisiana Pollution Discharge Elimination System (LPDES) permit in lieu of the separate federal and state permits. As older NPDES permits are renewed, they will become LPDES permits. Currently, Cleco Power's Rodemacher and Teche power plants have LPDES permits pending before the LDEQ which are expected to be issued before the fourth quarter of 2004.

The federal Clean Water Act, which was passed in 1972, contains provisions requiring the EPA to evaluate all bodies of water within its jurisdiction to determine if they meet water quality standards and to establish a program to bring non-compliant bodies of water into compliance with the standards. Given the enormous number of bodies of water required to be evaluated and the complexity of standards set forth in the Clean Water Act, the EPA has not completed the requirements. In October 1999, the EPA received a federal court order to develop and implement Total Maximum Daily Loading (TMDL) for all impacted streams in Louisiana. In November 1999, the EPA filed an appeal. In February 2000, the EPA established and submitted a modified list of impaired water bodies, approved by the court. In July 2001, the U.S. Fifth Circuit Court of Appeals vacated and remanded the case to the U.S. District Court (Eastern District of Louisiana) and allowed the EPA Region 6 and LDEQ to revise the TMDL schedule. The revised schedule includes target completion dates from 2004 through 2011 for those TMDLs not already completed. The TMDL will restrict the amount of specific covered pollutants that may be discharged under revised LPDES permits, which will incorporate the limitations of TMDLs. The EPA has released TMDLs for copper, oxygen demanding substances, and nutrients on certain water bodies, none of which have had a material impact on Cleco. Cleco continues to evaluate the potential impact of TMDL limitations currently being developed by the LDEQ and EPA.

Another new regulatory program, Section 316(b) of the Clean Water Act, which deals with minimizing adverse environmental impacts to all aquatic species due to water intake structures, may require some capital improvements to several of Cleco's generation facilities. The regulations are anticipated to be published in early 2004 and only apply to existing facilities. These regulations establish requirements applicable to the location, design, construction, and capacity of cooling water intake structures. Cleco anticipates that any new requirements will be established as the facilities go through the LPDES permit renewal process and will be established on a site-specific basis. LDEQ implementation of this regulation is in the initial development stages, so capital and operating costs for implementing these regulations are not known at the present time.

During the 2001 session, the Louisiana State Legislature passed laws that require the Department of Natural Resources to evaluate the need for new regulations to ensure that Louisiana's water resources are managed in an effective manner. The EPA issued regulations requiring a 60-day prior notification for new wells over certain capacities. These regulations will not have a material adverse effect on Cleco's financial condition or results of operations.

In late December 2002, Acadia was issued a Consolidated Compliance Order and Notice of Potential Penalty from the LDEQ. The enforcement action was due to exceedances of the facility's water discharge permit. Most of the exceedances were due to initial startup difficulties that have been corrected. In addition, on December 31, 2002, Evangeline was issued a Notice of Violation for exceedances of hourly discharge limitations that also have been corrected. The LDEQ imposed a penalty of $5,638 (paid July 2003) on Acadia as a result of these exceedances. Evangeline was not assessed a penalty for its violation.

The Solid Waste Division of the LDEQ has adopted regulations and a permitting system for the management and disposal of solid waste generated by power stations. Cleco has received all required permits from the LDEQ for the on-site disposal of solid waste from its generating stations.

Cleco produces certain wastes that are classified as hazardous at its six generating stations and at other locations. The Hazardous Waste Division of the LDEQ regulates these wastes and has issued identification numbers to the sites where such wastes are generated. Cleco does not treat, store long-term, or dispose of these wastes on-site; therefore, no permits are required. All hazardous wastes produced by Cleco are disposed of at federally permitted hazardous waste disposal sites.

The Toxics Release Inventory (TRI) is a part of the Emergency Planning and Community Right to Know Act administered by the EPA. The TRI requires an annual report from industrial facilities on about 650 substances that they release into air, water, and land. The TRI ranks companies based on how much of a particular substance they release on a state and parish (county) level. Cleco was exempt from the reporting requirements of the TRI until the EPA added seven new industry groups, including electric utility facilities, to the TRI in May 1997. Annual reports are due to the EPA on July 1 following the reporting year-end. Cleco has submitted timely TRI reports on its activities and the TRI rankings are available to the public. The rankings do not result in any federal or state penalties and, in management's estimation, have not caused significant adverse public perceptions of Cleco. Management is aware of the potential adverse effects and is continuing to monitor the TRI process. Management currently is taking steps such as increasing the recycling of fly ash at Dolet

Hills, to protect the environment and to protect against possible negative public perceptions of Cleco as a result of the TRI.

The possibility that exposure to Electric and Magnetic Fields (EMFs) emanating from electric power lines, household appliances and other electric devices may result in adverse health effects or damage to the environment has been a subject of some public attention. Cleco Power funds scientific research on EMFs through various organizations. To date, there are no definitive results, but research is continuing. Lawsuits alleging that the presence or use of electric power transmission and distribution lines has an adverse effect on health and/or property values have arisen in several states against electric utilities and others. Cleco Power is not a party in any lawsuits related to EMFs.

No customer accounted for 10% or more of Cleco's consolidated revenue or Cleco Power's revenue in 2003, 2002, or 2001. Additional information regarding Cleco's sales and revenues is set forth in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations."

For information on Cleco's construction program, financing and related matters, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements."

All of Cleco Power's electric generating stations and all other electric operating properties are located in the state of Louisiana. Cleco Power considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Cleco Power's generating facilities, see Item 1, "Operations - Cleco Power - Power Generation."

Electric Generating Stations

As of December 31, 2003, Cleco Power either owned or had an ownership interest in three steam electric generating stations and one gas turbine with a combined electric net generating capacity of 1,358,900 kilowatts. For additional information on Cleco Power's generating facilities, see Item 1, "Operations - Cleco Power - Power Generation."

As of December 31, 2003, Cleco Power owned 69 active transmission substations and 224 active distribution substations.

As of December 31, 2003, Cleco Power's transmission system consisted of approximately 67 circuit miles of 500 kiloVolt (kV) lines; 462 circuit miles of 230 kV lines; 663 circuit miles of 138 kV lines; and 17 circuit miles of 69 kV lines. Cleco Power's distribution system consisted of approximately 3,064 circuit miles of 34.5 kV lines and 8,068 circuit miles of other lines.

Cleco Power owns various properties, which include a headquarters office building, regional offices, service centers, telecommunications equipment, and other facilities for general purposes.

Cleco Power's electric generating plants and certain other principal properties are owned in fee. Electric transmission and distribution lines are located either on private rights-of-way or along streets or highways by public consent.

Substantially all of Cleco Power's property, plant and equipment are subject to a lien securing obligations of Cleco Power under an Indenture of Mortgage, which does not impair the use of such properties in the operation of its business.

Midstream considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Midstream's generating facilities, see Item 1, "Operations - Midstream."

As of December 31, 2003, Midstream owned two steam electric generating stations, Evangeline and Perryville and had a 50% ownership interest in an additional station, Acadia. For additional information on Midstream's generating facilities, see Item 1, "Operations - Midstream." Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. For additional information on Perryville's pending sale and the bankruptcy filings to facilitate this sale, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville," and Note 30 - "Subsequent Events - Perryville."

As of December 31, 2003, Cleco Energy had an ownership interest in 415 miles of gas gathering and transmission pipeline in Texas and Louisiana, as well as oil and gas producing properties in Texas.

Midstream's assets are owned in fee, including Midstream's portion of Acadia. Evangeline and Perryville are subject to a lien securing obligations under an Indenture of Mortgage, which does not impair the use of such properties in the operation of their businesses. The bankruptcy filings by Perryville and PEH caused Perryville to be in default of the Indenture of Mortgage. Various other properties are also subject to mortgages associated with the

debt used to acquire such properties. For information on the bankruptcy filings by Perryville and PEH, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

For information on legal proceedings affecting Cleco, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Gas Put Options," "- Review of Trading Activities," "- Fuel Audit," "- Gas Transportation Charge," and see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 16 - Securities Litigation and Other Commitments and Contingencies," Note 19 - "Review of Trading Activities," Note 22 - "Gas Transportation Charge," Note 27 - - "Perryville - Mirant Bankruptcy," "- Rejection of the Perryville Tolling Agreement," "- Perryville Allowance and Immediate Payment of Administrative Expenses Claim," "- Perryville Tolling Agreement Damage Claims," and Note 30 - "Subsequent Events - Perryville."

For information on legal proceedings affecting Cleco Power, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - - Gas Put Options," "- Review of Trading Activities," "- Fuel Audit," "- Gas Transportation Charge," and see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 16 - Securities Litigation and Other Commitments and Contingencies," Note 19 - "Review of Trading Activities," and Note 22 - "Gas Transportation Charge."

There were no matters submitted to a vote of security holders of Cleco during the fourth quarter of 2003.

The information called for by Item 4 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Executive Officers of the Registrants

The names of the executive officers of Cleco and certain subsidiaries, their positions held, five-year employment history, ages, and years of service as of December 31, 2003, are presented below. Executive officers are appointed annually to serve for the ensuing year or until their successors have been appointed.

Name of Executive	Position and Five-Year Employment History

David M. Eppler Cleco Corporation	President and Chief Executive Officer since May 2000; President and Chief Operating Officer from January 1999 to May 2000; Executive Vice President and Chief Operating Officer from July 1997 to January 1999.


Cleco Power	Chief Executive Officer since October 2003; President and Chief Executive Officer from May 2000 to October 2003; President and Chief Operating Officer from January 1999 to May 2000; Executive Vice President and Chief Operating Officer from July 1997 to January 1999. (Age 53; 23 years of service)


Michael H. Madison Cleco Power	President and Chief Operating Officer since October 2003; State President of American Electric Power - Louisiana/Arkansas from June 2000 to September 2003; President, Director and Board Chairman of American Electric Power/SWEPCO from May 1998 to June 2000. (Age 55; 1 year of service)


R. O'Neal Chadwick, Jr Cleco Corporation Cleco Power	Senior Vice President, General Counsel, and Corporate Secretary since April 2003; Senior Vice President and General Counsel from October 2002 to April 2003; Vice President of Legal Affairs from April 2002 to October 2002; Manager of Legal Services from May 2000 to April 2002; Assistant General Counsel of Entergy Services, Inc. from February 1999 to May 2000; Senior Attorney of Entergy Services, Inc. from May 1995 to February 1999. (Age 43; 4 years of service)


Catherine C. Powell Cleco Corporation Cleco Power	Senior Vice President of Corporate Services since October 2002; Senior Vice President of Employee and Corporate Services from July 1997 to October 2002. (Age 48; 13 years of service)


Dilek Samil Cleco Corporation Cleco Power	Senior Vice President of Finance and Chief Financial Officer since October 2001; Vice President of Special Projects, FPL Group, Inc., from June 2000 to October 2001; Vice President of Finance, FPL Energy, from September 1999 to June 2000, Treasurer, FPL Group, Inc., from May 1991 to September 1999. (Age 48; 3 years of service)


George W. Bausewine Cleco Corporation Cleco Power	Vice President of Regulatory and Rates since October 2002; Vice President of Strategic and Regulatory Affairs from July 2000 to October 2002; General Manager - Sales and Marketing from February 1998 to July 2000. (Age 48; 18 years of service)


Stephen M. Carter Cleco Power	Vice President of Regulated Generation since April 2003; General Manager of Regulated Generation from November 2002 to April 2003; Plant Superintendent of Dolet Hills Power Station from September 2000 to November 2002; Operations and Maintenance Supervisor of Dolet Hills Power Station from July 1998 to September 2000. (Age 44; 16 years of service)


R. Russell Davis Cleco Corporation Cleco Power	Vice President and Controller since June 2000; Controller of Central and South West Services, Inc., a subsidiary service company of Central & South West Corporation, and Controller of Central & South West Corporation's four U.S. electric utility operating companies from 1994 to June 2000. (Age 47; 4 years of service)


Jeffrey W. Hall Cleco Power	Vice President of Customer Services since October 2002; Vice President of Retail Energy Services from July 1997 to October 2002. (Age 52; 23 years of service)


Mark H. Segura Cleco Power	Vice President of Energy Transmission and Distribution since October 2002; Senior Vice President of Utility Operations from April 1999 to October 2002; Vice President - Distribution Services from July 1997 to April 1999. (Age 45; 19 years of service)


Michiele A. Shaw Cleco Corporation Cleco Power	Vice President of Human Resources, Communications, and Ethics since October 2002; Vice President of Employee and Organizational Development from April 2002 to October 2002; General Manager of Employee and Organizational Planning and Development from July 2000 to April 2002; Self-employed at Shaw Consulting from 1989 to July 2000. (Age 53; 4 years of service)

Samuel H. Charlton III Midstream	Senior Vice President and Chief Operating Officer of Midstream since March 2003; Vice President of Midstream from October 2002 to March 2003; Senior Vice President of Asset Management from November 2000 to October 2002; President and Chief Executive Officer of Cleco Energy since September 1999; Executive Vice President of Cleco Energy from November 1997 to September 1999. (Age 58; 7 years of service)


Kathleen F. Nolen Cleco Corporation Cleco Power	Treasurer since December 2000; Assistant Corporate Secretary since July 2003; Assistant Treasurer from April 1999 to December 2000; Manager - Purchasing from October 1993 to April 1999. (Age 43; 20 years of service)


Judy P. Miller Cleco Corporation Cleco Power	Assistant Controller since July 2000; Acting Controller from February 2000 to July 2000; Manager - Internal Audit from May 1998 to February 2000. (Age 46; 20 years of service)


Janice M. Mount Cleco Corporation Cleco Power	Assistant Corporate Secretary since July 2003; Director of Board Services from March 2003 to July 2003; Team Leader Executive Support Services from July 2000 to March 2003; Executive Assistant from May 1998 to July 2000. (Age 60; 19 years of service)

On January 28, 2004, Perryville entered into an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. As part of the sales process, Perryville and PEH, also a subsidiary of Midstream and the parent company of Perryville, filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. Mr. Eppler, Ms. Samil, and Mr. Charlton are or have been managers of Perryville and/or PEH within the two years preceding the voluntary bankruptcy filing. For more information regarding the pending sale of the Perryville facility and the related bankruptcy filing, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

ITEM 5. MARKET FOR CLECO CORPORATION'S COMMON EQUITY, CLECO POWER'S
MEMBERSHIP INTERESTS AND RELATED STOCKHOLDER MATTERS

Cleco Corporation's common stock is listed for trading on the New York Stock Exchange (NYSE) and the Pacific Exchange. For information on the high and low sales prices for Cleco Corporation's common stock as reported on the NYSE Composite Tape and dividends paid per share during each calendar quarter of 2003 and 2002, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 29 - Miscellaneous Financial Information (Unaudited)." For information on Cleco Corporation's common stock repurchase program, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 7 - Common Stock - Common Stock Repurchase Program."

Subject to the prior rights of the holders of the respective series of Cleco Corporation's preferred stock, such dividends as determined by the Board of Directors of Cleco Corporation may be declared and paid on the common stock from time to time out of funds legally available. The provisions of Cleco Corporation's charter applicable to preferred stock and certain provisions contained in the debt instruments of Cleco under certain circumstances restrict the amount of retained earnings available for the payment of dividends by Cleco Corporation. The most restrictive covenant requires Cleco Corporation's total indebtedness be less than or equal to 75% of total capitalization. At December 31, 2003, approximately $126.8 million of retained earnings were unrestricted. On January 23, 2004, Cleco Corporation's Board of Directors declared a quarterly dividend of $0.225 per share, which dividend was paid on February 15, 2004, to common shareholders of record on February 2, 2004.

As of February 29, 2004, there were 8,628 holders of record of Cleco Corporation's common stock, and the closing price of Cleco Corporation's common stock as reported on the NYSE Composite Tape was $18.97 per share.

There is no market for Cleco Power's membership interests. All of Cleco Power's outstanding membership interests are owned by its parent, Cleco Corporation. Distributions on Cleco Power's membership interests are paid when and if declared by Cleco Power's Board of Managers. Cleco Power's current credit agreement contains restrictions on its ability to pay cash distributions on its membership interests. Any future distributions also may be restricted by any credit or loan agreements that Cleco Power may enter into from time to time.

Some provisions in Cleco Power's debt instruments restrict the amount of equity available for distribution to Cleco Corporation by Cleco Power under specified circumstances. The most restrictive covenant requires Cleco Power's total indebtedness be less than or equal to 65% of total capitalization. At December 31, 2003, approximately $224.8 million of member's equity were unrestricted.

The following table shows the distributions or dividends paid by Cleco Power to Cleco Corporation during 2001, 2002, and 2003:

The information set forth below should be read in conjunction with the Consolidated Financial Statements and the related Notes in Item 8, "Financial Statements and Supplementary Data."

The information called for by Item 6 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(a) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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

Cleco is a diversified regional energy services holding company that has two principal operating business segments:

While Cleco Power has always been Cleco's foundation, Cleco began to expand its merchant energy business in the late 1990s. As of December 31, 2003, Cleco owned all or part of three merchant generation facilities with a net capacity of 2,073 MW. In connection with building the facilities, the subsidiaries of Cleco that owned the respective facilities entered into long-term tolling agreements. With the downturn in the wholesale energy market, Cleco pulled back from its plans to continue expanding its merchant energy business and has focused on maximizing the value of its merchant energy assets. During 2003, Cleco was successful in restructuring the Acadia Tolling Agreements to eliminate a parental guarantee and credit risk associated with the Aquila counterparty, and to increase the amount of credit support that could be drawn on in case of a default by the remaining tolling agreement counterparty, Calpine. In addition, in early 2004, Cleco reached an agreement to sell the Perryville facility to Entergy Louisiana, Inc. for $170.0 million, subject to certain adjustments. In order to facilitate an orderly sales process, Perryville and PEH filed voluntary petitions for bankruptcy protection. During 2003, Cleco recorded a $148.0 million noncash impairment charge relating to the Perryville facility. For information on Perryville, the sale agreement, a related power purchase agreement and the bankruptcy filings, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville," and Note 30 - "Subsequent Events - Perryville."

While management believes that Cleco remains a fundamentally strong company, Cleco faces the following near-term challenges:

Cleco Power currently has three power purchase contracts for 760 MW of capacity, all but 100 MW of which expire on December 31, 2004. While Cleco Power initiated a solicitation to identify existing or new generation resources for 2005 and beyond in the second quarter of 2003, no satisfactory proposals were received. Cleco Power has created an IRP team to evaluate generation supply options.

Cleco Power's current rate stabilization plan expires in September 2004. On February 13, 2004, Cleco Power filed to obtain a one-year extension without modification. This extension would allow Cleco Power time to develop a long-range IRP, solicit new market proposals and evaluate the best options to create an efficient generation portfolio.

In the second half of 2002, the LPSC commenced a fuel audit of Cleco Power. A Cleco Power customer has intervened and is involved in the LPSC fuel audit proceeding. The LPSC Staff has stated that it expects to issue its preliminary findings and recommendations related to the fuel audit proceeding by March 31, 2004. Management is unable to predict the results of the fuel audit, which could require Cleco Power to refund previously recovered revenue and could adversely impact the Registrants' results of operations and financial condition.

Cleco's merchant energy business is heavily dependent on the performance of the Acadia and Evangeline tolling agreements. The credit ratings of the parent companies of these tolling agreement counterparties, The Williams Companies, Inc. and Calpine, have been downgraded below investment grade, and in some cases, placed on negative outlook. Failure of the counterparties to perform under their respective tolling agreements will likely adversely impact Cleco's results of operations, financial condition and cash flows.

Certain reclassifications have been implemented to make the 2002 and 2001 consolidated financial statements conform to the presentation used in the 2003 consolidated financial statements. These reclassifications had no effect on net income applicable to common stock or total common shareholders' equity.

RESULTS OF OPERATIONS

Cleco Consolidated Results of Operations - Year ended December 31, 2003, Compared to Year ended December 31, 2002

Consolidated net (loss) income applicable to common stock decreased $106.8 million in 2003 compared to 2002, principally due to $156.3 million of impairment charges recorded at Midstream during 2003. Also contributing to the decrease were higher interest expense and higher corporate legal and consulting fees associated with the FERC and LPSC investigations of certain trading activities. On July 25, 2003, the FERC approved a settlement resolving its investigation of Cleco's energy marketing and trading practices, a review of which was initially disclosed in November 2002. The settlement included penalties and remedies that resulted in a $0.9 million decrease in consolidated pre-tax net income. For information on the trading activities, the investigations, and the settlement of the FERC's investigation, see "- Financial Condition - Regulatory Matters - Gas Put Options," "- Review of Trading Activities," "- Fuel Audit," "- Gas Transportation Charge", Item 8 - "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 19 - "Review of Trading Activities," and Note 25 - "FERC Settlement."

Operating revenue increased $153.4 million, or 21.3%, in 2003 compared to 2002, largely as a result of higher base, fuel cost recovery, and transmission revenues from utility customer sales, higher tolling revenue from commencement of full commercial operation of the Perryville facility in the third quarter of 2002, and higher energy operations revenue due to increased prices and volumes of natural gas marketed. Partially offsetting these increases were lower trading margins and lower other operations revenue.

Operating expenses increased $329.0 million, or 58.3%, in 2003 compared to 2002, primarily due to the $156.3 million impairments of long-lived assets at Perryville and Cleco Energy. Also contributing to this increase were higher prices for natural gas purchased for fuel generation and marketing purposes, increased depreciation expense at Perryville and Evangeline, and increased other operations and maintenance expenses at Perryville, Evangeline, and Cleco Power. These increases in operating expenses were partially offset by the absence in 2003 of organizational restructuring expenses recognized in 2002.

Equity income from investees increased $15.4 million, or 95.2%, in 2003 compared to 2002, primarily as a result of the

commencement of full commercial operation of the Acadia facility in August 2002. Interest charges increased $10.8 million, or 17.9%, compared to 2002, primarily due to the cessation of capitalizing interest-related expenses associated with the Perryville facility and Acadia once these facilities commenced commercial operation in addition to higher interest rates.

Results of operations for Cleco Power and Midstream are more fully described below.

Retail rates for residential, commercial, and industrial customers and other retail sales are regulated by the LPSC. Retail rates consist of a base rate and a fuel rate. Base rates are designed to allow recovery of the cost of providing service and a return on utility assets. Fuel rates fluctuate while generally allowing recovery of, with no profit, the costs of purchased power and fuel used to generate electricity. Rates for transmission service and wholesale power sales are regulated by the FERC. An LPSC-approved rate stabilization plan is in place through September 2004. This plan effectively allows Cleco Power the opportunity to realize a regulatory rate of return of up to 12.625%. As part of the rate stabilization plan, the LPSC annually reviews revenue and return on equity. A new plan may be ordered by the LPSC upon expiration of the existing plan, or the existing plan may be extended with or without modification. In addition, the LPSC may compel a rate proceeding as part of any scenario. On February 13, 2004, Cleco Power filed to obtain a one-year extension without modification. This extension would allow Cleco time to develop a long-range IRP, solicit new market proposals, and evaluate the best options to create an efficient generation portfolio. Any modification of the existing rate plan or a new rate plan may significantly impact both Cleco and Cleco Power's future results of operations, financial condition, and cash flows.

Cleco Power's residential customers' demand for electricity largely is affected by weather. Weather generally is measured in cooling degree-days and heating degree-days. A cooling degree-day is an indication of the likelihood that a consumer will use air conditioning, while a heating degree-day is an indication of the likelihood that a consumer will use heating. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days, because customers can choose an alternative fuel source for heating, such as natural gas. Normal heating degree-days and cooling degree-days are calculated for a month by separately calculating the average actual heating and cooling degree-days for that month over a period of about 30 years.

Cleco Power's commercial and industrial customers' demand for electricity is affected less by the weather and primarily is dependent upon the strength of the economy and by the worldwide demand for the customers' products compared to their ability to produce the products economically. Cleco Power's two largest customers manufacture wood products, such as newsprint, cardboard, corrugated packaging, and kraft paper.

Kilowatt-hour sales to retail electric customers have grown an average of 1.8% annually over the last five years and are expected to grow from 1.0% to 1.4% per year during the next five years. The growth of future sales will depend upon factors such as weather conditions, customer conservation efforts, retail marketing and business development programs, and the economy of Cleco Power's service area. Some of the issues facing the electric utility industry that could affect sales include:

For additional primary areas subject to potential energy legislation that could affect Cleco, see "- Financial Condition - Market Restructuring - Wholesale Electric Markets."

Changes in fuel and purchased power expenses reflect fluctuations in fuel used for electric generation, fuel handling costs, availability of economical power for purchase, and deferral of expenses for recovery from customers through the fuel adjustment clause in subsequent months. In comparison to other regional suppliers, Cleco's dependence on natural gas is greater. As a result, Cleco's reliance on natural gas as a component of its fuel mix could impact future earnings as a result of existing competition, primarily wholesale competition, and if and when full retail choice emerges.

Changes in fuel costs historically have not significantly affected Cleco Power's net income. Generally, fuel and purchased power expenses are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to customers substantially all such charges. Cleco Power's fuel adjustment clause is regulated by the LPSC (which represent about 93% of its total fuel costs) and the FERC. In the second half of 2002, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit. A Cleco Power customer has intervened and is involved in the LPSC fuel audit proceeding. Recovery of fuel adjustment clause costs is subject to refund until monthly approval is received from the LPSC; however, all amounts are subject to a periodic fuel audit by the LPSC. The LPSC Staff has stated that it expects to issue its preliminary findings and recommendations related to the fuel audit proceeding by March 31, 2004. Management is unable to predict the results of the fuel audit, which could require Cleco Power to refund previously

recovered revenue and could adversely impact the Registrants' results of operations and financial condition. For additional information on this audit, see "- Financial Condition - - Regulatory Matters - Fuel Audit."

Cleco Power obtains coal and lignite through long-term contracts and through the spot market. Natural gas is purchased under short-term contracts. Cleco Power has three power contracts with two power marketing companies, Williams Energy and Dynegy, for a total of 705 MW of capacity in 2002 and 2003, increasing to 760 MW of capacity in 2004, and decreasing to 100 MW of capacity in 2005. Because substantially all of these contracts expire on December 31, 2004, Cleco Power continues to evaluate its capacity and energy needs. Cleco Power initiated a solicitation during the second quarter of 2003 to identify existing or new generation resources for 2005 and subsequent years, including new power purchase contracts, to replace the Williams Energy contracts and the Dynegy contract. Cleco Power plans to issue a new RFP in mid-2004 to identify existing or additional generation resources. On January 30, 2004, Cleco Power agreed to terms for a one-year contract to purchase 500 MW of capacity from CES starting in January 2005. Such one-year contracts are not subject to the LPSC's RFP general order requirements but do remain subject to certification approval by the LPSC. Cleco Power anticipates that this contract will be executed by late March 2004 and the 500 MW of capacity from CES is expected to fill the shortfall left by the Williams Energy and Dynegy contracts expiring at the end of 2004. This contract is expected to minimize risks associated with transmission constraints in the area. However, Cleco Power continues to evaluate meeting capacity requirements in future periods. During the third quarter of 2003, Cleco Power created an IRP team to evaluate generation supply options. It is anticipated that the IRP effort will identify the leading alternatives that can provide customers with a long-term supply of power at stable, competitive prices. For additional information on the IRP process, see Part 1, Item 1, "Business - Operations - Cleco Power - Fuel and Purchased Power - Power Purchases." In addition to the power obtained under these contracts, Cleco Power purchases power from energy marketing companies and neighboring utilities to supplement its generation at times of relatively high demand or when the purchase price of the power is less than Cleco Power's cost of generation or other existing power agreements. However, transmission capacity must be available to transport this purchased power to Cleco Power's system. During 2003, 50.4% of Cleco Power's energy requirements were met with purchased power, up from 45.4% in 2002 and 40.3% in 2001.

In future years, depending on the outcome of the IRP process, Cleco Power's power plants may not be able to supply enough power to meet its growing native load. Because of its location on the transmission grid, Cleco Power relies on one main supplier of electric transmission, and constraints sometimes limit the amount of purchased power it can import into its system. The power contracts described above may be affected by these transmission constraints. For information on Cleco Power's purchased power and on certain Cleco Power obligations under the Williams Energy contracts and the Dynegy contract, see "- Financial Condition - Regulatory Matters - Purchased Power."

The majority of other expenses include other operations, maintenance, depreciation, and taxes other than income taxes. Other operations expenses are affected by, among other things, the cost of employee benefits, insurance expenses, and the costs associated with providing customer service. Maintenance expenses associated with Cleco Power's plants generally depend upon the physical characteristics of the plants, as well as planned preventive maintenance. Depreciation expense primarily is affected by the cost of the facility in service, the time the facility was placed in service, and the estimated useful life of the facility. Taxes other than income taxes generally are affected by payroll taxes and ad valorem taxes.

Cleco Power's Results of Operations - Year ended December 31, 2003, Compared to Year ended December 31, 2002

Cleco Power's net income applicable to member's equity for 2003 was $57.0 million compared to $59.6 million for 2002. Contributing factors include:

As reflected on the following page, the aggregation of fuel cost recovery revenue, power purchased for utility customers, and fuel used for electric generation significantly increased in 2003 compared to the same period in 2002. However, changes in these items do not significantly impact net income, since fluctuations in fuel-related costs generally are recovered through fuel cost recovery revenue via Cleco Power's fuel cost adjustment process.

			For the year ended December 31,
			2003	2002	Variance	Change
			(Thousands)
Operating revenue
	Base		$ 311,979	$ 305,383	$ 6,596	2.2 %
	Fuel cost recovery		364,023	262,719	101,304	38.6 %
	Electric customer credits		(1,562)	(2,900)	1,338	46.1 %
	Energy trading, net		626	(752)	1,378	*
	Other operations		30,013	29,331	682	2.3 %
	Intercompany revenue		2,209	1,708	501	29.3 %
		Total operating revenue	707,288	595,489	111,799	18.8 %

Operating expenses
	Fuel used for electric generation		163,869	138,582	25,287	18.2 %
	Power purchased for utility customers		230,691	151,090	79,601	52.7 %
	Other operations		62,742	62,794	(52)	(0.1)%
	Maintenance		44,542	28,170	16,372	58.1 %
	Depreciation		54,084	52,233	1,851	3.5 %
	Restructuring charge		(315)	8,099	(8,414)	*
	Taxes other than income taxes		37,062	36,892	170	0.5 %
		Total operating expenses	592,675	477,860	114,815	24.0 %

Operating income			$ 114,613	$ 117,629	$ (3,016)	(2.6)%
Other expenses			$ 7,775	$ 4,122	$ 3,653	88.6 %
Federal and state income taxes			$ 29,846	$ 32,172	$ (2,326)	(7.2)%
Net income applicable to member's equity			$ 57,008	$ 59,574	$ (2,566)	(4.3)%

* Not meaningful
				For the year ended December 31,
				2003	2002	Change
				(Million kWh)
Electric sales
	Residential			3,429	3,400	0.9 %
	Commercial			1,781	1,722	3.4 %
	Industrial			2,786	2,756	1.1 %
	Other retail			595	593	0.3 %
	Unbilled			39	30	30.0 %
		Total retail		8,630	8,501	1.5 %
	Sales for resale			1,066	715	49.1 %
Total retail and wholesale customer sales				9,696	9,216	5.2 %
Short-term sales to other utilities				169	124	36.3 %
Sales from trading activities				26	262	(90.1)%
		Total electric sales		9,891	9,602	3.0 %

The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior period. In the fourth quarter of 2002, Cleco Power changed the method of determining heating and cooling degree-days and began to use temperature data collected by the National Oceanic and Atmospheric Administration for this purpose. Cooling and heating degree-days for each period indicated have been adjusted to reflect the change in the temperature data source.

Base

Base revenue during 2003 increased $6.6 million, or 2.2%, compared to the same period in 2002. The increase was primarily due to slightly higher volumes of retail and wholesale customer kWh sales. Base revenue also increased approximately $1.1 million as a result of energy management services contracts that commenced in May 2003.

On July 7, 2003, one of Cleco Power's existing wholesale customers entered into a three-year contract with an energy marketing company. This new contract is scheduled to begin once Cleco Power's contract expires on May 31, 2004. The expiration of this contract is expected to reduce annual base revenue by approximately $4.8 million. Also anticipated with the non-renewal of this contract will be a reduction of capacity expenses of approximately $2.0 million, resulting in an expected net annual reduction of $2.8 million in pre-tax operating income.

On July 16, 2003, the LPSC approved Cleco Power's new five-year contract with one of its existing industrial customers. As a result of the terms in the new contract, annual base revenue was $1.0 million lower in 2003 and is expected to be $2.0 million lower for the remaining years of the contract.

During the second quarter of 2004, Cleco Power is expected to begin serving a new industrial customer and during the first quarter of 2005 is expected to begin providing service to an expansion of a current customer's operation. The expected new service and expected expansion of current service are projected to increase 2004 base revenue by approximately $0.6 million and increase annual revenue by approximately $1.5 million beginning in 2005, in each case compared to 2003 base revenue.

Fuel Cost Recovery

Fuel cost recovery revenue collected from customers increased $101.3 million, or 38.6%, primarily as a result of an increase of 37.2% in the average per unit cost of power purchased from the energy market in 2003 compared to 2002 and a 25.6% increase in the average per unit cost of fuel used for electric generation. The increase in fuel used for electric generation is primarily the result of higher natural gas prices. The increase in the per unit cost of purchased power was influenced by higher natural gas prices, as well as other market factors. For information on Cleco Power's ability to recover fuel and purchase power costs, see "- Significant Factors Affecting Cleco Power - Fuel and purchased power are primarily affected by the following factors," above.

Electric customer credits during 2003 were $1.3 million, or 46.1%, lower compared to the same period in 2002. This decrease in electric customer credits is a result of the revised estimate of the

accruals for the rate refund based on actual results for the twelve months ended September 30, 2003. The potential refunds are based on results for each 12-month period ended September 30. For additional information on the accrual for electric customer credits, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 12 - Accrual of Electric Customer Credits."

Decreases in power and gas volumes from 2002 to 2003 were directly related to the discontinuation of speculative trading activities in the fourth quarter of 2002. Most of Cleco Power's exposure to the market was mitigated in the summer of 2002 by transactions entered into specifically to offset open positions. Volumes and associated revenue were affected by these positions during 2003.

Generally, Cleco Power's energy trading transactions are considered non-hedging derivatives under SFAS No. 133, as amended, which requires that the transactions be reported at fair market value or "mark-to-market." The chart below presents the components of energy trading, net.

Energy trading, net, increased $1.4 million in 2003 compared to the same period in 2002. This increase was primarily a result of amounts required to be paid to Cleco Power pursuant to the Consent Agreement and a negative adjustment for premiums on certain gas put options recorded in the third quarter of 2002. In addition, Cleco Power's efforts to mitigate most of its exposure to the market following the discontinuation of speculative trading activities in the fourth quarter of 2002 and volatility in power and natural gas prices contributed to the fluctuations between each period. For additional information on the Consent Agreement and FERC settlement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement."

Operating expenses increased $114.8 million, or 24.0%, in 2003 compared to the same period of 2002. Fuel used for electric generation increased $25.3 million, or 18.2%, primarily due to an increase in the average per unit equivalent cost of fuel from $25.17 per MWh in 2002 to $32.30 per MWh in 2003. Power purchased for utility customers increased $79.6 million, or 52.7%, largely due to an increase in the average per unit cost of purchased power and volume. In addition, power purchased for utility customers increased as a result of higher capacity payments made during 2003. The increase in power purchased for utility customers was partially offset by a $1.1 million decrease resulting from payments received under the Consent Agreement. For additional information on the Consent Agreement and the FERC settlement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement." Increases in fuel used for electric generation and power purchased for utility customers both were influenced significantly by higher natural gas prices. As a result, total system cost increased from $26.22 per MWh in 2002 to $35.04 per MWh in 2003. Maintenance expense during 2003 increased $16.4 million, or 58.1%, compared to 2002. The primary reasons for this increase were increased maintenance expenses from Cleco Power's transmission and distribution reliability initiative, the production availability initiative, restoration efforts associated with Tropical Storm Bill, and the amortization of deferred expenses related to Hurricane Lili and Tropical Storm Isidore. Depreciation expense increased $1.9 million, or 3.5%, as a result of normal recurring additions to fixed assets. Restructuring charge decreased $8.4 million during 2003 compared to 2002 as a result of the absence of an organizational restructuring in 2003. The restructuring charge credit of $0.3 million for the year ended December 31, 2003, represents adjustments made during 2003 to 2002 original estimated amounts.

Other Expenses

Other expenses increased $3.7 million, or 88.6%, during 2003 compared to 2002, primarily due to increased donations, increased community project involvement, and payments made to community action agencies to assist low-income customers. Also contributing to the increase in other expenses was increased expenses related to work performed by Cleco Power employees for the restoration of power along the East Coast after Hurricane Isabel last fall.

Income Taxes

Income tax expense in 2003 decreased $2.3 million, or 7.2%, compared to 2002. The decrease was primarily due to lower taxable income compared to the same period of 2002. For information about assumptions and estimates underlying Cleco Power's accounting for the effect of income taxes, see - "Critical Accounting Policies."

Midstream's revenue is derived predominantly from its power plant operations and energy operations. Revenue from wholly owned power plant operations is derived primarily from tolling contracts. Tolling revenue generally is affected by the overall performance related to the availability and efficiency of the facility to operate and the level at which it operates. A facility's availability can be enhanced or protected by providing replacement power to the tolling counterparties. Each tolling agreement gives a tolling counterparty the right to own, dispatch, and market all of the electric generation capacity of the respective facility. Each tolling counterparty is responsible for providing its own natural gas to the respective facility. Earnings from jointly owned power plant

operations are derived from an equity investment, and they are reflected in equity income from investees. Revenue from energy operations is derived from energy management services and wholesale natural gas marketed.

Tolling revenue is partially derived from a 775-MW combined-cycle, natural gas-fired power plant through the Evangeline Tolling Agreement, and prior to September 15, 2003, tolling revenue was also derived from a 718-MW, natural gas-fired power plant through the Perryville Tolling Agreement. For more information on the termination of the Perryville Tolling Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - - Perryville." Pending the sale of the Perryville facility, tolling revenue at Perryville will be derived from the Entergy Services, Inc., power purchase agreement. For additional information on the power purchase agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville." Through an investment in Acadia, equity earnings are derived primarily from a 1,160-MW combined-cycle, natural gas-fired power plant. Acadia's output currently is sold through the Calpine Tolling Agreements. Prior to May 2003, Acadia's output was sold through two separate tolling agreements: one through the Aquila Tolling Agreement and the other through one of the Calpine Tolling Agreements. In May 2003, Acadia terminated its 580-MW 20-year tolling agreement with Aquila Energy and entered into a replacement contract with CES. For more information on the termination of the Aquila Tolling Agreement and replacement CES agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees." For additional information on Acadia, Evangeline, Perryville, and the tolling agreements related to these facilities, see "- Financial Condition - Liquidity and Capital Resources."

Evangeline and Acadia have certain performance obligations under their respective tolling agreements. Failure to perform could expose each facility to possible adverse financial penalties and requirements which include, but are not limited to, maintaining plant performance characteristics such as heat rate and demonstrated generation capacity at specified levels and maintaining specified availability levels with a combination of plant availability and replacement power. Obligations under the respective tolling agreements include, but are not limited to, maintaining various types of insurance at specified levels, maintaining power and natural gas metering equipment, and paying scheduled interest and principal payments on debt. In addition to the performance obligations by Evangeline and Acadia, there are various guarantees and commitments required by Cleco Corporation. For additional information on commitments by Cleco Corporation, see - "Financial Condition - Off-Balance Sheet Commitments" and Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 23 - Disclosures About Guarantees."

If Evangeline and Acadia fail to operate within specified requirements, the respective facilities may need to purchase replacement power on the open market and provide it to the tolling counterparties. Providing replacement power maintains availability levels, but exposes Evangeline and Acadia to power commodity price volatility and transmission constraints. If availability targets under the tolling agreements are not met and economical purchase power and transmission are not available, Evangeline and Acadia's financial condition and results of operations could be materially adversely affected.

Under the Evangeline Tolling Agreement, Williams Energy pays Evangeline a fixed fee and a variable fee for operating and maintaining the facility. The Evangeline Tolling Agreement is accounted for as an operating lease. For additional information on Cleco's operating leases, see - "Critical Accounting Policies - Midstream" and Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 14 - Operating Leases." Evangeline Tolling Agreement revenue correlates with the seasonal usage of the plant. Evangeline's 2003 revenue was recognized in the following manner:

Revenue for 2004 under the Evangeline Tolling Agreement is anticipated to be recognized in a similar manner. For additional information on recognition of revenue from the Evangeline Tolling Agreement, see "- Critical Accounting Policies - Midstream" and Item 8, "Financial Statements and Supplementary Data - - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Revenue and Fuel Costs - Tolling Revenue."

Prior to the cancellation of the Perryville Tolling Agreement, MAEM paid Perryville a fixed fee and a variable fee for operating and maintaining the facility. MAEM also paid a quarterly amount to Perryville, which represented its share of Perryville's quarterly parts and maintenance expenses under Perryville's long-term maintenance contract with General Electric Corporation. This amount was based upon Perryville's run hours and factored starts for each quarter. The Perryville Tolling Agreement was accounted for as an operating lease. For additional information on the termination of this tolling agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville" and for information on Cleco's operating leases, see "- Critical Accounting Policies - Midstream," and Item 8, "Financial Statements and Supplementary Data - - Notes to the Financial Statements - Note 14 - Operating Leases." Perryville Tolling Agreement revenue was recognized evenly throughout the year. For additional information on recognition of revenue from the Perryville Tolling Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - - Summary of Significant Accounting Policies - Revenue and Fuel Costs - Tolling Revenue."

Prior to the cancellation of the Aquila Tolling Agreement, Aquila Energy paid Acadia a fixed fee and a variable fee for operating and maintaining the facility. Following the termination of the Aquila Tolling Agreement, Acadia entered into a replacement contract with CES. Under the Calpine Tolling Agreements, CES pays Acadia a fixed fee and a variable fee for operating and maintaining the facility. Under each of these tolling agreements,

equity investment earnings from the tolling agreements were recognized evenly throughout the year. For additional information on the termination of the Aquila Tolling Agreement and replacement CES agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - - Note 13 - Equity Investment in Investees."

The parent companies of Cleco's remaining tolling counterparties are The Williams Companies, Inc. and Calpine. Each of these entities has issued guarantees of the payment obligations of the respective tolling counterparties under the tolling agreements. Calpine also issued a $40.0 million letter of credit which provides additional credit support in the event CES does not fulfill its obligations under the Calpine Tolling Agreements. The credit ratings of these parent companies have been downgraded below investment grade, and in some cases, placed on negative outlook. Failure by The Williams Companies, Inc. or Calpine to perform under their respective tolling agreements could adversely impact Cleco's results of operations, financial condition, and cash flows.

The following list discusses some possible adverse consequences if any of Cleco's remaining tolling counterparties should fail to perform their obligations under their respective tolling agreements, or if Cleco Corporation or its affiliates are not in compliance with loan agreements or bond indentures. Cleco's remaining tolling counterparties are Williams Energy and CES. The list is not all-inclusive, but represents examples of possible adverse consequences that could result from the nonperformance of Cleco's remaining tolling counterparties and certain defaults resulting from noncompliance with debt covenant agreements or bond indentures:

	Cleco's financial condition, results of operations and cash flows may be adversely affected by the failure of counterparties to pay amounts due and may not be consistent with historical and projected results.
	Cleco may not be able to enter into replacement agreements on terms as favorable as existing agreements, or at all.
	Cleco would be required to test any long-lived generation asset for impairment if the tolling counterparty defaulted under the related tolling agreement. If it was determined that an impairment existed, the asset would be written down to its fair market value, which could materially adversely affect Cleco's results of operations and financial condition. For more information on long-lived assets, see "- Critical Accounting Policies."
	Possible acceleration of Cleco's project-level debt, in particular:
	1) At December 31, 2003, under the provisions and based on the defaults of the Senior Loan Agreement, lenders holding two-thirds of the loan commitment had the right, but not the obligation, to declare any outstanding principal amount ($133.0 million at December 31, 2003) and interest immediately due and payable. On January 28, 2004, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The outstanding amounts due under the Senior Loan Agreement were deemed accelerated upon the bankruptcy filings by Perryville and PEH. As a result of the commencement of such bankruptcy cases and by virtue of the automatic stay under the U.S. Bankruptcy Code, the lenders' ability to exercise their remedies under the Senior Loan Agreement, including, but not limited to, their ability to foreclose on the mortgage or assume ownership of the Perryville facility, are significantly limited and would require approval of the Bankruptcy Court. For additional information on the bankruptcy filings, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville." For additional information on the Senior Loan Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville - Perryville's Senior Loan Agreement" and "- Financial Condition - Liquidity and Capital Resources - Debt - Cleco Corporation (Holding Company Level)."
	2) Under provisions of the bonds issued by Evangeline, the bondholders have the right to demand the entire outstanding principal amount ($202.8 million at December 31, 2003) plus accrued interest to be immediately due and payable upon a default under the Evangeline Tolling Agreement by Williams Energy. If the bondholders were to exercise this right, Cleco might, among other things, refinance the bonds, pay off the bonds with other borrowings or the proceeds of issuances of additional debt, or cause Evangeline to seek protection under federal bankruptcy laws. In addition, the trustee of the bonds could foreclose on the mortgage and assume ownership of the plant. Any alternative financing would likely be on less favorable terms than the existing terms. The bonds issued by Evangeline are nonrecourse to Cleco Corporation.

Revenue from energy operations generally is affected by transmission constraints, supply and demand in the market, the financial viability of marketing counterparties, and volatility of market prices. Energy operations revenue is comprised of two components: energy management services and wholesale natural gas marketed. Marketing & Trading, prior to the second quarter of 2003, provided energy management services to several municipalities and, prior to the fourth quarter of 2002, marketed and traded wholesale natural gas and electricity. Cleco Energy, also a subsidiary of Midstream, primarily markets wholesale natural gas in Louisiana and Texas and provides energy management services, including fixed-price gas hedges. Cleco Energy generally takes physical delivery of natural gas marketed and sells physical gas instead of settling transactions through the financial markets.

Other operations revenue was derived from services Generation Services provided to Perryville prior to Cleco's acquisition of the remaining interest in Perryville in the summer of 2002. For additional information regarding the acquisition of Perryville, see Item 8, "Financial Statements and Supplementary

Midstream's expenses include impairments of long-lived assets, purchases for energy operations, depreciation, maintenance and other operations expenses. The impairment charges relate to triggering events as defined by SFAS No. 144. Purchases for energy operations are affected primarily by the same factors as energy operations revenue. Depreciation expense is affected by the cost of the facility in service, the time the facility was placed in service, and the estimated useful life of the facility. Maintenance expenses generally depend on the physical characteristics of the facility, the frequency and duration of the facility's operations, and planned preventive maintenance. Other operating expenses mainly relate to administrative expenses and employee benefits.

Midstream's Results of Operations - Year ended December 31, 2003, Compared to Year ended December 31, 2002

Midstream's net loss applicable to member's equity for 2003 was $85.3 million, significantly below the $14.7 million earned in 2002. Contributing factors include:

			For the year ended December 31,
			2003	2002	Variance	Change
			(Thousands)
Operating revenue
	Tolling operations		$ 98,726	$ 90,260	$ 8,466	9.4 %
	Energy trading, net		(2,764)	2,421	(5,185)	*
	Energy operations		71,639	30,050	41,589	138.4 %
	Other operations		711	4,655	(3,944)	(84.7)%
	Intercompany revenue		205	366	(161)	(44.0)%
		Total operating revenue	168,517	127,752	40,765	31.9 %

Operating expenses
	Purchases for energy operations		66,812	25,317	41,495	163.9 %
	Other operations		36,250	27,804	8,446	30.4 %
	Maintenance		15,746	8,902	6,844	76.9 %
	Depreciation		22,399	15,989	6,410	40.1 %
	Restructuring charge		(409)	2,058	(2,467)	*
	Impairments of long-lived assets		156,250	3,587	152,663	*
	Taxes other than income taxes		513	1,536	(1,023)	(66.6)%
		Total operating expenses	297,561	85,193	212,368	249.3 %

Operating (loss) income			$ (129,044)	$ 42,559	$ (171,603)	*

Equity income from investees			$ 31,631	$ 16,204	$ 15,427	95.2 %
Other expenses			$ 897	$ 142	$ 755	*
Interest charges			$ 39,408	$ 31,750	$ 7,658	24.1 %
Federal and state income taxes (benefit) expense			$ (51,807)	$ 12,740	$ (64,547)	*
Net (loss) income applicable to member's equity			$ (85,313)	$ 14,660	$ (99,973)	*

* Not meaningful

Tolling operations revenue increased $8.5 million, or 9.4%, in 2003 compared to 2002 primarily due to the Perryville facility commencing full commercial operation in the third quarter of 2002. This increase was partially offset by decreased generation from the Evangeline facility, which was dispatched less frequently in 2003 compared to 2002.

Decreases in power and gas volumes and trading margins from 2002 to 2003 were directly related to the discontinuation of Midstream's speculative trading activities in the fourth quarter of 2002. Most of Midstream's exposure to the market from positions opened prior to the change in its speculative trading strategy was mitigated in the fourth quarter of 2002 by transactions entered into specifically to offset open positions. Volumes and associated revenue were affected by these positions during 2003. As of September 4, 2003, Marketing & Trading had closed all forward trading positions.

Generally, Midstream's energy trading transactions are considered non-hedging derivatives under SFAS No. 133, as amended, which requires that the transactions be reported at fair

market value or "mark-to-market." The chart below presents the components of energy trading, net.

Energy trading, net, decreased $5.2 million in 2003 compared to 2002. The decrease was primarily due to the discontinuation of Midstream's speculative trading activities in late 2002, as well as amounts required to be paid to Cleco Power under the Consent Agreement. Due to the discontinuance of speculative trading activities and the subsequent closing of all forward trading positions, trading margins are expected to be at a break-even level for future periods. For additional information on the Consent Agreement and FERC settlement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement."

The $41.6 million, or 138.4%, increase in energy operations revenue during 2003 compared to 2002 was primarily due to increases in the average per unit cost of natural gas and volumes of natural gas marketed by Cleco Energy to third parties. In 2002, Cleco Energy sold gas production to Marketing & Trading as a part of its speculative trading portfolio, which included trading physical gas. These affiliate transactions and all intercompany volumes and revenue within Midstream subsidiaries have been eliminated and therefore are not reflected in the charts below. Cleco Energy has marketed more physical gas to third parties in 2003 as a result of Marketing & Trading's discontinuation of speculative trading. This increase in revenue from third parties is reflected below as wholesale natural gas marketed. Energy management services revenue decreased $0.9 million, or 58.2%, and managed kWh decreased 67.1% for 2003 compared to 2002 primarily due to Marketing & Trading's termination of its energy management services contracts in May 2003. The chart below presents the components of energy operations revenue.

The chart below presents a summary of energy management kWh and natural gas marketed during 2003 and 2002.

Other operations revenue decreased $3.9 million, or 84.7%, in 2003 compared to 2002 primarily due to a change in the accounting treatment of Midstream's power plant operations, maintenance, and engineering services that were provided to Perryville. Prior to Midstream's purchase of Mirant's 50% ownership interest in Perryville in June 2002, revenue from these services was included in other operations revenue since Perryville was a 50%-owned joint venture, which did not require elimination of this activity. Subsequent to the acquisition, Perryville's assets, liabilities, revenue, and expenses were accounted for on a consolidated basis effective July 2002. As a result of this change in accounting treatment, all revenue associated with Midstream's plant operations for Perryville is included in intercompany revenue and has been eliminated.

Charges of $156.3 million for impairments of long-lived assets were the principal cause of the significant increase in total operating expenses. For additional information on these charges, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 24 - Impairments of Long-Lived Assets."

Purchases for energy operations increased $41.5 million, or 163.9%, in 2003 compared to 2002, primarily due to the same factors affecting energy operations revenue. Other operations expense increased $8.4 million, or 30.4%, during 2003 compared to 2002, primarily due to increased expenses associated with the commencement of the Perryville facility's full commercial operation in the third quarter of 2002. Additionally, $15.7 million of reserves were recorded at Perryville in 2003, to reflect potentially uncollectible MAEM receivables, as a result of Mirant and certain of its affiliates filing a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 14, 2003, and the related rejection of the Perryville Tolling Agreement. For additional information on Mirant's bankruptcy and the rejection of the tolling agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville." Partially offsetting these increases were decreased other operations expense that resulted primarily from reduced Midstream participation in wholesale energy markets (including wholesale generation asset development, project analytics, energy marketing and trading activities, and power plant engineering services).

Maintenance expenses increased $6.8 million, or 76.9%, in 2003 compared to 2002 primarily due to the commencement of the Perryville facility's full commercial operation in the third quarter of 2002 and increased expenses at Evangeline due to earlier-than-planned replacement of combustion turbine parts and certain repairs on the combustion turbines under the LTP Agreement. In addition, a fourth quarter 2003 settlement entered into under the Modified LTP Agreement increased maintenance expense as a result of expensing prepaid costs under the previous long-term maintenance agreement. The $6.4 million, or 40.1%, increase in depreciation expense was largely due to a $3.5 million increase at Perryville following the completion of construction of the Perryville facility in the third quarter of 2002, partially offset by lower depreciation expense as a result of the asset impairment charges recorded in 2003. Adding to the increase in depreciation expense

was a $3.4 million increase at Evangeline following design changes to certain combustion turbine parts as provided under the LTP Agreement and reassessment of the useful life of combustion turbine parts. Restructuring charge decreased $2.5 million during 2003 compared to 2002 as a result of the absence of an organizational restructuring in 2003. The restructuring charge credit of $0.4 million for the year ended December 31, 2003, represents adjustments made during 2003 to 2002 original estimated amounts. The $1.0 million, or 66.6%, decrease in taxes other than income taxes during 2003 compared to 2002, was primarily the result of state franchise tax adjustments made during 2003 that related to 2002 and decreased payroll taxes as a result of the transfer of employees to other affiliates.

Equity income from investees increased $15.4 million, or 95.2%, for 2003 compared to 2002 primarily due to increased equity earnings from Acadia as a result of the facility beginning full commercial operation in August 2002. For additional information on Acadia, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees."

Other expenses increased $0.8 million during 2003 compared to 2002, primarily due to the payment of a $0.8 million civil penalty agreed to in the Consent Agreement. For additional information on the Consent Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement."

Interest charges increased $7.7 million, or 24.1%, during 2003 compared to 2002, primarily due to a change in the treatment of interest-related expenses associated with Midstream's asset construction activity. Prior to the third quarter of 2002 commencement of commercial operation at Perryville and Acadia, interest related to these projects was capitalized in accordance with SFAS No. 58. Partially offsetting this increase in interest charges was the suspension of interest accruals and payments on Perryville's subordinated debt to Mirant as a result of Mirant's bankruptcy and MAEM's subsequent failure to remit pre-petition amounts under the Perryville Tolling Agreement.

Income Taxes

Income tax accruals provided a net tax benefit of $51.8 million for 2003, a decrease of $64.5 million in net tax expense when compared to 2002. The decrease was largely due to a loss recognized by Midstream as a result of $156.3 million of impairment charges recorded in 2003. For information about the assumptions and estimates underlying Midstream's accounting for the effect of income taxes, see - - "Critical Accounting Policies."

Cleco Consolidated Results of Operations - Year ended December 31, 2002, Compared to Year ended December 31, 2001

	For the year ended December 31,
	2002	2001	Variance	Change
	(Thousands)
Operating revenue	$ 721,224	$ 748,759	$ (27,535)	(3.7)%
Operating expenses	564,228	599,219	(34,991)	(5.8)%

Operating income	$ 156,996	$ 149,540	$ 7,456	5.0%

Equity income from investees	$ 16,204	$ 175	$ 16,029	*
Interest charges	$ 60,609	$ 47,693	$ 12,916	27.1%
Net income from continuing operations	$ 71,875	$ 72,273	$ (398)	(0.6)%
Loss from discontinued operations, net	$ -	$ (2,035)	$ 2,035	*
Net income applicable to common stock	$ 70,003	$ 68,362	$ 1,641	2.4%

* Not meaningful

Consolidated net income from continuing operations for 2002 totaled $71.9 million, a 0.6% decrease compared to 2001. The decrease was primarily due to a one-time recovery of fuel-related costs in 2001, an organizational restructuring charge, gas transportation charges, and impairment of a long-lived asset recorded in 2002, partially offset by increased tolling operations revenue and equity income from investees. For additional information on these charges, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Restructuring Charge," Note 22 - "Gas Transportation Charge," and Note 24 - "Impairments of Long-Lived Assets," respectively.

Cleco Power's slight increase of $0.4 million, or 0.7%, in net income from continuing operations in 2002 compared to 2001 was primarily due to increased base revenue and reduced operating expenses, partially offset by the absence in 2002 of a one-time recovery of fuel-related costs recognized in 2001, and a charge in 2002 for the organizational restructuring referred to above.

Midstream's net income from continuing operations increased $0.2 million, or 1.0%, in 2002 compared to 2001. Most of the increase was due to commencement of full commercial operations in the summer of 2002 at two of Cleco's merchant power plants, as well as increased generation from a third merchant power plant that has been in operation since July 2000. Partially offsetting the increase were lower margins from energy trading and decreased energy operations revenue. Also offsetting the increase at Midstream were a restructuring charge, a charge for impairment of a long-lived asset, and gas transportation charges recorded in 2002 compared to none in 2001. For additional information on these charges, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Restructuring Charge," Note 22 - - "Gas Transportation Charge," and Note 24 - "Impairments of Long-Lived Assets," respectively.

A companywide organizational restructuring was completed in the fourth quarter of 2002. As a result of the restructuring, Cleco's workforce was reduced by 154 employees. The costs associated with restructuring, consisting mainly of early retirement

and severance programs that were offered to eligible employees, resulted in a one-time charge to earnings of $10.2 million before taxes. The restructuring will benefit Cleco in future years by mitigating increases in operating expenses. For additional information on the restructuring charge, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Restructuring Charge."

Income tax expense increased $3.9 million, or 10.1%, in 2002 compared to 2001. Cleco's effective income tax rate increased from 34.7% to 37.0% primarily due to an adjustment related to an internal review of accumulated deferred income taxes.

Consolidated net income applicable to common stock increased $1.6 million, or 2.4%, for 2002 compared to 2001 primarily due to the absence in 2002 of a $2.0 million loss from discontinued operations at UTS experienced in 2001. For additional information regarding the UTS loss, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 17 - - Discontinued Operations."

Cleco Power's Results of Operations - Year ended December 31, 2002, Compared to Year ended December 31, 2001

Cleco Power's net income applicable to member's equity for 2002 was $59.6 million compared to $59.1 million for 2001. Contributing factors include:

			For the year ended December 31,
			2002	2001	Variance	Change
			(Thousands)
Operating revenue
	Base		$ 305,383	$ 287,905	$ 17,478	6.1 %
	Fuel cost recovery		262,719	304,348	(41,629)	(13.7)%
	Electric customer credits		(2,900)	(1,800)	(1,100)	(61.1)%
	Energy trading, net		(752)	1,456	(2,208)	*
	Other operations		29,331	30,813	(1,482)	(4.8)%
	Intercompany revenue		1,708	6,011	(4,303)	(71.6)%
		Total operating revenue	595,489	628,733	(33,244)	(5.3)%

Operating expenses
	Fuel used for electric generation		138,582	184,479	(45,897)	(24.9)%
	Power purchased for utility customers		151,090	140,524	10,566	7.5 %
	Other operations		62,794	81,868	(19,074)	(23.3)%
	Maintenance		28,170	25,773	2,397	9.3 %
	Depreciation		52,233	50,594	1,639	3.2 %
	Restructuring charge		8,099	-	8,099	*
	Taxes other than income taxes		36,892	35,358	1,534	4.3 %
		Total operating expenses	477,860	518,596	(40,736)	(7.9)%

Operating income			$ 117,629	$ 110,137	$ 7,492	6.8 %
Other expenses			$ 4,122	$ 20,463	$ (16,341)	(79.9)%
Interest charges			$ 29,091	$ 26,819	$ 2,272	8.5 %
Federal and state income taxes			$ 32,172	$ 31,290	$ 882	2.8 %
Net income applicable to member's equity			$ 59,574	$ 59,138	$ 436	0.7 %

* Not meaningful
				For the year ended December 31,
				2002	2001	Change
				(Million kWh)
Electric sales
	Residential			3,400	3,201	6.2 %
	Commercial			1,722	1,655	4.0 %
	Industrial			2,756	2,640	4.4 %
	Other retail			593	581	2.1 %
	Unbilled			30	34	(11.8)%
		Total retail		8,501	8,111	4.8 %
	Sales for resale			715	398	79.6 %
Total retail and wholesale customer sales				9,216	8,509	8.3 %
Short-term sales to other utilities				124	145	(14.5)%
Sales from trading activities				262	19	*
		Total electric sales		9,602	8,673	10.7 %

* Not meaningful

The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior year. In the fourth quarter of 2002, Cleco Power changed the method of determining heating and cooling degree-days and began to use temperature data collected by the National Oceanic and Atmospheric Administration for this purpose. Cooling and heating degree-days for each period indicated have been adjusted to reflect the change in the temperature data source.

Base revenue increased $17.5 million, or 6.1%, from 2001 to 2002. The increase was primarily due to higher retail sales resulting from customer growth and increased cooling degree-days and heating degree-days compared to normal and prior year, as shown in the chart above. The 79.6% increase in sales for resale volume was primarily due to the addition of one wholesale customer in June 2001 and a second wholesale customer in January 2002.

Fuel cost recovery revenue collected from customers decreased $41.6 million, or 13.7%, primarily as a result of a 22.6% decrease in the average per unit cost of fuel used for electric generation and a 6.8% decrease in the average per unit cost of purchased power for 2002 compared to 2001, which made the purchase of power more economical than the generation of power. For additional information on Cleco Power's ability to recover fuel and purchased power costs, see "- Significant Factors Affecting Cleco Power - Fuel and purchased power are primarily affected by the following factors."

Revenue for 2002 was decreased by a $2.9 million accrual for electric customer credits compared to a $1.8 million accrual in 2001. For additional information on the accrual for electric customer credits, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 12 - Accrual of Electric Customer Credits."

The increase in power and gas volumes traded from 2001 to 2002 was primarily due to expansion of Cleco Power's power and gas trading portfolio. During the third quarter of 2002, Cleco began an assessment of its speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and it was determined, in light of market conditions and other factors, that Cleco Power would discontinue speculative trading activities. Most exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions entered into specifically to offset those open positions. A summary of power and natural gas traded by Cleco Power for the periods indicated appears below.

Energy trading, net, decreased $2.2 million from 2001 to 2002. The decrease was primarily due to an adjustment for premiums on certain gas put options, volatility in power and natural gas prices, and Cleco's efforts in the fourth quarter of 2002 to mitigate most of the exposure to the market following the decision to discontinue speculative trading activities. For additional information on the premiums on certain gas put options, see "- Financial Condition - Regulatory Matters - Gas Put Options."

Issue 1 of EITF No. 02-3 requires that all gains and losses from energy trading contracts be reported on the income statement on a net basis, with revenue and expenses aggregated and the net number reported in one line item. Cleco adopted EITF No. 02-3 effective July 1, 2002. Prior periods have been restated to reflect the adoption of Issue 1 of EITF No. 02-3.

In October 2002, the EITF rescinded EITF No. 98-10, effective the first fiscal period beginning after December 15, 2002. EITF No. 98-10 required certain energy contracts to be reported at fair market value or "mark-to-market." Instead of using EITF No. 98-10, energy contracts are now evaluated using SFAS No. 133, as amended, in order to determine whether mark-to-market accounting is appropriate.

Intercompany Revenue

Intercompany revenue decreased $4.3 million, or 71.6%, in 2002 compared to 2001. The decrease was primarily due to a change in the billing process to an affiliate and reduced billings to other affiliates for software usage.

Operating expenses decreased $40.7 million, or 7.9%, in 2002 compared to 2001. In 2002 compared to 2001, fuel used for electric generation decreased $45.9 million, or 24.9%, primarily due to the following factors: a decrease in the average per unit cost of fuel from $2.92 per MMBtu in 2001 to $2.31 per MMBtu in 2002; an increase in power purchased for utility customers; and

a $6.6 million one-time adjustment in 2001 for the recovery of fuel-related costs not collected previously from utility customers. From 2001 to 2002, power purchased for utility customers increased $10.6 million, or 7.5%, primarily due to a 6.8% decrease in average per unit cost, which made the purchase of power more economical than the generation of power. The $16.7 million, or 15.5%, decrease in other operations and maintenance expenses for 2002 compared to 2001, was primarily due to a decrease in affiliate billings and to a decrease in administrative expenses as a result of a change in vacation policy between 2001 and 2002. Depreciation expense increased $1.6 million, or 3.2%, in 2002 compared to 2001, primarily due to normal asset additions such as line extensions and substation upgrades and new software. Also, an $8.1 million organizational restructuring charge was incurred in 2002. For additional information regarding the restructuring charge, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Restructuring Charge." Taxes other than income taxes increased $1.5 million, or 4.3%, primarily due to increased payroll and ad valorem taxes.

Interest income decreased $5.6 million, or 85.6%, in 2002 compared to 2001, primarily due to the recognition in 2001 of the one-time recovery of fuel-related costs that had not been previously collected from utility customers and the associated interest. Interest charges increased $2.3 million, or 8.5%, primarily due to interest related to gas transportation charges. For additional information regarding gas transportation charges, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 22 - Gas Transportation Charge."

Midstream's Results of Operations - Year ended December 31, 2002, Compared to Year ended December 31, 2001

Midstream's net income for 2002 was $14.7 million, slightly above the $14.5 million earned in 2001. Contributing factors include:

			For the year ended December 31,
			2002	2001	Variance	Change
			(Thousands)
Operating revenue
	Tolling operations		$ 90,260	$ 60,522	$ 29,738	49.1 %
	Energy trading, net		2,421	5,608	(3,187)	(56.8)%
	Energy operations		30,050	58,659	(28,609)	(48.8)%
	Other operations		4,655	1,135	3,520	310.1 %
	Intercompany revenue		366	13,947	(13,581)	(97.4)%
		Total operating revenue	127,752	139,871	(12,119)	(8.7)%

Operating expenses
	Purchases for energy operations		25,317	48,942	(23,625)	(48.3)%
	Other operations		27,804	33,365	(5,561)	(16.7)%
	Maintenance		8,902	4,828	4,074	84.4 %
	Depreciation		15,989	9,379	6,610	70.5 %
	Restructuring charge		2,058	-	2,058	*
	Impairments of long-lived assets		3,587	-	3,587	*
	Taxes other than income taxes		1,536	1,402	134	9.6 %
		Total operating expenses	85,193	97,916	(12,723)	(13.0)%

Operating income			$ 42,559	$ 41,955	$ 604	1.4 %

Equity income from investees			$ 16,204	$ 175	$ 16,029	*
Other expenses			$ 142	$ 9	$ 133	*
Interest charges			$ 31,750	$ 21,010	$ 10,740	51.1 %
Federal and state income taxes			$ 12,740	$ 8,676	$ 4,064	46.8 %
Net income applicable to member's equity			$ 14,660	$ 14,511	$ 149	1.0 %

* Not meaningful

Tolling Operations

Tolling operations revenue increased $29.7 million, or 49.1%, in 2002 compared to 2001. The increase was primarily due to the Perryville facility commencing full commercial operation on July 1, 2002, and increased generation from the Evangeline facility for 2002 compared to 2001. For additional information on tolling operations, see "- Significant Factors Affecting Midstream - Revenue is primarily affected by the following factors."

Energy Trading, Net

The increase in power and gas volumes traded from 2001 to 2002, was primarily due to expansion of Midstream's power and physical gas trading portfolio, as well as power sales to Acadia. During the third quarter of 2002, Cleco began an assessment of its speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and it was determined, in light of market conditions and other factors, that Midstream would discontinue speculative trading activities. Most exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions entered into specifically to offset those open positions. A summary of

Generally, Midstream's energy trading transactions are considered non-hedging derivatives under SFAS No. 133, as amended, which requires that the transactions be reported at fair market value or "mark-to-market." The chart below presents the components of energy trading, net.

Energy trading, net, decreased $3.2 million, or 56.8%, from 2001 to 2002. The decrease was primarily due to the efforts in the fourth quarter of 2002 to mitigate most of the exposure to the market following the decision to discontinue speculative trading activities and to the volatility in power and natural gas prices in 2002.

Issue 1 of EITF No. 02-3 requires that all gains and losses from energy trading contracts be reported on the income statement on a net basis, with revenues and expenses aggregated, and the net number reported in one line item. Cleco adopted EITF No. 02-3 effective July 1, 2002.

In October 2002, the EITF rescinded EITF No. 98-10, effective the first fiscal period beginning after December 15, 2002. EITF No. 98-10 required certain energy contracts to be reported at fair market value or "mark-to-market." Instead of using EITF No. 98-10, Cleco now evaluates energy contracts using SFAS No. 133, as amended, in order to determine whether mark-to-market accounting is appropriate.

The $28.6 million, or 48.8%, decrease in energy operations revenue during 2002 compared to 2001 was primarily due to a decrease in the average per unit cost of natural gas and decreased volumes of natural gas marketed at Cleco Energy, partially offset by increased energy management services at Marketing & Trading. Energy management services revenue increased $0.8 million for 2002 compared to 2001, primarily due to increased energy management service volumes because of two new contracts. Intercompany volume and revenue have been eliminated and therefore are not reflected in the charts below. The chart below presents the components of energy operations revenue.

The chart below presents a summary of natural gas marketed during 2002 and 2001.

Natural gas sales volume decreased primarily due to the expiration of a contract with a major gas supplier, partially offset by new long-term supply and spot contracts entered into during March 2001, October 2001, and February 2002.

Intercompany revenue decreased $13.6 million, or 97.4%, in 2002 compared to 2001. The decrease was primarily due to a gas transportation charge of $6.4 million and a decline in trading activity between affiliates. For additional information on the gas transportation charge, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 22 - Gas Transportation Charge."

Purchases for energy operations decreased $23.6 million, or 48.3%, from 2001 to 2002, primarily due to lower per unit costs and lower volumes of natural gas marketed. Other operations expenses decreased $5.6 million, or 16.7%, during 2002 compared to 2001, primarily as the result of lower administrative expenses. This decrease was partially offset by increased expenses associated with the Perryville facility's commencement of full commercial operation in 2002. Maintenance expenses increased a net $4.1 million, or 84.4%, across several Midstream companies. Maintenance expenses at Generation Services increased $2.6 million, or 98.7%, from 2001 to 2002. The increase was primarily due to maintenance expenses no longer being capitalized following the completion of construction of Perryville in the summer of 2002, as well as unplanned power outages. At Evangeline, maintenance expenses increased $1.7 million, or 47.9%, in 2002 compared to 2001, primarily due to unplanned plant outages. The $6.6 million, or 70.5%, increase in depreciation expense was primarily due to a $4.9 million increase at Perryville following the completion of construction of Perryville in the summer of 2002 and to a $1.7 million, or 24.1%, increase in depreciation expense at Evangeline primarily due to a reassessment of the useful life of turbine parts. A $2.1 million organizational restructuring charge and a $3.6 million charge for impairment of a long-lived asset were incurred in 2002; there were no such charges in 2001. For additional information on these charges, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Restructuring Charge" and Note 24 - "Impairments of Long-Lived Assets," respectively.

Equity Income from Investees and Income Taxes

Equity income from investees increased $16.0 million for 2002 compared to 2001, primarily due to increased equity earnings from Acadia as a result of Acadia beginning commercial operation in the summer of 2002. For additional information regarding the investment in Acadia, see Item 8, "Financial Statements and

Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees."

Income tax expense increased $4.1 million, or 46.8%, in 2002 compared to 2001. Midstream's effective income tax rate increased from 37.4% to 46.5%, primarily due to an adjustment related to an internal review of accumulated deferred income taxes.

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2003 and the year ended December 31, 2002, see "Results of Operations - Cleco Power's Results of Operations - Year ended December 31, 2003, Compared to Year ended December 31, 2002."

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2002, and the year ended December 31, 2001, see "Results of Operations - Cleco Power's Results of Operations - Year ended December 31, 2002, Compared to Year ended December 31, 2001."

The narrative analyses referenced above should be read in combination with Cleco Power's Financial Statements and the Notes contained in this Form 10-K.

Cleco's critical accounting policies include both those accounting policies that are both important to Cleco's financial condition and results of operations and those that require management to make difficult, subjective, or complex judgments about future events, which could result in a material impact to the financial statements of Cleco Corporation's segments or to Cleco as a consolidated entity. The financial statements contained in this report are prepared in accordance with accounting principles generally accepted in the United States of America, which require Cleco to make estimates and assumptions. Estimates and assumptions about future events and their effects cannot be made with certainty. Management bases its current estimates and assumptions on historical experience and on various other factors that are believed to be reasonable under the circumstances. On an ongoing basis, these estimates and assumptions are evaluated and, if necessary, adjustments are made when warranted by new or updated information or by a change in circumstances or environment. Actual results may differ significantly from these estimates under different assumptions or conditions. For additional information on Cleco's accounting policies see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies."

Cleco believes that the following are the most significant critical accounting policies for the Company:

SFAS No. 71 determines how to account for actions by regulators that control the price an entity can charge its customers. Cleco Power's prices are regulated by the LPSC and the FERC. By determining what costs can be recovered by Cleco Power through the price it charges its customers, regulatory assets and liabilities are recognized. Future changes made by the regulatory bodies could have a material impact on the operations and financial condition of Cleco Power. Below are three areas that could be materially impacted by future actions of regulators.

Generally, Midstream is most affected by market conditions and changes in contract counterparty credit ratings and financial condition. The most important are listed below.

Liquidity and Capital Resources

General Considerations and Credit-Related Risks

Financing for operational needs and construction requirements is dependent upon the cost and availability of external funds from capital markets and financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, Cleco Corporation's credit rating, the credit rating of Cleco Corporation's subsidiaries, the cash flows from routine operations, and the credit ratings of project counterparties. On March 24, 2003, Moody's downgraded the senior unsecured debt ratings of Cleco Corporation to Baa3 from Baa1, the senior secured debt ratings of Cleco Power to A3 from A2, and the senior unsecured debt ratings of Cleco Power to Baa1 from A3. Moody's noted that the ratings outlook for Cleco Corporation is negative and the ratings outlook for Cleco Power is stable. In its press release, Moody's stated that the downgrade reflected deterioration in the credit quality of Cleco's merchant power plants and the adverse underlying market conditions for merchant generation in the Southeastern Electric Reliability Council region. In addition, Moody's stated that the stable outlook for Cleco Power reflected the relative strength of the utility, constructive regulatory relations, reasonable amounts of leverage, and strong cash flows. On March 26, 2003, Standard & Poor's Ratings Services affirmed its senior unsecured debt ratings of Cleco at BBB- and Cleco Power at BBB. Both Cleco Corporation's and Cleco Power's senior unsecured debt ratings were taken off CreditWatch, but Standard & Poor's stated that the outlook for the ratings is negative due to continued uncertainties surrounding Cleco's merchant energy activities. If Cleco Corporation or Cleco Power's credit rating were to be further downgraded by Moody's or downgraded by Standard & Poor's, Cleco Corporation or Cleco Power would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.

The parent companies of Cleco's remaining tolling counterparties are The Williams Companies, Inc. and Calpine. Each of these entities has issued guarantees of the payment obligations of the respective tolling counterparties under the tolling agreements. The credit ratings of these parent companies have been downgraded below investment grade, and in some cases, placed on negative outlook. On June 23, 2003, Moody's revised its outlook for the Evangeline senior secured bonds to positive from negative. Currently, Moody's rates the Evangeline bonds B3. Moody's stated that this action reflected improvement in the credit quality of The Williams Companies, Inc. Cleco notes that these credit ratings are not recommendations to buy, sell, or hold securities. Each rating should be evaluated independently of any other rating. For information on possible consequences resulting from failure of Cleco's counterparties to perform their obligations under the tolling agreements and recent events relating to the tolling agreements, see "- Results of Operations - Midstream - Significant Factors Affecting Midstream - Revenue is primarily affected by the following factors."

Trading agreements entered into by Cleco Energy provide the counterparties with the right to request Cleco Corporation to provide credit support if the counterparty assesses Cleco Energy's creditworthiness as unsatisfactory. Under these agreements, the counterparties can request credit support, but Cleco Corporation could liquidate the transactions and pay liquidating damages to the counterparties as applicable in accordance with the terms and conditions of the contracts. As of December 31, 2003, the amount Cleco Corporation would have been required to pay if all of Cleco Energy's counterparties requested credit support was approximately $3.7 million; however, the risk related to this potential credit support is substantially mitigated as Cleco Energy's transactions are largely contracts to fix future gas prices for municipal customers.

On September 4, 2003, Marketing & Trading closed all forward trading positions, eliminating any credit exposure of Cleco Corporation to Marketing & Trading's power and gas trading counterparties. With respect to any open power or gas trading positions that Cleco may maintain in the future, Cleco Corporation may be required to provide credit support (or pay liquidated damages), and the amount Cleco Corporation may be required to pay at any point in the future is dependent on changes in the market price of power and gas, the changes in the open power and gas positions, and changes in the amount counterparties owe Cleco Corporation. Changes in any of these factors could cause the amount of requested credit support to increase or decrease.

The Mirant Debtors filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 14, 2003. This bankruptcy has significant financial, operational, and business impacts on Cleco, the most significant of which is related to the Perryville Tolling Agreement, the Senior Loan Agreement at Perryville for which KBC acts as agent, and the Subordinated Loan Agreement. The Mirant Debtors have asserted that the Perryville Tolling Agreement was rejected as of September 15, 2003. For information regarding the effects of the Mirant Debtors' bankruptcy, MAEM's rejection of the Perryville Tolling Agreement, and Perryville facility operation subsequent to the rejection of the Perryville Tolling Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville" and "- Debt - Midstream" below.

On January 28, 2004, Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. and entered into a power purchase agreement to sell the output of the Perryville facility to Entergy Services, Inc. To facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The sale of the Perryville facility is subject to regulatory approval, Bankruptcy Court approval, and Entergy Louisiana, Inc.'s ability to recover all of its costs through base rates, fuel adjustment charges or other such rates or regulatory treatment as deemed solely acceptable to Entergy Louisiana, Inc., which is expected to be completed by December 2004. For additional information on the sale agreement, power purchase agreement, and bankruptcy filings, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

Debt

At December 31, 2003 and 2002, Cleco had $200.8 million and $315.3 million, respectively, of short-term debt outstanding in the form of bank loans. If Cleco Corporation were to default under covenants in its various credit facilities, Cleco Corporation would be unable to borrow additional funds under the credit facilities. If Cleco Corporation's credit rating as determined by outside rating agencies, were to be further downgraded, Cleco Corporation would be required to pay additional fees and higher interest. As a result of the downgrades described above in "- General Considerations and Credit-Related Risks - Credit Ratings and Counterparties," Cleco Corporation's interest rate increased by 0.20% and Cleco Power's rate increased by 0.10%. At December 31, 2003, Cleco Corporation was in compliance with the covenants in its credit facilities.

Cleco

At December 31, 2003, Cleco had a working capital deficit of $92.2 million. This deficit occurred primarily as a result of the reclassification of the $133.0 million Senior Loan Agreement to short-term debt. Due to the bankruptcy filings, by Perryville and PEH, on January 28, 2004, the lenders' ability to exercise their remedies under the Senior Loan Agreement, including, but not limited to, their ability to foreclose on the mortgage or assume ownership of the Perryville facility, are significantly limited and would require approval of the Bankruptcy Court.

Short-term debt at Cleco decreased by $114.6 million at December 31, 2003, compared to December 31, 2002. The decrease is attributable to a reduction in short-term debt of $121.6 million and $107.0 million at Cleco Corporation and Cleco Power, respectively. These decreases were offset by an increase of short-term debt of $114.0 million at Midstream. Changes in short-term debt are more fully described below.

Cash and cash equivalents available at December 31, 2003, were $95.4 million combined with $112.5 million facility capacity ($32.5 million from Cleco Corporation and $80.0 million from Cleco Power) for total liquidity of $207.9 million. Cash and cash equivalents decreased $19.0 million, when compared to December 31, 2002, largely due to paydown of short-term bank loans and payment of dividends.

Short-term debt at Cleco Corporation decreased by $121.6 million at December 31, 2003, compared to December 31, 2002, primarily due to the issuance of $100.0 million of long-term notes on April 28, 2003, as discussed below.

In May 2003, Cleco Corporation replaced its then existing $225.0 million credit facility, which was scheduled to terminate in June 2003, with a $105.0 million, 364-day facility, which provides that borrowings outstanding on the maturity date may be converted into a nine-month term loan. This facility provides for working capital and other needs. At December 31, 2003, Cleco Corporation's borrowing cost under this facility was equal to LIBOR plus 1.625%, including facility fees, and the weighted average cost of the borrowings was 2.81%. The prior credit facility provided for an optional conversion to a one-year term loan, and Cleco Corporation's borrowing costs under the facility were equal to LIBOR plus 1.25%. An uncommitted line of credit with a bank in an amount up to $5.0 million also is available to support Cleco Corporation's working capital needs.

If either Cleco Power or Midstream should default under their respective facilities, Cleco Corporation would be considered in default under the current facility. Perryville's default on the Senior Loan Agreement, as described below under "- Midstream" and in Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville," is not considered a default under Cleco Corporation's credit facility. The bonds issued by Evangeline are non-recourse to Cleco Corporation. Off-balance sheet commitments entered into by Cleco with third parties for certain types of transactions between those parties and Cleco's subsidiaries, other than Cleco Power, reduce the amount of credit available to Cleco Corporation under the facility by an amount equal to the stated or determinable amount of the primary obligation. At December 31, 2003, there was $50.0 million drawn on the facility, leaving $55.0 million available. The $55.0 million at December 31, 2003, was further reduced by off-balance sheet commitments of $22.5 million, leaving available capacity of $32.5 million. For more information about these commitments, see "- Cash Generation and Cash Requirements - Off-Balance Sheet Commitments."

Cash and cash equivalents available at December 31, 2003, were $24.2 million combined with $32.5 million facility capacity for total liquidity of $56.7 million. Cash and cash equivalents decreased $20.8 million, when compared to December 31, 2002, largely due to paydown of short-term bank loans and payment of dividends. These expenditures were offset by the issuance of long-term debt and cash from routine operations.

Pursuant to the Construction Management Services Agreement between Perryville and KBC, Perryville paid KBC performance damages of approximately $7.3 million on March 31, 2003, as the sole and exclusive remedy for failure to achieve performance guarantees within the required timeframe. The payment was placed in a restricted liquidated damages account and applied toward the loan balance. Cleco Corporation provides a limited guarantee to pay interest and principal under the Senior Loan Agreement should Perryville be unable to pay its debt service. At December 31, 2003, the amount guaranteed was $7.3 million. Also, under the terms of the Senior Loan Agreement, specified amounts are required to be maintained in restricted cash accounts for debt service payments, major maintenance, and operating needs. At December 31, 2003, there was $6.9 million in these restricted cash accounts. The Senior Loan Agreement is collateralized by Cleco Corporation's membership interest in Perryville. At December 31, 2003, Cleco Corporation had no remaining equity in Perryville. The Senior Loan Agreement is scheduled to mature on October 1, 2007; however, the loan agreement is classified as short-term debt at December 31, 2003, due to defaults under the Senior Loan Agreement. For additional information on the Senior Loan Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville."

For information on the bankruptcy filings by Perryville and PEH and its impact on Cleco Corporation guarantees and restricted cash, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

On April 28, 2003, Cleco Corporation issued $100.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 7.0%. The notes mature on May 1, 2008. The net proceeds from the notes offering were used to repay outstanding borrowings under its revolving credit facility. The notes were issued pursuant to Cleco Corporation's debt shelf registration statement (Registration No. 333-33098). No additional debt securities may be offered and sold under this shelf registration statement.

On October 6, 2003, Cleco Corporation filed a shelf registration statement (Registration No. 333-109506) providing for the issuance of up to $200.0 million of debt securities, common stock, preferred stock, or any combination thereof. This shelf registration statement has not yet been declared effective by the SEC.

Short-term debt at Cleco Power decreased by $107.0 million at December 31, 2003, compared to December 31, 2002, primarily due to the issuance of $75.0 million of long-term senior unsecured notes on April 28, 2003. In May 2003, Cleco Power replaced its then existing $107.0 million credit facility, which was scheduled to terminate in June 2003, with an $80.0 million, 364-day facility, which provides that borrowings outstanding on the maturity date may be converted into a nine-month term loan. This facility provides for working capital and other needs. At December 31, 2003, no amounts were outstanding under this facility, and Cleco Power's borrowing cost under this facility was equal to LIBOR plus 1.25%, including facility fees. The prior credit facility provided for an optional conversion to a one-year term loan, and Cleco Power's borrowing costs under the facility were equal to LIBOR plus 1.00%, including facility fees. An uncommitted line of credit with a bank in an amount up to $5.0 million also is available to support Cleco Power's working capital needs. Cash and cash equivalents available at December 31, 2003, were $71.0 million combined with $80.0 million facility capacity for a total of $151.0 million. Cash and cash equivalents increased $1.8 million, when compared to December 31, 2002, due to routine working capital fluctuations.

On April 28, 2003, Cleco Power issued $75.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 5.375%. The notes mature on May 1, 2013. The net proceeds from the notes offering were used to repay outstanding borrowings under its revolving credit facility. The notes were issued pursuant to Cleco Power's debt shelf registration statement (Registration No. 333-52540). Cleco Power has issued a total of $150.0 million in aggregate principal amount of debt securities pursuant to the shelf registration statement, leaving $50.0 million available for future issuance.

On October 6, 2003, Cleco Power filed a shelf registration statement (Registration No. 333-109507) that provides for the issuance of up to $150.0 million of debt securities. This shelf registration statement has not yet been declared effective by the SEC.

Short-term debt at Midstream increased by $114.0 million at December 31, 2003, compared to December 31, 2002, primarily due to the reclassification of the Senior Loan Agreement to short-term debt. This increase was partially offset by paydown of debt on the Midstream credit facility. Midstream has a $36.8 million credit facility that expires on March 31, 2004. The facility is used to support Midstream's generation activities, and outstanding balances are guaranteed by Cleco Corporation on a subordinated basis. Midstream's cost of borrowings under this facility is equal to LIBOR plus 3.00%, including commitment fees and was 4.1875% at December 31, 2003. At December 31, 2003, the balance due on this credit facility was $17.8 million. APH holds $1.8 million of this outstanding balance as restricted cash pursuant to the terms of the Midstream credit facility. This facility requires that net proceeds from any sale of Midstream's assets must first be applied to any outstanding borrowings under this credit facility.

In August 2002, a portion of the Perryville Senior Loan Agreement was converted to the Subordinated Loan Agreement in the amount of $100.0 million. In October 2002, the remainder of the $151.9 million senior loan was terminated and replaced with a five-year $145.8 million loan with a group of lenders led by KBC acting as agent. The interest rate at December 31, 2003, was 2.64% and was based on LIBOR plus a spread of 1.5%. The Senior Loan Agreement provides for quarterly principal and interest payments. Cleco Corporation provides a guarantee to pay interest and principal under the Senior Loan Agreement should Perryville be unable to pay its debt service. At December 31, 2003, the amount guaranteed was $7.3 million. However, if Cleco Corporation's long-term senior unsecured debt is rated below "BBB-" by Standard & Poor's or "Baa3" by Moody's, Cleco Corporation will be required to post a letter of credit in the amount of $7.4 million. As of December 31, 2003, Cleco Corporation was not required to post a letter of credit, as its credit rating was above the required level. In addition, Cleco Corporation may elect to provide additional credit support under the Senior Loan Agreement under specified circumstances in connection with Perryville's exercise of certain set off rights as described in Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - - Perryville." Also, under the terms of the Senior Loan Agreement, specified amounts are required to be maintained in restricted cash accounts for debt service payments, major maintenance, and operating needs. At December 31, 2003, there was $6.9 million in these restricted cash accounts. The Senior Loan Agreement is collateralized by PEH's membership interest in Perryville. The Subordinated Loan Agreement also is collateralized by PEH's membership interest in Perryville, subordinate to claims under the Senior Loan Agreement. At December 31, 2003, Cleco Corporation had no remaining equity in Perryville. The Senior Loan Agreement is scheduled to mature on October 1, 2007.

The bankruptcy filing by the Mirant Debtors was an event of default under Perryville's Senior Loan Agreement, which gave the lenders holding in aggregate at least 66-2/3% of the outstanding senior loan the right, but not the obligation, to declare any outstanding principal and interest immediately due and payable. As of December 31, 2003, the outstanding principal was $133.0 million. Perryville's Senior Loan Agreement is nonrecourse to Cleco Corporation (other than to the extent of the guarantee discussed above). This default is not an event of default under any other credit facility or financing arrangement of Cleco Corporation or its other subsidiaries. At December 31, 2003, remedies available to the lenders during the existence of an event of default included foreclosure on the Perryville assets, PEH's membership interest in Perryville, which was pledged as collateral against the Senior Loan Agreement and/or cash in the restricted accounts relating to the Senior Loan Agreement. On January 28, 2004, Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana Inc. and also entered into a power purchase agreement with Entergy Services, Inc. To facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The outstanding amounts due under the Senior Loan Agreement were deemed accelerated upon the bankruptcy filings by Perryville and PEH. As a result of the commencement of such bankruptcy cases and by virtue of the automatic stay under the U.S. Bankruptcy Code, the lenders' ability to exercise their remedies under the Senior Loan Agreement, including, but not limited to, their ability to foreclose on the mortgage, call on the outstanding balance under the Senior Loan Agreement or assume ownership of the Perryville facility, are significantly limited and would require approval of the Bankruptcy Court. Subsequent to the filing of bankruptcy by Perryville and PEH, Cleco will no longer consolidate those entities but instead will account for them under the cost method. The cost method will require Cleco Corporation to present the net assets of Perryville and PEH at January 28, 2004, as an investment and not recognize any income or loss from Perryville or PEH in Cleco's results of operations during the reorganization period. For additional information on Perryville's Senior Loan Agreement, the Subordinated Loan Agreement, and effects of the Mirant Debtors' bankruptcy filing, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville." For additional information on the sale agreement, power purchase agreement, and bankruptcy filings by Perryville and PEH, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

As a result of the Mirant Debtors' bankruptcy and MAEM's failure to make pre-petition payments under the Perryville Tolling Agreement, all obligations of Perryville to make principal and interest payments under the Subordinated Loan Agreement, as well as the accrual of additional interest, are indefinitely suspended. At December 31, 2003, the amount outstanding under the Subordinated Loan Agreement was $98.7 million. For additional information on the Subordinated Loan Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - - Perryville."

Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow

accounts and becomes available for general corporate purposes. At December 31, 2003, and 2002, $32.6 million and $29.7 million, respectively, of cash was restricted under the Evangeline senior secured bond indenture, $6.9 million and $22.2 million, respectively, of cash was restricted under an agreement with the lenders for Perryville, and $1.8 million and $1.8 million, respectively, of APH's cash was restricted under the terms of the Midstream line of credit.

Net cash provided by operating activities was $197.5 million during 2003 or a 19.4% increase compared to $165.5 million during 2002. Although 2003 results from operations produced a net loss of $34.9 million, the primary reasons for that loss were due to noncash charges to earnings for normal depreciation of $81.2 million, as well as charges for asset impairments of $156.3 million, Evangeline warranty contract settlement charges of $8.6 million and reserves for uncollectible receivables of $17.4 million. Acadia's cash distribution in excess of book earnings also contributed to the increased operating cash in 2003. Offsetting these positive effects of cash in relation to earnings were a net consumption of cash for general working capital type needs such as receivables, payables, prepayments, interest, fuel and parts inventory, customer deposits and other deferred items. Although Cleco received $25.6 million of cash refunds in 2003 from income tax returns related to 2002, the income tax benefit and receivable related to the operating loss for 2003 offsets the actual cash received in 2003.

Net cash used in investing activities was $53.0 million during 2003 or a 73.6% decrease compared to $200.8 million in 2002. This $147.8 million decline is primarily caused by Midstream's completion of the construction and investment phases of Perryville and Acadia. During 2002, Midstream invested $54.6 million to acquire Mirant's 50% ownership interest of Perryville. In addition, Midstream's investment toward the completion of Acadia was finalized and during 2003 Cleco received a full year of cash returns from its investment in Acadia instead of just a partial year in 2002. Additions to property, plant and equipment were slightly higher in 2002 due primarily to Cleco's investment in new financial software.

Net cash used in financing activities was $163.5 million during 2003 compared to $137.6 million provided in 2002. This $301.1 million decline is primarily caused by the $250.2 million reduction in short-term debt in 2003 as compared to $135.7 million of cash provided by issuance of short-term debt in 2002. The increased cash from short-term debt in 2002 was primarily used to fund project development at Midstream. The reduction of short-term debt in 2003 was partially provided for by issuance of $175.0 million of long-term debt as well as utilizing cash provided by routine operations of both Cleco Power and Midstream. The retirement of long-term obligations and dividends paid on common and preferred stock remained relatively constant from 2001 through 2003. Net cash provided by financing activities in 2002 was also enhanced by the issuance of 2.0 million shares of common stock, the proceeds of which were used to purchase Mirant's 50% ownership interest of Perryville.

Cleco's 2004 expenditures for construction, investment, and debt maturity are estimated to total $291.2 million. For the five-year period ending in 2008, they are expected to total $1.0 billion. Cleco believes that its cash and cash equivalents on hand, together with cash generated from its operations, borrowings from credit facilities, and the net proceeds of any issuances under Cleco's shelf registration statements, will be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.

At December 31, 2003, Cleco Corporation (holding company level) had no remaining securities available for issuance under a $200.0 million shelf registration statement (Registration No. 333-33098) that allowed for the issuance of its debt securities. On April 28, 2003, Cleco Corporation issued $100.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 7.0%. The notes mature on May 1, 2008. The net proceeds from the notes offering were used to repay outstanding borrowings under its revolving credit facility. These notes were issued pursuant to its $200.0 million debt shelf registration statement. In addition, Cleco Corporation had $104.0 million remaining on a $150.0 million shelf registration statement (Registration No. 333-55656) that allows for the issuance of common stock or preferred stock or any combination thereof. On October 6, 2003, Cleco Corporation filed a shelf registration statement (Registration No. 333-109506) that provides for the issuance of up to $200.0 million of debt securities, common stock, preferred stock, or any combination thereof. This shelf registration statement has not yet been declared effective by the SEC.

At December 31, 2003, Cleco Power had $50.0 million remaining on a $200.0 million shelf registration statement (Registration No. 333-52540) that allows for the issuance of its debt securities. On April 28, 2003, Cleco Power issued $75.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 5.375%. The notes mature on May 1, 2013. The net proceeds from the notes offering were used to repay outstanding borrowings under its revolving credit facility. The notes were issued pursuant to its $200.0 million debt shelf registration statement. On October 6, 2003, Cleco Power filed a shelf registration statement (Registration No. 333-109507) that provides for the issuance of up to $150.0 million of debt securities. This shelf registration statement has not yet been declared effective by the SEC.

Cleco divides its construction and investments among its major first-tier subsidiaries - Cleco Power and Midstream. Cleco Power construction consists of assets that may be included in Cleco Power's rate base, the cost of which, if considered prudent by the LPSC, is passed on to its ratepayers. Those assets earn a rate of return authorized by the LPSC and are subject to the rate

agreement described under "- Retail Rates of Cleco Power," below. Such assets consist of improvements to Cleco Power's distribution system, transmission system, and generation stations. Midstream's construction and investment consists of assets whose rate of return is largely determined by the market, not by regulators. Examples of this type of construction include the repowering or construction of generating facilities, additions to gas pipeline transmission systems, and investments in a joint venture engaged in owning power plants.

Cleco Power's construction expenditures totaled $68.5 million in 2003, $87.3 million in 2002, and $45.6 million in 2001. The decrease in construction expenditures from 2002 to 2003 is primarily due to storm restoration costs in 2002. For additional information on storm restoration costs, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 3 - - Regulatory Assets and Liabilities - Deferred Storm Restoration Costs."

Cleco Power's construction expenditures, excluding AFUDC, for 2004 are estimated to be $70.4 million. For the five-year period ending in 2008, they are expected to total $343.1 million. About half of the planned construction in the five-year period will support line extensions and substation upgrades to accommodate new business and load growth. Some investment will be made to rehabilitate older transmission, distribution, and generation assets. Cleco Power also plans to continue to invest in technology to allow it to operate more efficiently. Additionally, this plan assumes that Cleco Power will purchase capacity on a short-term basis to meet its needs. The outcome of the IRP that currently is underway may materially impact Cleco Power's capital requirements and earnings. For additional information on the IRP, see Part I, Item 1, "Business - Operations - Cleco Power - Fuel and Purchased Power - Power Purchases."

In 2003, 2002, and 2001, 100.0% of Cleco Power's construction requirements was funded internally. In 2004, 100.0% of construction requirements is expected to be funded internally. Assuming no investment under the IRP, for the five-year period ending 2008, 100.0% of the construction requirements is expected to be funded internally.

Midstream's construction expenditures totaled $4.8 million in 2003, $3.6 million in 2002, and $3.2 million in 2001. Cash investments in subsidiaries, as discussed below, totaled $94.4 million in 2002, and $133.1 million in 2001. There were no cash investments in subsidiaries in 2003. Total construction and investment in subsidiaries totaled $4.8 million in 2003, $98.0 million in 2002, and $136.3 million in 2001.

Midstream is currently participating in one joint venture, Acadia, which is 50% owned by Midstream and 50% owned by Calpine. Acadia constructed a 1,160-MW, combined-cycle, natural gas-fired power plant near Eunice, Louisiana, that commenced commercial operations in the summer of 2002. Total construction costs of the plant incurred by Acadia were $495.1 million. APH capitalized $19.5 million of costs, which consist of interest and other miscellaneous charges related to the construction of Acadia. As of December 31, 2003, Midstream's equity in Acadia was $264.1 million. Midstream funded its investment in Acadia through an intercompany loan from Cleco Corporation, and Cleco Corporation funded the intercompany loan through its credit facility and the issuance of long-term debt. Midstream does not expect to obtain project-level financing in 2004 for its equity interest in Acadia. For additional information regarding Acadia, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees."

Perryville, currently a wholly owned subsidiary of Midstream, but originally a joint venture with Mirant, constructed a 718-MW, natural gas-fired power plant in Perryville, Louisiana, that commenced full commercial operation in the summer of 2002. At December 31, 2003, total construction costs of the plant incurred by Perryville were $321.1 million, including capitalized interest. Nonrecourse financing was obtained in June 2001 in the form of a construction note. The construction note converted to a five-year term note on October 1, 2002, after construction of the Perryville facility was complete. On June 20, 2002, Midstream purchased Mirant's 50% ownership interest in Perryville. For additional information regarding this purchase and Perryville, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 21 - - Acquisition," and Note 27 - "Perryville."

Midstream's 2004 expenditures for construction and investment in subsidiaries are estimated to total $13.9 million. For the five-year

period ending in 2008, they are expected to total $19.1 million. Most of the planned construction and investment in the five-year period will consist of routine upgrades or other capitalized expenditures on existing generation assets.

In 2003, 100.0% of Midstream's construction and investment in subsidiaries requirements was funded internally, compared to 56.4% in 2002 and 19.2% in 2001. In 2004 and for the five-year period ending 2008, 100.0% of Midstream's construction and investment in subsidiaries requirements are expected to be funded internally.

Other subsidiaries had construction expenditures of $1.2 million during 2003, $5.0 million during 2002, and $3.9 million during 2001. Additions of $6.2 million in 2002 and $3.4 million in 2001 were allocated to Cleco Power and Midstream. These expenditures related to the installation and upgrade of computer hardware and software implementation for Support Group, Cleco's information technology and shared services subsidiary, in order to meet the growing needs of Cleco. Other construction expenditures for 2004 are estimated to total $1.2 million. For the five-year period ending 2008, they are expected to total $2.8 million. The majority of the planned other construction in the five-year period will go toward upgrade of computer hardware and software for Support Group.

Cleco, in the course of normal business activities, enters into a variety of contractual obligations. Some of these result in direct obligations that are reflected in the Consolidated Balance Sheets while others are commitments, some firm and some based on uncertainties, that are not reflected in the consolidated financial statements. The obligations listed below do not include amounts for ongoing needs for which no contractual obligation existed as of December 31, 2003, and represent only amounts that Cleco was contractually obligated to meet as of December 31, 2003.

The following table summarizes the projected future payments for Cleco's contractual obligations existing at December 31, 2003:

			Payments Due by Period
Contractual Obligations		Total		Less than one year	1-3 years	4-5 years	More than 5 years
	(Thousands)
Cleco Corporation
Long-term debt obligations (1)		$ 292,846		$ 65,867	$ 117,646	$ 109,333	$ -
Capital lease obligations (2)		10		2	5	3	-
Operating lease obligations (3)		8,644		2,897	4,080	1,667	-
Purchase obligations (4)		22,637		8,494	7,007	3,242	3,894
Other long-term liabilities (5)		82,141		2,586	5,562	6,192	67,801
Total Cleco Corporation		$ 406,278		$ 79,846	$ 134,300	$ 120,437	$ 71,695
Cleco Power
Long-term debt obligations (1)		630,874		27,247	143,373	83,018	377,236
Capital lease obligations (2)		-		-	-	-	-
Operating lease obligations (3)		16,583		1,169	2,277	2,156	10,981
Purchase obligations (4)		170,462		124,531	17,627	9,590	18,714
Other long-term liabilities (5)		145,769		13,864	28,098	21,456	82,351
Total Cleco Power		$ 963,688		$ 166,811	$ 191,375	$ 116,220	$ 489,282
Midstream
Long-term debt obligations (1)		671,304		55,276	74,407	268,101	273,520
Capital lease obligations (2)		-		-	-	-	-
Operating lease obligations (3)		774		172	519	61	22
Purchase obligations (4)		747,157		80,011	156,382	161,684	349,080
Other long-term liabilities (5)		-		-	-	-	-
Total Midstream		$ 1,419,235		$ 135,459	$ 231,308	$ 429,846	$ 622,622
Other
Long-term debt obligations (1)		-		-	-	-	-
Capital lease obligations (2)		-		-	-	-	-
Operating lease obligations (3)		-		-	-	-	-
Purchase obligations (4)		6,539		3,949	2,590	-	-
Other long-term liabilities (5)		97		56	41	-	-
Total Other		$ 6,636		$ 4,005	$ 2,631	$ -	$ -

Total long-term debt obligations (1)		$ 1,595,024		$ 148,390	$ 335,426	$ 460,452	$ 650,756
Total capital lease obligations (2)		$ 10		$ 2	$ 5	$ 3	$ -
Total operating lease obligations (3)		$ 26,001		$ 4,238	$ 6,876	$ 3,884	$ 11,003
Total purchase obligations (4)		$ 946,795		$ 216,985	$ 183,606	$ 174,516	$ 371,688
Total other long-term liabilities (5)		$ 228,007		$ 16,506	$ 33,701	$ 27,648	$ 150,152
Total		$ 2,795,837		$ 386,121	$ 559,614	$ 666,503	$1,183,599

(1) Long-term debt existing as of December 31, 2003, is debt that has a final maturity of January 1, 2005, or later (current maturities of long-term debt are due within one-year). Cleco's anticipated interest payments related to long-term debt are also included in this category. Scheduled maturities of debt will total $4.9 million for 2004, and $912.7 million for the years thereafter. For additional information regarding Cleco's long-term debt, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt" and - "Debt" above.

(2) Capital leases are maintained in the ordinary course of Cleco's business activities. These leases include office equipment leases.

(3) Operating leases are maintained in the ordinary course of Cleco's business activities. These leases include tolling agreements and vehicle, office space, operating facilities, office equipment, and operating equipment leases and have various terms and expiration dates from 1 to 20 years. For additional information regarding Cleco's operating leases, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 14 - - Operating Leases."

(5) Other long-term liabilities primarily consist of obligations for franchise payments, facilities use, and various operating and maintenance agreements.

Cleco Power and Midstream's merchant power plants are Cleco's primary sources of internally generated funds. These funds, along with the issuance of additional debt and commercial paper in future years, will be used for general corporate purposes, construction, and to repay corporate debt. For the years ended December 31, 2003, and 2002, Cleco had internally generated cash of $197.5 million and $165.5 million, respectively, that was available for the repayment of long-term debt and funding of its construction expenditures.

Cleco has entered into various off-balance sheet commitments, in the form of guarantees and a standby letter of credit, in order to facilitate the activities of its subsidiaries and an equity investee (affiliate). Cleco entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of compensation to the counterparty if its affiliates do not fulfill certain contractual obligations. If Cleco had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco's affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco's Consolidated Balance Sheets, because it has been determined that Cleco's affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco will be required. Some of these commitments reduce the amount of the credit facility available to Cleco Corporation by an amount defined by the credit facility. The following table shows off-balance sheet commitments grouped by the affiliate on whose behalf each commitment was made. The table also shows the face amount of the commitment, applicable reductions, the resulting net amount of the commitment and associated reductions in Cleco Corporation's ability to draw on its credit facility at December 31, 2003. Changes occurring subsequent to December 31, 2003, and a discussion of the off-balance sheet commitments are detailed in the explanations following the table. The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco's financial condition.

If Acadia cannot pay the contractor that built its plant, Cleco Corporation will be required to pay 50% of the current amount outstanding. At December 31, 2003, Cleco Corporation's 50% portion of the contractor's current amount outstanding was approximately $0.2 million. The guarantee on the Acadia construction contracts will cease upon full payment of those contracts. Management expects Acadia to have the ability to pay its contractor as scheduled and does not expect Cleco Corporation to pay on behalf of Acadia. However, under the covenants associated with Cleco Corporation's credit facility, the current monthly amount due the Acadia contractor reduces the amount Cleco Corporation can borrow under its credit facility.

If Perryville is unable to make principal and interest payments to its lenders, Cleco Corporation will be required to pay up to $7.3 million on behalf of Perryville under a guarantee issued in connection with the replacement of Perryville's construction loan in the fourth quarter of 2002. However, if Cleco Corporation's long-term senior unsecured debt is rated below BBB- by Standard & Poor's or Baa3 by Moody's, Cleco Corporation will be required to post a letter of credit in the amount of $7.4 million. For information on Mirant's bankruptcy impact on the Senior Loan Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - - Perryville."

Cleco Corporation has issued guarantees to Marketing & Trading's counterparties in order to facilitate energy trading and to Cleco Energy's counterparties in order to facilitate energy operations. In conjunction with the guarantees issued, Marketing & Trading has received guarantees from certain counterparties and has entered into netting agreements whereby Marketing & Trading is only exposed to the net open position with each trading counterparty. The guarantees issued and received expire at various

times. The balances of net guarantees for Marketing & Trading and Cleco Energy do not affect the amount Cleco Corporation can borrow under its credit facility. The total amount of guaranteed net open positions with all of Marketing & Trading and Cleco Energy's counterparties over $20.0 million reduces the amount Cleco Corporation can borrow under its credit facility. At December 31, 2003, the total guaranteed net open positions for Cleco Energy were $2.1 million and no net open positions were maintained by Marketing & Trading, so the borrowing restriction in Cleco's credit facility was not affected. As counterparties and amounts traded change, corresponding changes will be made in the level of guarantees issued by Cleco Corporation. As of September 4, 2003, all of Marketing & Trading's forward positions were closed; therefore, Cleco Corporation's level of guarantees will decrease as these guarantees are terminated. As of January 31, 2004, $86.3 million of Marketing & Trading's guarantees have been terminated.

If Evangeline fails to perform certain obligations under its tolling agreement, Cleco Corporation will be required to make payments to Evangeline's tolling agreement counterparty under the commitments listed in the above table. Cleco Corporation's obligation under the Evangeline commitment is in the form of a standby letter of credit from investment grade banks and is limited to $15.0 million. Ratings triggers do not exist in the Evangeline Tolling Agreement. Cleco expects Evangeline to be able to meet its obligations under the tolling agreement and does not expect Cleco Corporation to be required to make payments to the counterparty. However, under the covenants associated with Cleco Corporation's credit facility, the entire net amount of the Evangeline commitment reduces the amount that can be borrowed under the credit facility. The letter of credit for Evangeline is expected to be renewed annually until 2020.

As part of a lignite mining agreement entered into in 2001, Cleco Power and SWEPCO, joint owners of Dolet Hills Unit 1, have agreed to pay the lignite miner's loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered. At December 31, 2003, Cleco Power's 50% exposure was approximately $25.9 million. The lignite mining contract is in place until 2011 and does not affect the amount Cleco Corporation can borrow under its credit facility.

The following table summarizes the expected termination date of the guarantees and standby letter of credit:

The capacity and energy contracts between Cleco Power and Williams Energy stipulate that Cleco Power must provide additional security in the event of certain Cleco Power ratings triggers. These Cleco Power triggers include: ratings downgrade below investment grade, negative credit watch for possible downgrade below investment grade, failure to make required payments, and failure to maintain a certain debt-to-equity ratio. The amount of the additional security required to be provided by Cleco Power to Williams Energy in the event of a Cleco Power ratings trigger is $20.0 million under these contracts. The contract between Cleco Power and Dynegy stipulates that Cleco Power may be required to provide additional security in the event of a ratings downgrade below investment grade. The amount of the additional security that Cleco Power could be required to provide to Dynegy is for the full amount of Cleco Power's obligations with respect to the capacity payments for the remainder of the contract. At December 31, 2003, this amount was $6.2 million. This obligation, however, may be affected or revoked by virtue of the fact that Dynegy currently may be in default of its contractual obligation to provide additional security in the event of certain credit ratings downgrades of Dynegy. At December 31, 2003, no additional security obligations existed for the Williams Energy and Dynegy contracts referenced above.

Cleco Corporation previously was obligated under guarantees relating to the Perryville Tolling Agreement and the Acadia Tolling Agreement with Aquila Energy. These obligations terminated when the tolling agreements terminated in September 2003 and May 2003, respectively. For information on an additional guarantee entered into by Cleco Corporation on January 28, 2004, for performance obligations and liquidated damages related to the sale of the Perryville facility, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."

Generation RFP

Cleco Power issued a RFP in May 2003 for up to 750 MW of generation supply to replace existing purchase power agreements that expire in 2004 and 2005. Cleco Power received facility specific asset sale and long-term purchase power proposals, from which a short-list of respondents was established in September 2003. Binding proposals were received on October 15, 2003. During the same time period, Cleco Power modified its existing RFP to request shorter-term options. These proposals also were received October 15, 2003. There were no winning proposals selected from the RFP; however, on January 30, 2004, Cleco Power agreed to terms for a one-year contract to purchase 500 MW of capacity from CES starting in January 2005. Such one-year contracts are not subject to the LPSC's RFP general order requirements, but do remain subject to certification approval by the LPSC. Cleco Power anticipates that this contract will be executed by late March 2004 and expects that the 500 MW from CES will fill the shortfall left by contracts expiring at the end of 2004; however, Cleco Power continues to evaluate meeting capacity requirements through its IRP team and plans to issue a new RFP in mid-2004. During the third quarter of 2003, Cleco Power created an IRP team to evaluate generation supply options. It is anticipated that the IRP effort will identify the leading alternatives that can provide customers with a long-term supply of power at stable, competitive prices. For additional information on the IRP process, see Part I, Item 1, "Business - Operations - Cleco Power - Fuel and

Purchased Power - Power Purchases." In addition, Cleco Power filed a notice of intent to issue a new RFP in February 2004. The RFP informational filing is expected to be made during the second quarter of 2004. Thereafter, Cleco Power will work with the LPSC to determine the final RFP timeline.

Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged approximately 2.2% during the three years ended December 31, 2003. Cleco believes inflation, at this level, does not materially affect its results of operations or financial position. However, under existing regulatory practice, only the historical cost of a plant is recoverable from customers. As a result, Cleco Power's cash flows designed to provide recovery of historical plant costs may not be adequate to replace property, plant and equipment in future years.

For information on environmental matters, see Part I, Item 1, "Business - Regulatory Matters, Industry Developments, and Franchises - Environmental Matters."

Retail rates regulated by the LPSC accounted for approximately 77% of Cleco's consolidated 2003 revenue. Fuel costs are passed through directly to customers via a monthly fuel adjustment clause, which is subject to audit by the LPSC. In the past, Cleco Power has sought increases in base rates to reflect the cost of service related to capital construction additions and increases in operating costs. If a rate increase is requested and adequate rate relief is not granted on a timely basis, the ability to attract capital at reasonable costs to finance operations and capital improvements could be impaired.

The LPSC elected in 1993 to review the earnings of all electric, gas, water, and telecommunications utilities it regulated to determine whether the returns on equity of these companies may be higher than returns that might be awarded in the then-current economic environment. In 1996, the LPSC approved a settlement of Cleco Power's earnings review, which provided customers with lower electricity rates. The terms of this settlement, referred to as the rate stabilization plan, were to be effective for a five-year period. The settlement period was extended until September 30, 2004, under a February 1999 agreement with the LPSC to transfer the existing assets of CPS from Cleco Power's LPSC regulated rate base into Evangeline, which then repowered the generation plant as an exempt wholesale generator subject to regulation by the FERC.

The rate stabilization plan allows Cleco Power to retain all earnings equating to a regulatory return on equity, up to and including 12.25% on its regulated utility operations. Any earnings that result in a return on equity over 12.25% and up to and including 13% will be shared equally between Cleco Power and its customers. Any earnings above this level will be fully refunded to customers. This effectively allows Cleco Power the opportunity to realize a regulatory rate of return up to 12.625%. As part of the rate stabilization plan, the LPSC annually reviews revenue and return on equity. If Cleco Power is found to be achieving a regulatory return on equity above the minimum 12.25%, the refund will be made in the form of billing credits subsequent to an order by the LPSC. The determination of any refund relative to the 2001, 2002 and 2003 earnings monitoring periods is under review by the LPSC Staff. For information concerning amounts accrued by Cleco Power based on the settlement agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 12 - Accrual of Electric Customer Credits."

As referred to above, the rate stabilization plan is due to expire on September 30, 2004. A new plan may be ordered by the LPSC upon expiration of the existing plan or the existing plan may be extended with or without modification. In addition, the LPSC may compel a rate proceeding as part of any scenario. On February 13, 2004, Cleco Power filed to obtain a one-year extension without modification. This extension would allow Cleco time to develop a long-range IRP, solicit new market proposals, and evaluate the best options to create an efficient generation portfolio. Any modification of the existing rate plan or a new rate plan may significantly impact both Cleco and Cleco Power's future results of operations, financial condition, and cash flows.

For information on Cleco Power's IRP team and its evaluation of generation supply options, see Part I, Item 1, "Business - Operations - Cleco Power - Fuel and Purchased Power - - Power Purchases."

Cleco's wholesale rates are regulated by the FERC via cost-based and market-based tariffs at Cleco Power and via market-based tariffs at Evangeline, Acadia, Perryville, and Cleco Energy. These tariffs and the associated codes of conduct accompanying them are updated periodically to comply with FERC directives. Such an update was completed in December 2003 for each entity, except Cleco Energy, to comply with FERC's requirement to amend market-based rates to add "market behavior rules" to the codes of conduct. Contracts utilizing these tariffs do not require prior approval by FERC, but are reported each quarter pursuant to FERC's requirement for reporting of sales by authorized power marketers.

Marketing & Trading's market-based rate approval was revoked by the FERC during the year as part of the Consent Agreement. For information on the Consent Agreement, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement."

For information on franchises, see Part I, Item 1, "Business - Regulatory Matters, Industry Developments, and Franchises - Franchises."

The Energy Policy Act, enacted by Congress in 1992, significantly changed the U.S. energy policy, including regulations governing the electric utility industry. The Energy Policy Act allows the FERC,

on a case-by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. The Energy Policy Act prohibits FERC-ordered retail wheeling, such as opening up electric utility transmission systems to allow customer choice of energy suppliers at the retail level, including "sham" wholesale transactions. Further, under the Energy Policy Act, any FERC transmission order requiring a transmitting utility to provide wholesale transmission services must include provisions that permit the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services, including any enlargement of the transmission system and any associated services.

In addition, the Energy Policy Act revised the 1935 FPA to permit utilities, including registered holding companies and non-utilities, to form "exempt wholesale generators" without the principal restrictions of the 1935 FPA. Under prior law, independent power producers generally were required to adopt inefficient and complex ownership structures to avoid pervasive regulation under the 1935 FPA.

In 1999, the FERC issued Order No. 2000, which established a general framework for all transmission-owning entities in the nation to voluntarily place their transmission facilities under the control of an appropriate RTO. Although participation is voluntary, the FERC has made it clear that any jurisdictional entity not participating in an RTO will be subject to further regulatory directives. These directives could take the form of review and/or denial of market-based rates for independent power sales. In July 2001, the FERC issued orders stating its intention to form four regional RTOs covering the Northeast, Southeast, Midwest, and West. The FERC has since relaxed its mandate for the four RTOs, but still is insisting upon the large regional RTO model. Many transmission-owning entities and system operators have been trying to interpret and implement the FERC directives by attempting to organize acceptable RTOs. In November 2001, Entergy and Southern Company announced a combined effort to form a Southeastern RTO, the SeTrans. At the same time, SPP and Midwest Independent System Operator (MISO) announced their combined effort to design a Midwestern RTO. During 2002, numerous procedural meetings and filings were made by these parties in an effort to advance their RTO formation. However, in December 2003, the MISO merged with the eastern power pool PJM, thus leaving SPP without a viable partner. On February 10, 2004, FERC gave its approval of SPP's solo application for RTO recognition in its Order Granting RTO Status Subject to Fulfillment of Requirements. However, FERC ordered a number of conditions that SPP must meet before it can receive final FERC approval. In November 2003, the sponsors of SeTrans announced their intent to withdraw their support for further development of that RTO. The primary reason cited was the continued lack of progress from a regulatory approval standpoint, as jurisdictional authority between the FERC and the states remains unclear. On February 13, 2004, a large group of SeTrans stakeholders filed a joint response to the SeTrans' Sponsors' decision to suspend development activities. The stakeholders include municipal and cooperative utilities as well as independent power producers and merchant developers. The stakeholder group has asked FERC to conduct several investigations and audits as well as issue a show cause order on revocation of market-based rate authorization. Upon the collapse of SeTrans, Entergy has continued to make filings at the FERC regarding the future operation of its transmission system. Its Available Flowgate Capacity filing would change the way available transmission capacity on Entergy's system is determined. FERC issued an order in this Entergy filing on February 10, 2004 accepting and suspending the tariff to become effective April 1, 2004. Its Weekly Procurement Process filing would potentially change the merit order dispatch of generating units in the region. Both proposals could have a significant impact on the ability to transport power into and out of the Cleco control area. Cleco plans to be an active participant in these and all other proceedings affecting availability and sale of power in and around Louisiana. As with RTO developments at-large, other various parties, including several state commissions, utilities, and other industry participants, are participants in the RTO and Entergy proceedings described above.

In September 2001, the LPSC issued Order No. U-25965, which requires Cleco Power and other transmission-owning entities in Louisiana to demonstrate why they should not be ordered to transfer ownership or control of the bulk transmission assets, paid for by jurisdictional ratepayers, to another entity, such as an RTO. This order also requires that Cleco Power and the other Louisiana transmission-owning entities show cause why the LPSC should not declare that the pricing and cost transfers required by the recommendation of the Administrative Law Judge in FERC Docket No. RTO1-100-000 conflict with the public interest. The order does not limit Cleco Power's ability to participate in RTO development. In August 2002, the LPSC filed a protest to the June 27, 2002, Petition for Declaratory Order concerning the proposed SeTrans RTO. The LPSC asserted that the SeTrans Petition should be denied, and the SeTrans RTO should not receive the preliminary approval requested. The LPSC, absent an adequate study or sufficient evidence demonstrating that the benefits to ratepayers of joining an RTO outweigh the costs, opposes the participation of Cleco Power and other Louisiana transmission-owning entities.

The transfer of control of Cleco Power's transmission facilities to an RTO has the potential to materially affect its financial condition and results of operations. Cleco Power cannot predict the possible impact to financial earnings that may arise from the adoption of new transmission rates resulting from Cleco Power's possible membership in an RTO.

On November 24, 2003, the FERC adopted Order 2004, which updates its Order 889 governing Standards of Conduct for Transmission Providers. Cleco Power and all other transmission providers are required to comply with the order by June 1, 2004. FERC's stated intent is to broaden the definition of an energy affiliate and apply the standards uniformly to natural gas pipelines and public utility transmission providers; to eliminate the loophole in the current regulations that does not cover a transmission provider's relationship with energy affiliates that are not marketers or merchant affiliates; and to ensure that transmission providers cannot extend their market power over transmission to other energy markets by giving their energy affiliates preferential treatment.

Congress continues to study the potential effects of restructuring the nation's vertically integrated utility systems and providing retail customers with a choice of generation supplier. Congress, along with the FERC and the North American Electric Reliability Council, is evaluating power production and delivery as part of the formation of a national energy policy. This, while ongoing since 2001, took on added importance with the summer 2003 blackout in the Midwest and Northeast. It is not possible to predict when or if retail customers nationwide will be able to choose their electric suppliers as a result of federal legislation. Other primary areas subject to potential energy legislation that could affect Cleco include:

Cleco cannot predict what future legislation may be proposed and/or passed and what impact, if any, it may have upon Cleco's results of operations or financial condition.

Cleco Power and a number of parties, including the other Louisiana electric utilities, certain power marketing companies, and various associations representing industry and consumers, have been participating in electric industry restructuring activities before the LPSC since 1997. During 2000, the LPSC Staff developed a transition to competition plan that was presented to the LPSC. In November 2001, the LPSC directed its staff to monitor neighboring jurisdictions and to report back the success or failure of those efforts 12 months after these initiatives begin. Presently, no such monitoring condition exists within the region. Management anticipates that the LPSC Staff will evaluate the east Texas market once retail choice has occurred.

At this time, Cleco cannot predict whether any legislation or regulation affecting Cleco Power will be enacted or adopted and, if enacted, what form such legislation or regulation may take. A potentially competitive environment presents both the opportunity to supply electricity to new customers and the risk of losing existing customers. Cleco Power is striving to be positioned to compete effectively should retail access be adopted at some future time in Louisiana.

In April 2002, the LPSC adopted order R-26172 governing the way in which electric generation sources are to be solicited and tested versus self-build options of a utility. Cleco Power conducted an RFP pursuant to this order during 2003. In January 2004, the LPSC amended its prior order to formally add the requirement that the soliciting utility employ an independent monitor. The independent monitor's role is to assure the RFP process is run fairly, that bidder data is treated confidentially and that no preference is afforded bids from affiliate companies of the utility. For additional information on Cleco Power's RFP, see "- Generation RFP."

Currently, the LPSC does not provide exclusive service territories for electric utilities under its jurisdiction. Instead, retail service is obtained through a long-term nonexclusive franchise. The LPSC uses a "300-foot rule" for determining the supplier for new customers. The application of this rule has led to competition with neighboring utilities for retail customers at the borders of Cleco Power's service areas. Cleco Power also competes in its service area with suppliers of alternative forms of energy, some of which may be less costly than electricity for certain applications. Cleco Power could experience some competition for electric sales to industrial customers in the form of cogeneration or from independent power producers.

During 2002, certain fourth-quarter 2001 natural gas purchase transactions were identified that were accounted for inconsistently with Cleco Power's fuel adjustment clause. Cleco Power sold a limited number of natural gas put options. The cost of the natural gas purchased by Cleco Power pursuant to those options was charged to Cleco Power's fuel cost and was ultimately recovered from Cleco Power's customers through its fuel adjustment clause. However, the premium received by Cleco Power for the sale of those options was not credited to fuel cost, which thereby overstated the net cost of the natural gas for fuel clause purposes, causing fuel revenues and pre-tax income to be overstated by a similar amount. The total amount of the option premiums was approximately $2.1 million. Upon identification of this matter in 2002, Cleco Power credited the cumulative amount of the option premiums previously received to its fuel cost for fuel adjustment clause purposes resulting in a 2002 reduction of fuel revenue by the amount of the option premiums and thereby returning this amount to Cleco Power's customers. Although management believes the original accounting for these transactions may have violated the LPSC's regulations governing Cleco Power's fuel adjustment clause, management does not believe any action the LPSC may take pertaining to the gas put options would have a material effect on Cleco Power's results of operations or financial condition. For information on Cleco Power's pending LPSC fuel audit, see "- Fuel Audit."

During a review of trading activities in the second half of 2002, Cleco identified simultaneous buy and sell trades with the same counterparty for the same volumes at the same price, referred to

as "round-trip trades," for both Cleco Power and Marketing & Trading. The majority of Cleco Power's round-trip trades involved service to a retail industrial customer. Cleco Power would sell power to a third party, which then immediately would sell the same volume of power at the same price as the purchase price back to Cleco Power, which in turn would sell the power to its industrial customer or to others. A few of the trades classified as round-trip trades in 1999 included a small price difference between the buy and the sell. Cleco Power contacted the FERC and the LPSC and discussed these and other transactions with both agencies. These discussions led to formal investigatory proceedings with dockets being opened by the FERC and the LPSC, with which Cleco cooperated. These proceedings have entailed discovery measures by the agencies with jurisdiction over the referenced energy trading transactions and energy trading transactions in general between Cleco's power marketer subsidiaries. On July 25, 2003, the FERC issued its order approving a Consent Agreement between Cleco and the FERC Staff which settled the FERC's investigation into certain transactions. Management is unable to predict the remedial actions that may be taken with respect to these transactions by the LPSC and cannot reasonably estimate Cleco's minimum probable contingency for these transactions. For information about the FERC settlement concerning these transactions, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - - FERC Settlement."

Marketing & Trading participated in round-trip trades whereby Marketing & Trading would buy power from a third party, and sell the same volume at the same price as the purchase price back to the third party. Additionally, Marketing & Trading had round-trip trades whereby Marketing & Trading would sell power to a third party, which then would sell the same volume at the same price as the purchase price back to Marketing & Trading. Marketing & Trading contacted the FERC regarding its round-trip trades and other transactions. These discussions led to the same investigatory proceeding with the FERC as referenced above, which has been settled as discussed above and in Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - FERC Settlement." Cleco received requests for information from the Commodity Futures Trading Commission (CFTC) related to Cleco Power and Marketing & Trading's round-trip trades and the reporting of trading activities to trade publications. Cleco provided the requested information to the CFTC. From 1999 through mid-January, 2002, the same personnel performed the trading operations of Cleco Power and Marketing & Trading. Management believes these trading activities may be reviewed in Cleco Power's pending LPSC fuel audit. For additional information regarding the review of trading activities, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 19 - Review of Trading Activities." For additional information on the fuel audit, see "- Fuel Audit." For information about the FERC settlement concerning this issue, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 25 - - FERC Settlement."

Cleco has implemented Issue 1 of EITF No. 02-3 as of July 15, 2002, which requires all gains and losses (both realized and unrealized) from energy trading contracts to be reported retroactively on the income statement on a net basis, by aggregating revenue and expenses and reporting the number in one line item. Therefore, the effect on Cleco's revenue and expenses related to the round-trip trades has been eliminated through the implementation of Issue 1 of EITF No. 02-3.

In the second half of 2002, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit. The audit, which commenced in March 2003, includes Fuel Adjustment Clause filings for January 2001 through December 2002, although a portion of the data requested for the audit relates to periods prior to 2001. A Cleco Power customer has intervened and is involved in the LPSC fuel audit proceeding. The audit, pursuant to the Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497, is required to be performed not less than every other year; however, this is the first LPSC Fuel Adjustment Clause audit of Cleco Power. LPSC-jurisdictional revenue recovered by Cleco Power through its Fuel Adjustment Clause for the audit period of January 2001 through December 2002 was $567.1 million. Management is unable to predict the results of the LPSC fuel audit, which could require Cleco Power to refund previously recovered revenue and could adversely impact the Registrants' results of operations and financial condition. The LPSC Staff expects to issue its preliminary findings and recommendations related to the fuel audit proceeding by March 31, 2004.

During a review of an affiliate gas transportation contract, Cleco determined that the gas transportation charge billed by a wholesale subsidiary of Cleco Energy to Cleco Power may have exceeded the wholesale subsidiary's cost of providing such services to Cleco Power, plus a reasonable rate of return. These transactions have potentially exceeded the pricing standards of the LPSC for affiliate transactions. Midstream recorded a charge of $6.4 million for these subsidiary transactions. Additionally, Cleco Power accrued interest expense of $1.4 million for a potential refund to its customers and had discussions with the staff of the LPSC regarding this issue. Cleco Energy reimbursed Cleco Power approximately $6.4 million for these gas transportation charges. Cleco Power anticipates that these transactions will be reviewed in Cleco Power's pending LPSC fuel audit. For information on the fuel audit, see "- Fuel Audit."

In May 2001, Cleco Power signed a lignite contract with the miner at the Dolet Hills mine. As ordered by the LPSC in dockets U-21453, U-20925(SC), and U-22092(SC) (Subdocket G), retail ratepayers are receiving fuel cost savings equal to 2% of the projected costs under the previous mining contract through 2011. Costs above 98% of the previous contract's projected costs are deferred. Deferred costs will be recovered from retail customers through the fuel adjustment clause when the actual costs of the new contract are below 98% of the projected costs of the previous contract. Cleco Power recorded recovery of $0.5 million in the fourth quarter of 2003, as the miner's cost fell below the 98%

threshold. As of December 31, 2003, Cleco Power had remaining deferred costs and interest relating to the mining contract of $9.7 million. The expectation of recovery is based upon assumptions of the future benchmark price of lignite, interest rates, inflation rates and quality and quantity of lignite mined and burned. A material change in the assumptions in subsequent years could cause management to determine that a portion, or all, of the deferred lignite costs are not recoverable and could result in an impairment charge. An impairment charge also could be recorded if the miner's cumulative actual costs do not fall below the 98% threshold. Cleco Power will continue to monitor and assess the recoverability of these amounts on a periodic basis; however, management expects the miner's cumulative costs to continue to fall below the 98% threshold, and therefore, expects Cleco Power to recover the remaining amounts deferred.

Cleco Power supplies a portion of its customers' electric power requirements from generation facilities owned by Cleco Power. Purchases of additional electric power are made from the wholesale power market in the form of generation capacity and/or purchased power to satisfy these needs. Portions of these purchases are made at a fixed price, and the remainder is made approximately at prevailing market prices. Cleco Power obtains approximately 32% of its annual capacity from contracts with Williams Energy and Dynegy. Management expects to meet substantially all of its native load demand through 2004 with Cleco Power's own generation capacity, and the contracts with Williams Energy and Dynegy and other economy purchases. Because substantially all of its long-term capacity and energy contracts with Williams Energy and Dynegy expire on December 31, 2004, Cleco Power currently is evaluating its long-term capacity and energy needs. On January 30, 2004, Cleco Power agreed to terms for a one-year contract to purchase 500 MW of capacity from CES starting in January 2005. Cleco Power anticipates this contract will be executed by late March 2004 and expects that the 500 MW from CES will fill the shortfall left by contracts expiring at the end of 2004; however, Cleco Power continues to evaluate meeting capacity requirements through its IRP team and its plans to issue a new RFP in mid-2004. For additional information on Cleco Power's identification of existing or additional generation resources, see "- Results of Operations - Significant Factors Affecting Cleco Power - Fuel and purchased power are primarily affected by the following factors" and "- Generation RFP." Because of its location on the transmission grid, Cleco Power relies on one main supplier for electric transmission and is sometimes constrained as to the amount of purchased power it can deliver into its system. The power contracts described above may be affected by such transmission constraints.

If either Williams Energy or Dynegy fails to provide power to Cleco Power in accordance with the power purchase agreements, Cleco Power would have to obtain replacement power at then prevailing market prices to meet its customers' demands. The power market can be volatile, and the prices at which Cleco Power would obtain replacement power could be higher than the prices Cleco Power currently pays under the power purchase agreements. The LPSC may not allow Cleco Power to recover, through an increase in its rates or through fuel adjustment costs, part or all of any additional amounts Cleco Power may pay in order to obtain replacement power. If this occurred, Cleco Power's financial condition and results of operations could be materially adversely affected.

On July 23, 2003, the FERC issued a final ruling regarding standard procedures and a standard agreement for the interconnection of generators larger than 20 MW. The FERC also proposed rules regarding expedited procedures for small generators under 20 MW. The original date of October 20, 2003, for compliance with the large generator standards was extended to January 20, 2004. On January 8, 2004, the FERC issued a notice to clarify the process for complying with the January 20, 2004, effective date. The FERC has not yet set a date for compliance with the small generator standards.

Cleco Power filed and received approval during 2003 to establish charges for unauthorized use of point-to-point transmission services, ancillary services, and transmission losses. Customers using Cleco Power's transmission system are required to reserve capacity in order to deliver power within and across the regional power grid. With the onset of higher power transactional volumes, unauthorized use had increased. FERC approved Cleco Power's application effective December 1, 2003, subject to revisions to the billing determinants proposed in the original filing.

For discussion of new accounting standards, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Recent Accounting Standards."

Market risk inherent in Cleco's market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity price of power and natural gas traded in the industry on different energy exchanges. Prior to the third quarter of 2002, Cleco Power and Marketing & Trading used EITF No. 98-10 to determine whether the market risk-sensitive instruments and positions were required to be marked-to-market. In October 2002, the EITF rescinded EITF No. 98-10, effective the second fiscal period beginning after December 15, 2002. Cleco Power currently uses SFAS No. 133 to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market. Generally, Cleco Power's market risk-sensitive instruments and positions qualify for the normal-purchase, normal-

sale exception to mark-to-market accounting of SFAS No. 133, as modified by SFAS No. 149, since Cleco Power generally takes physical delivery and the instruments and positions are used to satisfy customer requirements. Cleco Power could have positions that are required to be marked-to-market, because they do not meet the exception of SFAS No. 133, and do not qualify for hedge accounting treatment. The positions for marketing and trading purposes do not meet the exemptions of SFAS No. 133 and the net mark-to-market of those positions is recorded in income. Cleco Power has entered into other positions to mitigate some of the volatility in fuel costs passed on to customers. These positions are marked-to-market, with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability. When these positions close, actual gains or losses will be included in the Fuel Adjustment Clause and reflected on customers' bills. Cleco Energy's financial positions are marked-to-market.

Cleco also is subject to market risk associated with its remaining tolling agreement counterparties. For additional information concerning Cleco's market risk associated with its remaining counterparties, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - General Considerations and Credit Related Risks" and Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville."

Cleco's exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of power and natural gas. Management's views on market risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains or losses. The views do represent, within the parameters disclosed, what management estimates may happen.

Cleco has entered into various fixed- and variable-rate debt obligations. The calculations of the changes in fair market value and interest expense of the debt securities are made over a one-year period.

Sensitivity to changes in interest rates for fixed-rate obligations is computed by calculating the current fair market value using a net present value model based upon a 1% change in the average interest rate applicable to such debt. Sensitivity to changes in interest rates for variable-rate obligations is computed by assuming a 1% change in the current interest rate applicable to such debt.

As of December 31, 2003, the carrying value of Cleco's short-term variable-rate debt was approximately $200.8 million, which approximates the fair market value. Each 1.0% change in the average interest rates applicable to such debt would result in a change of approximately $2.0 million in Cleco's pretax earnings. At December 31, 2003, Cleco Power had no short-term, variable-rate debt.

Cleco monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt.

During the fourth quarter of 2002, Marketing & Trading and Cleco Power discontinued speculative trading activities. As of September 4, 2003, all of Marketing & Trading's remaining positions were closed; therefore no mark-to-market amount was recorded on the balance sheet. The change in the mark-to-market amount between December 31, 2002, and December 31, 2003, was a gain of $0.4 million and was recorded in the income statement. Due to the change in trading strategy, commodity price risks have been substantially mitigated when compared to previous periods.

Management believes Cleco has controls in place to minimize the remaining risks involved in trading. Controls over trading consist of a back office (accounting) and middle office (risk management) independent of the trading operations, oversight by a risk management committee comprised of officers, and a daily risk report that shows VAR and current market conditions. Cleco's Board of Directors appoints the members of the Risk Management Committee. VAR limits are set and monitored by the Risk Management Committee.

Cleco Power's financial positions that are not used to meet the power demands of customers are marked-to-market as required by SFAS No. 133. Based on market prices at December 31, 2003, the net mark-to-market amount for those positions also was zero; therefore, no balance remained on the balance sheet. The change in the mark-to-market amount between December 31, 2002, and December 31, 2003, was a gain of $0.5 million and was recorded in the income statement.

Cleco Power provides fuel for generation and purchases power to meet the power demands of customers. Cleco Power has entered into positions to mitigate some of the volatility in fuel costs passed on to customers, as encouraged by an LPSC order. These positions are marked-to-market, with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability and a component of the risk management asset or liability. Based on market prices at December 31, 2003, the net mark-to-market impact was a gain of $1.0 million.

Cleco Energy provides natural gas to wholesale customers, such as municipalities, and enters into transactions in order to provide fixed gas prices to some of its customers. All of Cleco Energy's trades are marked-to-market as required by SFAS No. 133. Due to market price volatility, mark-to-market reporting may introduce volatility to carrying values and hence to Cleco Energy's financial statements. At December 31, 2003, the net mark-to-market impact had a minimal effect on the financial statements.

Cleco Power and Cleco Energy utilize a VAR model to assess the market risk of their trading portfolios, including derivative financial instruments. VAR represents the potential loss in fair values for an instrument from adverse changes in market factors for a specified period of time and confidence level. The VAR is

estimated using a historical simulation calculated daily assuming a holding period of one day, with a 95% confidence level for natural gas and power positions. Total volatility is based on historical cash volatility, implied market volatility, current cash volatility, and option pricing.

Based on these assumptions, the high, low, and average VAR for 2003, as well as the VAR at December 31, 2003 and 2002, is summarized below:

The following table summarizes the market value maturities of contracts at December 31, 2003.

Contractual Obligations		Maturity less than one year		Maturity 1-3 years		Maturity over three years		Total Fair Value
	(Thousands)
Assets
Cleco Power	$	22,803	$	-	$	-	$	22,803
Cleco Energy		14,148		-		-		14,148
Consolidated	$	36,951	$	-	$	-	$	36,951
Liabilities
Cleco Power	$	39,896	$	-	$	-	$	39,896
Cleco Energy		14,148		-		-		14,148
Consolidated	$	54,044	$	-	$	-	$	54,044

For additional information on the market value maturities of contracts, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 5 - Fair Value of Financial Instruments."

Prior to the third quarter of 2002, Cleco Power used EITF No. 98-10 to determine whether the market risk-sensitive instruments and positions were required to be marked-to-market. In October 2002, the EITF rescinded EITF No. 98-10, effective the first fiscal period beginning after December 15, 2002. Cleco Power currently uses SFAS No. 133 to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market. Generally, Cleco Power's market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting of SFAS No. 133, since Cleco Power generally takes physical delivery and the instruments and positions are used to satisfy customer requirements. Cleco Power could have positions that are required to be marked-to-market because they do not meet the exceptions of SFAS No. 133 and do not qualify for hedge accounting treatment. The positions entered into for marketing and trading purposes do not meet the exemptions of SFAS No. 133, and the net mark-to-market of those positions is recorded in income. Cleco Power has entered into other positions to mitigate some of the volatility in fuel costs passed on to customers. These positions are marked-to-market, with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability. When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers' bills.

Cleco Power's exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of power and natural gas. Management's views on market risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains or losses. The views do represent, within the parameters disclosed, what management estimates may happen.

Cleco Power has entered into various fixed- and variable-rate debt obligations. For details, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt." The calculations of the changes in fair market value and interest expense of the debt securities are made over a one-year period.

As of December 31, 2003, the carrying value of Cleco Power's long-term fixed-rate debt was approximately $410.6 million, with a fair market value of approximately $450.4 million. Fair value was determined using quoted market prices. Each 1.0% change in the average interest rates applicable to such debt would result in a change of approximately $4.5 million in the fair values of these instruments. If these instruments are held to maturity, no change in stated value will be realized.

As of December 31, 2003, Cleco Power had no short-term variable-rate debt. Cleco Power monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt.

Cleco Power's management believes it has controls in place to help minimize the risks involved in trading. Controls over trading consist of a back office (accounting) and a middle office (risk management) independent of the trading operations, oversight by a risk management committee comprised of officers, and a daily risk report which shows VAR and current market conditions. Cleco's Board of Directors appoints the members of the Risk Management Committee. VAR limits are set and monitored by the Risk Management Committee.

During the third quarter of 2002, Cleco Power began an assessment of its speculative trading strategies. This assessment was completed during the fourth quarter of 2002, and Cleco Power determined, in light of market conditions and other factors, that it would discontinue speculative trading activities.

The change in the mark-to-market amount between December 31, 2002, and December 31, 2003, was a gain of $0.5 million and was recorded in the income statement.

Cleco Power utilizes a VAR model to assess the market risk of its trading portfolios, including derivative financial instruments. VAR represents the potential loss in fair values for an instrument from adverse changes in market factors for a specified period of time and confidence level. The VAR is estimated using a historical simulation calculated daily assuming a holding period of one day, with a 95% confidence level for natural gas and power positions. Total volatility is based on historical cash volatility, implied market volatility, and current cash volatility.

Based on these assumptions, the high, low, and average VAR for Cleco Power for 2003, as well as the VAR at December 31, 2003, and 2002, is summarized below:

As a result of Cleco Power's decision to no longer engage in speculative trading activities, there was no change in VAR at December 31, 2003, compared to December 31, 2002.

The following table summarizes the market value maturities of contracts at December 31, 2003, with respect to Cleco Power:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements of Cleco Corporation, effective January 1, 2001, the Company adopted provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

					For the year ended December 31,
				2003		2002		2001
					(Thousands, except share and per share amounts)
Operating revenue
	Electric operations			$	676,002	$	568,102	$	592,253
	Tolling operations				98,726		90,260		60,522
	Energy trading, net				(855)		1,675		7,049
	Energy operations				71,639		30,051		58,659
	Other operations				30,687		34,036		32,076
		Gross operating revenue			876,199		724,124		750,559
			Electric customer credits		(1,562)		(2,900)		(1,800)
		Total operating revenue			874,637		721,224		748,759
Operating expenses
	Fuel used for electric generation				163,769		143,733		182,384
	Power purchased for utility customers				231,839		151,086		140,550
	Purchases for energy operations				66,869		25,317		48,314
	Other operations				97,979		87,292		100,113
	Maintenance				60,493		35,080		29,459
	Depreciation				77,550		69,157		60,433
	Restructuring charge				(757)		10,164		-
	Impairments of long-lived assets				156,250		3,587		-
	Taxes other than income taxes				39,285		38,812		37,966
		Total operating expenses			893,277		564,228		599,219
Operating (loss) income					(18,640)		156,996		149,540
Interest income					2,380		1,576		7,764
Allowance for other funds used during construction					2,741		2,719		769
Equity income from investees					31,631		16,204		175
Other income					3,652		2,181		20,930
Other expense					(9,224)		(4,949)		(20,856)
Income before interest charges					12,540		174,727		158,322
Interest charges
	Interest charges, including amortization of debt expenses,
		premium and discount, net of capitalized interest			72,256		61,212		48,871
	Allowance for borrowed funds used during construction				(813)		(603)		(1,178)
		Total interest charges			71,443		60,609		47,693
(Loss) income from continuing operations before
	income taxes and preferred dividends				(58,903)		114,118		110,629
Federal and state income tax (benefit) expense					(23,974)		42,243		38,356
(Loss) income from continuing operations					(34,929)		71,875		72,273
Discontinued operations
	Loss on disposal of segment, net of income taxes				-		-		(2,035)
(Loss) income before preferred dividends					(34,929)		71,875		70,238
Preferred dividends requirements, net					1,861		1,872		1,876
Net (loss) income applicable to common stock				$	(36,790)	$	70,003	$	68,362


Average shares of common stock outstanding
	Basic				46,820,058		46,245,104		45,000,955
	Diluted				46,820,058		48,771,864		47,763,713
Basic (loss) earnings per share
	From continuing operations			$	(0.79)	$	1.51	$	1.56
	From discontinued operations			$	-	$	-	$	(0.04)
	Net (loss) income applicable to common stock			$	(0.79)	$	1.51	$	1.52
Diluted (loss) earnings per share
	From continuing operations			$	(0.79)	$	1.47	$	1.51
	From discontinued operations			$	-	$	-	$	(0.04)
	Net (loss) income applicable to common stock			$	(0.79)	$	1.47	$	1.47
Cash dividends paid per share of common stock				$	0.900	$	0.895	$	0.870

The accompanying notes are an integral part of the consolidated financial statements.

				At December 31,
				2003	2002
				(Thousands)
Assets
	Current assets
		Cash and cash equivalents		$ 95,381	$ 114,331
		Restricted cash, current portion		6,668	7,762
		Customer accounts receivable (less allowance for doubtful
			accounts of $17,154 in 2003 and $1,071 in 2002)	28,657	32,599
		Other accounts receivable		28,233	45,264
		Taxes receivable		22,127	23,607
		Unbilled revenues		23,658	20,171
		Fuel inventory, at average cost		15,719	13,309
		Material and supplies inventory, at average cost		17,348	14,416
		Risk management assets		1,322	285
		Accumulated deferred federal and state income taxes, net		1,544	3,829
		Other current assets		12,742	9,258
			Total current assets	253,399	284,831
	Property, plant and equipment
		Property, plant and equipment		2,119,515	2,200,103
		Accumulated depreciation		(779,154)	(714,178)
		Net property, plant and equipment		1,340,361	1,485,925
		Construction work-in-progress		76,705	80,230
			Total property, plant and equipment, net	1,417,066	1,566,155

	Equity investment in investees			264,073	273,688
	Prepayments			12,732	32,865
	Restricted cash, less current portion			34,594	45,907
	Regulatory assets and liabilities - deferred taxes, net			93,142	65,268
	Long-term receivable			14,701	10,370
	Other deferred charges			69,719	65,472
Total assets				$ 2,159,426	$ 2,344,556

The accompanying notes are an integral part of the consolidated financial statements.

(Continued on next page)

					At December 31,
					2003	2002
					(Thousands)
Liabilities and shareholders' equity
	Liabilities
		Current liabilities
			Short-term debt		$ 200,787	$ 315,300
			Long-term debt due within one year		4,918	45,401
			Accounts payable		82,314	104,046
			Retainage		7,625	6,278
			Accrued payroll		2,141	2,180
			Customer deposits		21,382	21,087
			Interest accrued		15,667	15,546
			Accumulated deferred fuel		6,579	3,509
			Risk management liabilities		357	2,310
			Other current liabilities		3,785	3,032
				Total current liabilities	345,555	518,689
		Deferred credits
			Accumulated deferred federal and state income taxes, net		324,687	299,019
			Accumulated deferred investment tax credits		19,015	20,744
			Other deferred credits		61,643	57,442
				Total deferred credits	405,345	377,205
		Long-term debt			907,058	868,684
			Total liabilities		1,657,958	1,764,578

Commitments and Contingencies (Note 16)

Shareholders' equity
	Preferred stock
		Not subject to mandatory redemption			25,324	26,578
		Deferred compensation related to preferred stock held by ESOP			(6,607)	(9,070)
			Total preferred stock not subject to mandatory redemption		18,717	17,508
	Common shareholders' equity
		Common stock, $1 par value, authorized 100,000,000 shares,
			issued 47,299,119 and 47,065,152 shares at December 31, 2003
			and 2002, respectively		47,299	47,065
		Premium on common stock			154,928	152,745
		Retained earnings			286,797	366,073
		Treasury stock, at cost, 115,484 and 29,959 shares
			at December 31, 2003 and 2002, respectively		(2,493)	(579)
		Accumulated other comprehensive loss			(3,780)	(2,834)
			Total common shareholders' equity		482,751	562,470
				Total shareholders' equity	501,468	579,978
Total liabilities and shareholders' equity					$ 2,159,426	$ 2,344,556

The accompanying notes are an integral part of the consolidated financial statements.

					For the year ended December 31,
					2003	2002	2001
Operating activities					(Thousands)
	(Loss) income before preferred dividends				$ (34,929)	$ 71,875	$ 70,238
	Adjustments to reconcile net (loss) income to net cash provided by operating activities:
			Loss on disposal of segment, net of tax		-	-	(2,555)
			Depreciation and amortization		81,204	71,144	61,775
			Evangeline warranty and settlement		8,649	-
			Provision for doubtful accounts		17,407	688	2,018
			Income from equity investments		(31,631)	(16,204)	(175)
			Return on equity investments		34,525	-	-
			Allowance for other funds used during construction		(2,741)	(2,719)	(769)
			Impairments of long-lived assets		156,250	3,587	-
			Amortization of investment tax credits		(1,729)	(1,743)	(1,765)
			Net deferred income taxes		(6,264)	79,060	(6,898)
			Deferred fuel costs		3,070	11,488	(4,362)
			Changes in assets and liabilities:
				Accounts receivable	10,166	(5,119)	19,524
				Unbilled revenues	(3,650)	(2,308)	16,937
				Fuel, materials and supplies inventory	(5,342)	372	(4,953)
				Prepayments	(2,043)	(14,667)	(326)
				Accounts payable	(21,732)	3,931	(21,026)
				Customer deposits	295	395	214
				Long-term receivable	(4,331)	(4,465)	(5,009)
				Other deferred accounts	5,389	334	2,038
				Taxes accrued	1,480	(35,204)	(8,639)
				Interest accrued	121	(150)	(517)
				Risk management assets and liabilities, net	(2,990)	2,991	(3,866)
				Other, net	(3,626)	2,229	12,716
		Net cash provided by operating activities			197,548	165,515	124,600
Investing activities
	Additions to property, plant and equipment				(74,511)	(89,704)	(49,371)
	Allowance for other funds used during construction				2,741	2,719	769
	Proceeds from sale of property, plant and equipment				316	-	1,845
	Proceeds from disposal of segment				-	-	4,590
	Return of equity investment in investee				6,043	-	-
	Equity investment in investees				-	(39,860)	(133,084)
	Acquisition of partnership, net of cash acquired				-	(54,561)	-
	Cash transferred from (to) restricted accounts, net				12,406	(19,359)	25,667
		Net cash used in investing activities			(53,005)	(200,765)	(149,584)
Financing activities
	Sale of common stock				-	44,300	-
	Conversion of options to common stock				120	-	-
	Issuance of common stock under employee stock purchase plan				(44)	-	-
	Change in short-term debt, net				(250,211)	135,745	83,598
	Retirement of long-term obligations				(41,470)	(63,204)	(32,035)
	Issuance of long-term debt				175,000	67,739	-
	Deferred financing costs				(2,474)	(3,776)	-
	Dividends paid on common and preferred stock, net				(44,347)	(43,056)	(41,031)
	Repurchase of common stock				(67)	(105)	(3,017)
		Net cash (used in) provided by financing activities			(163,493)	137,643	7,515
Net (decrease) increase in cash and cash equivalents					(18,950)	102,393	(17,469)
Cash and cash equivalents at beginning of period					114,331	11,938	29,407
Cash and cash equivalents at end of period					$ 95,381	$ 114,331	$ 11,938
Supplementary cash flow information
	Interest paid (net of amount capitalized)				$ 68,004	$ 62,671	$ 50,037
	Income taxes (received) paid				$ (25,567)	$ 3,000	$ 41,261
Supplementary noncash investing activity
	Transfer of assets to joint venture, net				$ -	$ -	$ 5,156
Supplementary noncash financing activity
	Issuance of treasury stock				$ -	$ 1,584	$ 2,125
	Issuance of treasury stock - LTICP and ESOP plan				$ 2,734	$ -	$ -

The accompanying notes are an integral part of the consolidated financial statements.

		For the year ended December 31,
		2003	2002	2001
		(Thousands)

(Loss) income applicable to common stock		$ (36,790)	$ 70,003	$ 68,362
Other comprehensive (loss) income, net of tax:
	Transition adjustment from implementation of SFAS No. 133	-	-	(4,453)
	Net unrealized gain from derivative instruments	-	-	4,453
	Net unrealized gain (loss) from limited partnership	109	(413)	-
	(net of income tax expense of $68 in 2003)
	Net unrealized gain from available-for-sale securities	47	55	-
	(net of income tax expense of $29 in 2003)
	Recognition of additional minimum pension liability	(1,102)	(2,476)	-
	(net of income tax benefit of $689 in 2003 and $1,548 in 2002)
Comprehensive (loss) income, net of tax		$ (37,736)	$ 67,169	$ 68,362

The accompanying notes are an integral part of the consolidated financial statements.

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDERS' EQUITY

				Long-Term
				Debt Payable				Accumulated
			Premium	in Company				Other	Total
	Common Stock		on Common	Common	Retained	Treasury Stock		Comprehensive	Common
	Shares	Amount	Stock	Stock	Earnings	Shares	Cost	Loss	Equity
	(Thousands, except share and per share amounts)
BALANCE, JANUARY 1, 2001	45,065,152	$ 45,065	$112,477	$ 519	$ 308,047	(73,072)	$(1,188)	$ -	$ 464,920
Treasury shares purchased						(148,432)	(3,017)		(3,017)
Issuance of treasury stock			(750)			87,304	1,606		856
Directors' restricted stock			(13)				13		-
Dividend requirements, preferred stock, net					(1,876)				(1,876)
Payment in common stock				(519)		31,958	519		-
Cash dividends paid, common stock,
$0.870 per share					(39,155)				(39,155)
Net income from continuing operations					72,273				72,273
Loss from discontinued operations					(2,035)				(2,035)
BALANCE, DECEMBER 31, 2001	45,065,152	45,065	111,714	-	337,254	(102,242)	(2,067)	-	491,966
Issuance of common stock	2,000,000	2,000	42,300						44,300
Treasury shares purchased						(5,784)	(105)		(105)
Issuance of treasury stock			(1,260)			78,067	1,584		324
Directors' restricted stock			(9)				9		-
Dividend requirements, preferred stock, net					(1,872)				(1,872)
Cash dividends paid, common stock,
$0.895 per share					(41,184)				(41,184)
Net income from continuing operations					71,875				71,875
Other comprehensive income, net of tax								(2,834)	(2,834)
BALANCE, DECEMBER 31, 2002	47,065,152	47,065	152,745	-	366,073	(29,959)	(579)	(2,834)	562,470
Common stock issued for compensatory plans	233,967	234	2,247						2,481
Incentive shares forfeited						(91,022)	(2,022)		(2,022)
Issuance of treasury stock			(58)			5,497	102		44
Directors' restricted stock			(6)				6		-
Dividend requirements, preferred stock, net					(1,861)				(1,861)
Cash dividends paid, common stock,
$0.900 per share					(42,486)				(42,486)
Net loss from continuing operations					(34,929)				(34,929)
Other comprehensive income, net of tax								(946)	(946)
BALANCE, DECEMBER 31, 2003	47,299,119	$ 47,299	$154,928	$ -	$286,797	(115,484)	$(2,493)	$ (3,780)	$482,751
The accompanying notes are an integral part of the consolidated financial statements.

In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Power LLC at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements of Cleco Power LLC, effective January 1, 2001, the Company adopted provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

				For the year ended December 31,
				2003	2002	2001
				(Thousands)
Operating revenue
	Electric operations			$ 676,002	$ 568,102	$ 592,253
	Energy trading, net			626	(752)	1,456
	Other operations			30,013	29,331	30,813
	Intercompany revenue			2,209	1,708	6,011
		Gross operating revenue		708,850	598,389	630,533
			Electric customer credits	(1,562)	(2,900)	(1,800)
		Total operating revenue		707,288	595,489	628,733

Operating expenses
	Fuel used for electric generation			163,869	138,582	184,479
	Power purchased for utility customers			230,691	151,090	140,524
	Other operations			62,742	62,794	81,868
	Maintenance			44,542	28,170	25,773
	Depreciation			54,084	52,233	50,594
	Restructuring charge			(315)	8,099	-
	Taxes other than income taxes			37,062	36,892	35,358
		Total operating expenses		592,675	477,860	518,596

Operating income				114,613	117,629	110,137

Interest income				1,335	933	6,498
Allowance for other funds used during construction				2,741	2,719	769
Other income				4,714	3,678	20,306
Other expenses				(7,775)	(4,122)	(20,463)

Income before interest charges				115,628	120,837	117,247

Interest charges
	Interest charges, including amortization of debt expenses,
		premium and discount		29,587	29,694	27,997
	Allowance for borrowed funds used during construction			(813)	(603)	(1,178)
		Total interest charges		28,774	29,091	26,819

Net income before income taxes				86,854	91,746	90,428

Federal and state income taxes				29,846	32,172	31,290

Net income applicable to member's equity				$ 57,008	$ 59,574	$ 59,138


The accompanying notes are an integral part of the financial statements.

				At December 31,
				2003	2002
				(Thousands)
Assets
	Utility plant and equipment
		Property, plant and equipment		$ 1,692,815	$ 1,617,254
		Accumulated depreciation		(732,334)	(680,305)
		Net property, plant and equipment		960,481	936,949
		Construction work-in-progress		68,224	76,131
			Total utility plant, net	1,028,705	1,013,080

	Current assets
		Cash and cash equivalents		70,990	69,167
		Customer accounts receivable (less allowance for
			doubtful accounts of $755 in 2003 and $846 in 2002)	25,513	25,467
		Other accounts receivable		18,733	23,553
		Affiliates receivable		17,052	9,296
		Taxes receivable		-	18,123
		Unbilled revenues		17,208	15,996
		Fuel inventory, at average cost		15,719	13,309
		Material and supplies inventory, at average cost		13,477	12,333
		Risk management assets		966	67
		Accumulated deferred federal and state income taxes, net		2,353	3,652
		Other current assets		4,738	4,234
			Total current assets	186,749	195,197

	Prepayments			9,033	8,733
	Regulatory assets and liabilities - deferred taxes, net			93,142	65,268
	Other deferred charges			61,287	56,167

Total assets				$ 1,378,916	$ 1,338,445

The accompanying notes are an integral part of the financial statements.

(Continued on next page)

			At December 31,
			2003	2002
			(Thousands)
Liabilities and member's equity
	Member's equity		$ 445,866	$ 423,816
	Long-term debt		410,576	335,517

		Total capitalization	856,442	759,333

Current liabilities
	Short-term debt		-	107,000
	Long-term debt due within one year		-	25,000
	Accounts payable		69,456	63,108
	Accounts payable - affiliates		24,694	9,126
	Customer deposits		21,364	21,069
	Taxes accrued		11,216	-
	Interest accrued		7,619	7,725
	Accumulated deferred fuel		6,579	3,509
	Risk management liabilities		-	1,935
	Other current liabilities		2,768	2,779
		Total current liabilities	143,696	241,251

Deferred credits
	Accumulated deferred federal and state income taxes, net		313,871	274,205
	Accumulated deferred investment tax credits		19,015	20,744
	Other deferred credits		45,892	42,912
		Total deferred credits	378,778	337,861

Total liabilities and member's equity			$ 1,378,916	$ 1,338,445

The accompanying notes are an integral part of the financial statements.

					For the year ended December 31,
					2003	2002	2001
					(Thousands)
Operating activities
	Net income applicable to member's equity				$ 57,008	$ 59,574	$ 59,138
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		55,849	53,409	51,473
			Allowance for other funds used during construction		(2,741)	(2,719)	(769)
			Amortization of investment tax credits		(1,729)	(1,743)	(1,765)
			Provision for doubtful accounts		1,614	688	2,018
			Deferred income taxes		13,419	56,926	(11,993)
			Deferred fuel costs		3,070	11,538	(4,362)
			Changes in assets and liabilities:
				Accounts receivable	3,160	(7,677)	17,478
				Accounts and notes receivable, affiliates	(7,756)	(4,443)	1,074
				Unbilled revenues	(1,212)	(1,194)	12,061
				Fuel, materials and supplies inventory	(3,554)	526	(4,381)
				Prepayments	(300)	(433)	(326)
				Accounts payable	6,348	5,886	(13,428)
				Accounts payable, affiliates	15,533	(915)	(5,271)
				Customer deposits	295	370	221
				Other deferred accounts	(3,411)	(3,296)	(2,855)
				Taxes accrued	29,339	(33,935)	(1,237)
				Interest accrued	(106)	(344)	(451)
				Risk management assets and liabilities, net	(2,834)	1,971	-
				Other, net	(2,768)	216	3,681
		Net cash provided by operating activities			159,224	134,405	100,306

Investing activities
	Additions to property, plant and equipment				(68,507)	(87,321)	(45,642)
	Allowance for other funds used during construction				2,741	2,719	769
	Proceeds from sale of property, plant and equipment				316	-	736
		Net cash used in investing activities			(65,450)	(84,602)	(44,137)

Financing activities
	Change in short-term debt, net				(107,000)	43,258	22,345
	Retirement of long-term obligations				(25,000)	(50,000)	(24,823)
	Issuance of long-term debt				75,000	75,059	-
	Deferred financing costs				(551)	(3,776)	-
	Distribution to parent				(44,400)	(51,300)	(52,792)
	Contribution from parent				10,000	3,000	-
		Net cash (used in) provided by financing activities			(91,951)	16,241	(55,270)

Net increase in cash and cash equivalents					1,823	66,044	899
Cash and cash equivalents at beginning of period					69,167	3,123	2,224
Cash and cash equivalents at end of period					$ 70,990	$ 69,167	$ 3,123

Supplementary cash flow information
	Interest paid (net of amount capitalized)				$ 27,322	$ 28,503	$ 29,830
	Income taxes (received) paid				$ (10,198)	$ 2,906	$ 41,501

The accompanying notes are an integral part of the financial statements.

CLECO POWER
STATEMENTS OF CHANGES IN
COMMON SHAREHOLDERS' EQUITY AND MEMBER'S EQUITY

						Other		Total
		Retained		Member's		Comprehensive		Member's
		Earnings		Equity		Loss		Equity
	(Thousands)
BALANCE, JANUARY 1, 2001	$	234,734	$	172,376	$	-	$	407,110
Change to Limited Liability Company		(241,080)		241,080		-		-
Distribution to member		(52,792)		-		-		(52,792)
Net income		59,138		-		-		59,138
BALANCE, DECEMBER 31, 2001		-		413,456		-		413,456
Recognition of additional minimum pension liability, net of tax		-		-		(914)		(914)
Contribution from parent		-		3,000		-		3,000
Distribution to member		-		(51,300)		-		(51,300)
Net income		-		59,574		-		59,574
BALANCE, DECEMBER 31, 2002		-		424,730		(914)		423,816
Recognition of additional minimum pension liability, net of tax		-		-		(558)		(558)
Contribution from parent		-		10,000		-		10,000
Distribution to member		-		(44,400)		-		(44,400)
Net income		-		57,008		-		57,008
BALANCE, DECEMBER 31, 2003	$	-	$	447,338	$	(1,472)	$	445,866

The accompanying notes are an integral part of the financial statements.

Cleco Corporation is a holding company that is exempt from regulation, subject to certain limited exceptions, as a public utility holding company under PUHCA. Cleco Corporation has three continuing business segments and one discontinued business segment. The continuing business segments are:

The discontinued segment is UTS, formerly known as UtiliTech, a utility line construction business. In December 2000, Cleco Corporation decided to sell substantially all of the UTS assets. Revenue and expenses associated with UTS are netted and shown on Cleco's Consolidated Statements of Operations as a loss from discontinued operations. For additional information on selling substantially all of the UTS assets, see Note 17 - "Discontinued Operations."

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

The accompanying consolidated financial statements of Cleco include the accounts of Cleco and its majority-owned subsidiaries after elimination of intercompany accounts and transactions.

Certain reclassifications have been done to make the 2002 and 2001 financial statements conform to the presentation used in the 2003 financial statements. These reclassifications had no effect on Cleco Corporation's net income applicable to common stock or total common shareholders' equity or Cleco Power's net income or total member's equity.

Cleco Power maintains its accounts in accordance with the Uniform System of Accounts prescribed for electric utilities by the FERC, as adopted by the LPSC. Cleco Power's retail rates are regulated by the LPSC, and its rates for transmission services and wholesale power sales are regulated by the FERC. Cleco Power follows SFAS No. 71, which allows utilities to capitalize or defer certain costs based on regulatory approval and management's ongoing assessment that it is probable these items will be recovered through the ratemaking process.

Pursuant to SFAS No. 71, Cleco Power has recorded regulatory assets and liabilities, primarily for the effects of income taxes. In addition, Cleco Power has recorded regulatory assets for deferred mining, storm restoration, interest costs and estimated future asset removal costs, and a regulatory liability has been recorded for fuel and energy purchases as a result of rate actions of regulators. For information regarding the regulatory assets and liabilities recorded by Cleco Power, see Note 3 - "Regulatory Assets and Liabilities."

Any future plan adopted by the LPSC transitioning utilities from LPSC regulation to retail competition may affect the regulatory assets and liabilities recorded by Cleco Power, if the criteria for the application of SFAS No. 71 cannot continue to be met. At this time, Cleco cannot predict whether any legislation or regulation affecting Cleco Power will be enacted or adopted and, if enacted, what form such legislation or regulation may take.

Property, plant and equipment consist primarily of regulated utility generation and energy transmission assets, along with merchant generation stations and natural gas pipelines. Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction. Merchant assets are stated at the lower of fair market value or cost of construction (including interest) or acquisition. Jointly owned assets are reflected in property, plant and equipment at Cleco's share of the cost to construct or purchase the assets. For information on jointly owned assets, see Note 4 - "Jointly Owned Generation Units."

Cleco's cost of improvements to property, plant and equipment is capitalized. Costs associated with repairs and major

maintenance projects are expensed as incurred. Cleco capitalizes the cost to purchase or develop software for internal use.

Upon retirement or disposition, the cost of Cleco Power's depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation and are recovered via a return on the cost of plant included in the rate base. For Cleco's other depreciable assets, upon disposition or retirement, the difference between the net book value of the property and any proceeds received for the property is recorded as a gain or loss on asset disposition on Cleco's statement of operations. Any cost incurred to remove the asset is charged to expense. Annual depreciation provisions expressed as a percentage of average depreciable property for Cleco Power were 3.23% for 2003, 3.28% for 2002, and 3.27% for 2001.

Depreciation on property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets, as follows:

The table below discloses the amounts of plant acquisition adjustments reported in Cleco Power's property, plant and equipment and the associated accumulated amortization reported in accumulated depreciation. The plant acquisition adjustment primarily relates to the 1997 acquisition of Teche. The acquisition adjustment represents the amount paid by Cleco Power for the assets of Teche in excess of their carrying value.

Fuel inventories consist of coal, lignite, and oil used to generate electricity.

Materials and supplies inventory consist of transmission and distribution line construction and repair material, and generating station and transmission and distribution substation repair materials.

Both fuel and materials and supplies inventories are stated at cost determined by pricing fuel and materials and supplies inventory used at the average cost of existing inventory.

Cleco applies the provisions of SFAS No. 144 to account for asset impairments. Under this standard, Cleco evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible operational impairment. Cleco uses an estimate of the future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether operating assets are recoverable. An impairment is recognized when future undiscounted cash flows of assets are estimated to be insufficient to recover the related carrying value. Cleco considers continued operating losses or significant and long-term changes in business conditions to be primary indicators of potential impairment. In measuring impairment, Cleco looks to quoted market prices, if available, or the best information available in the circumstances, including the estimated discounted cash flows associated with the related assets. During 2002, Cleco recorded an impairment charge on certain oil and gas proved reserves at Cleco Energy. During 2003, Cleco recorded impairment charges on generation assets owned by Perryville, pipeline assets owned by Cleco Energy, and oil and gas proved reserves at Cleco Energy. For additional information on the asset impairment charges, see Note 24 - "Impairments of Long-Lived Assets."

Cleco considers highly liquid, marketable securities, and other similar instruments with original maturity dates of three months or less at the time of purchase to be cash equivalents.

Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for general corporate purposes. At December 31, 2003 and 2002, $32.6 million and $29.7 million, respectively, of cash was restricted under the Evangeline senior secured bond indenture, $6.9 million and $22.2 million, respectively, of cash was restricted under an agreement with the lenders for Perryville, and $1.8 million and $1.8 million, respectively, of APH's cash was restricted under the terms of the Midstream line of credit. For additional information on Perryville's use of restricted cash, see Note 30 - "Subsequent Events - Perryville."

Cleco reports its investment in unconsolidated affiliated companies on the equity method of accounting, as defined in APB Opinion No. 18. The amounts reported on Cleco's balance sheet represent the value of assets contributed by Cleco plus Cleco's share of the net income of the affiliate, less any distributions of earnings (dividends) received from the affiliate. For more information, see Note 13 - "Equity Investment in Investees."

Cleco accounts for income taxes under SFAS No. 109. Under this method, income tax expense and related balance sheet amounts are comprised of a "current" portion and a "deferred" portion. The current portion represents Cleco's estimate of the income

taxes payable or receivable for the current year. The deferred portion represents Cleco's estimate of the future income tax effects of events that have been recognized in the financial statements or income tax returns in the current or prior years. Cleco makes assumptions and estimates when it records income taxes such as its ability to deduct items on its tax returns, the timing of the deduction and the effect of regulation by the LPSC on income taxes. Cleco's income tax expense and related assets and liabilities could be affected by its assumptions and estimates, changes in such assumptions and estimates, and by ultimate resolution of assumptions and estimates with taxing authorities.

Cleco Corporation and its subsidiaries, other than Cleco Power, record current and deferred federal and state income taxes at a composite rate of 38.5%. Cleco Power records current and deferred federal income taxes at the statutory rate of 35.0% and records current state income tax expense at 3.0%. Cleco Power records temporary differences between book and tax income under the flow-through method of accounting for state purposes as required by LPSC guidelines. Cleco files a federal consolidated income tax return for all wholly owned subsidiaries.

Investment tax credits, which were deferred for financial statement purposes, are amortized to income over the estimated service lives of the properties that gave rise to the credits.

Expenses, premiums, and discounts applicable to debt securities are amortized to income ratably over the lives of the related issues. Expenses and call premiums related to refinanced Cleco Power debt are deferred and amortized over the remaining life of the original issue.

Utility Revenue Revenue from sales of electricity is recognized based upon the amount of energy delivered. The cost of fuel and purchased power used for retail customers currently is recovered from customers through the fuel adjustment clause, based upon fuel costs incurred in prior months. These adjustments are subject to audit and final determination by regulators. Excise taxes and pass-through fees collected on the sale of electricity are not recorded in utility revenue.

Unbilled Revenue Cleco Power accrues estimated revenue monthly for energy delivered since the latest billings. Cleco Energy accrues estimated revenue monthly for gas sales to customers. The monthly estimated unbilled revenue amounts are recorded as revenue and a receivable and are reversed the following month.

Energy Trading, Net, and Other Revenue Revenue is recognized at the time products or services are provided to and accepted by customers. A component of energy trading, net revenue is the change in mark-to-market for Cleco. For additional information on mark-to-market accounting, see "- Risk Management" below.

Tolling Revenue Tolling revenue is the amount received by Midstream from its counterparties for the operation of its merchant generating stations. Cleco considers the Evangeline Tolling Agreement and considered the Perryville Tolling Agreement to be operating leases as defined by SFAS No. 13 and SFAS No. 29 because of the tolling counterparties' ability to control the use of the plants, among other criteria, through or beyond 2020. The Evangeline Tolling Agreement contains a monthly shaping factor that provides for a greater portion of annual revenue to be received by Cleco during the summer months, which is designed to coincide with the physical usage of the plant. SFAS No. 13 generally requires lessors to recognize revenue using a straight-line approach unless another rational allocation of the revenue is more representative of the pattern in which the leased property is employed. Cleco believes that the recognition of revenue pursuant to the monthly shaping factor for several provisions contained within the Evangeline Tolling Agreement is a rational allocation method, which better reflects the expected usage of the plant. Other provisions are recognized as revenue using a straight-line approach. Certain provisions of the tolling agreements, such as bonuses and penalties, are considered contingent as defined by SFAS No. 29. Contingent rents are recorded as revenue or a reduction in revenue in the period in which the contingency is met. The Perryville Tolling Agreement did not contain a monthly shaping factor for revenue, but instead had a monthly adjustment for penalties, which caused a greater risk of losing revenue if capacity was not available during the summer peak months. The Perryville Tolling Agreement was rejected by MAEM, effective September 15, 2003 and as a result, Midstream no longer receives tolling revenue from MAEM. For additional information on the rejection of the Perryville Tolling Agreement, see Note 27 - "Perryville."

Taxes/Excise Taxes Cleco Power collects a sales and use tax on the sale of electricity that subsequently is remitted to the state in accordance with state law. These amounts are not recorded as income or expense on the income statement, but are reflected at gross amounts on Cleco's balance sheet as a receivable until the tax is collected and as a payable until the liability is paid due to the pass-through nature of this item. Additionally, Cleco collects a consumer fee for one of its franchise agreements. This fee is not recorded on Cleco's income statement as revenue and expense, but is reflected at gross amounts on Cleco's balance sheet as a receivable until it is collected and as a payable until the liability is paid. Cleco currently does not have any excise taxes reflected on its income statement.

The capitalization of AFUDC by Cleco Power is a utility accounting practice prescribed by the FERC and the LPSC. AFUDC represents the estimated cost of financing construction and is not a current source of cash. Under regulatory practices, a return on and recovery of AFUDC is permitted in setting rates charged for utility services. The composite AFUDC rate, including borrowed and other funds, was 12.71% on a pretax basis (7.82% net of tax) for 2003, 13.45% on a pretax basis (8.27% net of tax) for 2002, and 13.65% on a pretax basis (8.40% net of tax) for 2001.

Cleco and its subsidiaries, except Cleco Power (see AFUDC above), capitalize interest costs related to longer-term construction projects. Other than AFUDC at Cleco Power, no interest was capitalized in 2003. However, Cleco capitalized $6.0 million of interest in 2002 and $10.3 million of interest in 2001. For more information, see Note 13 - "Equity Investment in Investees."

Market risk inherent in Cleco's market risk-sensitive instruments and positions includes the potential change arising from changes in interest rates and the commodity prices of power and natural gas traded on different energy exchanges. Cleco's Trading Risk Management Policy authorizes the use of various derivative instruments, including exchange traded options and futures contracts, forward purchase and sales contracts, and swap transactions, to reduce exposure to fluctuations in the price of power and natural gas. Cleco adopted SFAS No. 133 in the first quarter of 2001 and, prior to the third quarter of 2002, Cleco used the guidelines in this standard as well as EITF No. 98-10, to determine whether market risk-sensitive instruments and positions were required to be marked-to-market. EITF No. 98-10 was rescinded, and Cleco Power currently uses SFAS No. 133 to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market. Generally, Cleco Power's market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting of SFAS No. 133, as modified by SFAS No. 149, since Cleco Power generally takes physical delivery and the instruments and positions are used to satisfy customer requirements. Cleco Power could have positions that are required to be marked-to-market because they do not meet the exceptions of SFAS No. 133 and do not qualify for hedge accounting treatment. The positions entered into for marketing and trading purposes do not meet the exemptions of SFAS No. 133 and the net mark-to-market of those positions is recorded in income. Cleco Power has entered into other positions to mitigate some of the volatility in fuel costs passed on to customers. These positions are marked-to-market, with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability. When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers' bills. Cleco Energy's financial positions are marked-to-market. Cleco Power and Cleco Energy have in place with various counterparties agreements that authorize the netting of financial buys and sells and contract payments to mitigate credit risk.

Unless otherwise noted, Cleco and Cleco Power will adopt the new accounting standards on their respective effective dates.

In January 2003, Cleco adopted SFAS No. 143 which requires the recognition of a liability for obligations surrounding future asset retirements. The new standard requires recognition of the liability in the period in which the event which triggers the liability occurs. The adoption has an immaterial impact on Cleco Power's financial position and results of operations. For additional information, see Note 28 - "Accounting for Asset Retirement Obligation."

In December 2003, FASB released FIN 46R, which expands the requirements of consolidation by including "Variable Interest Entities," which depend on the financial support of a parent in order to maintain viability. Detailed tests prescribed in FIN 46R can be used to determine the dependence of a Variable Interest Entity on a parent company. The effective date of FIN 46R depends upon certain characteristics of the parent company and subsidiaries. For entities Cleco forms or invests in after December 31, 2003, FIN 46R is required to be applied at the time of formation or investing. For transactions prior to December 31, 2003, FIN 46R is required to be applied as of March 31, 2004, unless the entity is a special purpose entity. If the entity is a special purpose entity, then certain tests must be performed in order to determine consolidation at December 31, 2003. Cleco did not have any interest in special purpose entities and was not required to consolidate any previously unconsolidated entities at December 31, 2003. Due to the currently changing interpretations and clarifications of FIN 46R, Cleco cannot determine the impact of adopting this new standard in 2004.

In April 2003, FASB issued SFAS No. 149, which amends SFAS No. 133 by incorporating certain decisions made by the FASB as a part of the Derivatives Implementation Group process. This pronouncement also amends several FASB statements as they relate to FASB Statement of Concepts 7 - Using Cash Flow Information and Present Value in Accounting Measurement. All portions of this statement are currently effective. The adoption of this standard did not have a material effect on Cleco's financial statements. The FASB Staff has several proposed positions that clarify the FASB position relating to specific issues. The current proposed positions will not have a material impact on Cleco or Cleco Power's results of operations or financial condition.

In April 2003, FASB issued SFAS No. 150, which established standards on how an entity classifies and measures certain financial instruments that have characteristics of both liabilities and equity. Generally, a financial instrument that requires the entity to either repurchase the instrument in cash or other assets or requires the entity to issue a variable number of shares in order to redeem the financial instrument must be reported as a liability and any dividends must be reported as interest costs. Obligations to repurchase or settle the financial instrument upon the liquidation or termination of the entity are not within the scope of SFAS No. 150. On October 29, 2003, the FASB Staff deferred portions of SFAS No. 150. The adoption of this standard did not have a material impact on Cleco or Cleco Power's results of operations or financial condition.

In December 2003, FASB issued a revision to SFAS No. 132 that requires additional disclosure of pension assets and assumptions. In January 2004, FASB also issued FSP SFAS No. 106-1, which requires certain disclosures about a new federal law as it relates to other postretirement benefits. Both SFAS No. 132 and FSP SFAS No. 106-1 disclosure requirements have been adopted and incorporated into Note 9 - "Pension Plan and Employee Benefits."

		For the year ended December 31, (Thousands, except per share amounts)
		2003				2002				2001
	Income (Numerator)		Shares (Denominator)	Per Share Amount	Income (Numerator)		Shares (Denominator)	Per Share Amount	Income (Numerator)		Shares (Denominator)	Per Share Amount
Net (loss) income from continuing operations	$ (34,929)				$ 71,875				$ 72,273
Less: preferred dividends requirement, net	1,861				1,872				1,876

Basic (loss) earnings per share
(Loss) income from continuing operations available for common shareholders	$ (36,790)		46,820	$ (0.79)	$ 70,003		46,245	$ 1.51	$ 70,397		45,001	$ 1.56

Effect of Dilutive Securities
Stock option grants			-				47				213
Convertible ESOP preferred stock	-		-		1,803		2,480		1,814		2,550

Diluted (loss) earnings per share
(Loss) income from continuing operations available to common shareholders plus assumed conversions	$ (36,790)		46,820	$ (0.79)	$ 71,806		48,772	$ 1.47	$ 72,211		47,764	$ 1.51

Earnings (loss) per average common share are computed using the weighted average number of shares of common stock outstanding during the year. All shares and per share data have been restated to reflect the two-for-one split of Cleco's common stock that became effective for shareholders of record at the close of business on May 7, 2001. The table above is a reconciliation of the components in the calculation of basic and diluted (loss) earnings per share.

No options to purchase shares of common stock were included in the computation of diluted loss per share for the fiscal year ended December 31, 2003, because the effects would have been anti-dilutive.

Options to purchase 889,136 shares of common stock at prices ranging from $20.375 to $24.25 were outstanding at the end of fiscal year 2002 but not included in the computation of diluted earnings per share for the fiscal year ended December 31, 2002, because the options' exercise prices were greater than the average market price of the common shares. The options expire between 2009 and 2012.

Options to purchase 10,334 shares of common stock at prices ranging from $22.69 to $23.25 were outstanding at the end of fiscal year 2001 but not included in the computation of diluted earnings per share for the fiscal year ended December 31, 2001, because the options' exercise prices were greater than the average market price of the common shares. The options expire in 2011.

Cleco accounts for stock options granted to employees under the provisions of APB Opinion No. 25. Cleco has not recognized compensation expense for stock options granted, because the fair market value of common stock was equal to the exercise price of the option on the date of the grant. Disclosure of pro forma compensation expense, net income applicable to common stock and earnings per share is presented below.

At December 31, 2003, Cleco Corporation had two stock-based compensation plans: the LTICP and the ESPP. APB Opinion No. 25 and related interpretations are applied in accounting for Cleco Corporation's plans. Accordingly, no compensation cost has been recognized for stock options issued pursuant to the LTICP and stock issued under the ESPP. In 2003, 91,022 shares were forfeited, which resulted in a $1.6 million reduction in compensation cost related to restricted stock. In 2002 and 2001, the compensation cost that has been recognized for restricted stock issued pursuant to Cleco Corporation's LTICP, was $6.6 million and $5.0 million, respectively. Had the compensation expense for Cleco Corporation's stock-based compensation plans been determined consistent with SFAS No. 123, net income and

	For the year ended December 31,
		2003		2002		2001
		As Reported	Pro Forma	As Reported	Pro Forma	As Reported	Pro Forma
		(Thousands, except per share amounts)
SFAS No. 123 expense		$ -	$ 564	$ -	$ 654	$ -	$ 589
Estimated reduction in income tax for SFAS No.123 expense		-	(226)	-	(242)	-	(204)
Net (loss) income applicable to common stock		$ (36,790)	$ (37,128)	$ 70,003	$ 69,591	$ 68,362	$ 67,977
Net (loss) income per basic common share		$ (.79)	$ (.79)	$ 1.51	$ 1.50	$ 1.52	$ 1.51
Net (loss) income per diluted common share		$ (.79)	$ (.79)	$ 1.47	$ 1.46	$ 1.47	$ 1.46

The assumptions used to calculate the additional compensation expense are as follows:

The effects of applying SFAS No. 123 in this pro forma disclosure are not necessarily indicative of future amounts. SFAS No. 123 is not applicable to awards prior to 1995. Cleco Corporation anticipates making awards in the future under Cleco's stock-based compensation plans.

Cleco Power follows SFAS No. 71, which allows utilities to capitalize or defer certain costs based on regulatory approval and management's ongoing assessment that it is probable these items will be recovered through the ratemaking process.

The deferred storm restoration costs, deferred mining costs, deferred interest costs, and the deferred asset removal costs are presented in the line item entitled "Other Deferred Charges" and the deferred fuel and purchased power costs are presented on the line item entitled "Accumulated Deferred Fuel" on the Cleco Corporation Consolidated Balance Sheets. Under the current regulatory and competitive environment, Cleco Power believes these regulatory assets will be fully recoverable; however, if in the future, as a result of regulatory changes or increased competition, Cleco Power's ability to recover these regulatory assets would not be probable, then to the extent that such regulatory assets were determined not to be recoverable, Cleco Power would be required to write-off or write-down such assets.

The following chart summarizes Cleco Power's regulatory assets and liabilities at December 31, 2003 and 2002:

	At December 31,				Remaining
	2003		2002		Recovery Period
		(Thousands)
Depreciation	$	27,110	$	43,748
Asset basis differences		860		1,349
Prior years flowthrough		9,233		14,928
Other		-		24
Total federal regulatory asset - SFAS No. 109		37,203		60,049

Depreciation		22,883		6,150
Asset basis differences		6,111		1,566
Prior years flowthrough		556		167
Nonplant		2,676		(3,334)
Total state regulatory asset - SFAS No. 109		32,226		4,549

Total AFUDC		34,531		31,547
Total investment tax credit		(10,818)		(30,877)
Total regulatory assets and liabilities - deferred taxes, net		93,142		65,268
Deferred mining costs		9,724		8,347		8 yrs.
Deferred storm restoration costs		6,930		7,038		5 yrs.
Deferred interest costs		9,547		9,261		33 yrs.
Deferred fuel and purchased power		(6,579)		(3,509)
Deferred asset removal costs		265		-
Total deferred costs		19,887		21,137
Total regulatory assets and liabilities, net	$	113,029	$	86,405

At December 31, 2003, and 2002, Cleco Power had recorded $93.1 million and $65.3 million, respectively, of SFAS No. 109 net regulatory assets related to probable future taxes payable that will be recovered from customers through future rates. The regulatory requirement to flow through the current tax benefits of certain accelerated deductions to customers results in deferred tax liabilities that are recovered from ratepayers as they are paid. Regulatory asset and liability recovery periods are based on assets' lives, which are typically 30 years or greater, and are attributable to differences between book and tax income. The effects of potential deregulation of the industry or possible future changes in the method of rate regulation of Cleco Power could require discontinuance of the application of SFAS No. 71.

In May 2001, Cleco Power signed a lignite contract with the miner at the Dolet Hills mine. As ordered by the LPSC in dockets U-21453, U-20925(SC) and U-22092(SC) (Subdocket G), retail ratepayers are receiving fuel cost savings equal to at least 2% of the projected costs under the previous mining contract through 2011. Costs above 98% of the previous contract's projected costs are deferred. Deferred costs will be recovered from retail customers through the fuel adjustment clause when the actual costs of the new contract are below 98% of the projected costs of the previous contract. Cleco Power recorded recovery of $0.5 million in the fourth quarter of 2003 as the miner's cost fell below the 98% threshold. As of December 31, 2003 and 2002, Cleco Power had remaining deferred costs and interest relating to the mining contract of $9.7 million and $8.3 million, respectively.

Deferred Storm Restoration Costs

Cleco Power incurred approximately $29.0 million of storm restoration costs, primarily during the fourth quarter of 2002, to replace utility poles and conductors damaged by Tropical Storm Isidore and Hurricane Lili. According to an agreement with the LPSC, approximately $8.2 million of these restoration costs were recorded as a regulatory asset ($7.0 million in 2002 and $1.2 million in 2003), for recovery over the six-year period which began in January 2003. The balance deferred at December 31, 2003, and 2002, was $6.9 million and $7.0 million, respectively.

Cleco Power's "Other Deferred Charges" include additional deferred capital construction financing costs authorized by the LPSC. At December 31, 2003 and 2002, these costs totaled $9.5 million and $9.3 million, respectively, and are being recovered over the estimated lives of the respective assets constructed.

The cost of fuel used to generate electricity and the cost of purchased power are recovered through the LPSC established fuel adjustment clause, which enables Cleco Power to pass on to customers substantially all such charges. Cleco Power's fuel adjustment clause is regulated by the LPSC (representing about 93% of its total fuel costs) and the FERC. Deferred fuel and purchased power costs recorded at December 31, 2003, and 2002, of $6.6 million and $3.5 million, respectively, represent over-recovery of costs scheduled to be credited to customer bills in future months.

For information regarding deferred asset removal costs, see Note 28 - "Accounting for Asset Retirement Obligation."

Two electric generation units operated by Cleco Power are jointly owned with other utilities. Cleco Power recognized $9.4 million, $8.6 million, and $10.5 million of its proportionate share of operation and maintenance expenses associated with these two units, not including fuel, during the years ended December 31, 2003, 2002 and 2001; respectively.

The amounts reflected in Cleco's and Cleco Power's Balance Sheets at December 31, 2003, and 2002, for cash and cash equivalents, accounts receivable, accounts payable, and short-term debt approximate fair value because of their short-term nature. Estimates of the fair value of Cleco's and Cleco Power's long-term debt and Cleco's nonconvertible preferred stock are based upon the quoted market price for the same or similar issues or by a discounted present value analysis of future cash flows using current rates obtained by Cleco and Cleco Power for debt and by Cleco for preferred stock with similar maturities. In connection with the establishment of the ESOP, the ESOP borrowed $30.0 million. Subsequently, Cleco Power purchased the loan. The amount of the loan is directly offset by Cleco Power's guarantee of the loan. The fair value of Cleco's convertible preferred stock is estimated assuming its conversion into common stock at the market price per common share at December 31, 2003, and 2002, with proceeds from the sale of the common stock used to repay the principal balance of Cleco Power's loan to the ESOP. The estimated fair value of energy market positions is based upon observed market prices when available. When such market prices are not available, management estimates market value at a discrete point in time by assessing market conditions and observed volatility. These estimates are subjective in nature and involve uncertainties. Therefore, actual results may differ from these estimates.

The financial instruments not marked-to-market are reported on Cleco's and Cleco Power's Balance Sheets at carrying value. The financial instruments marked-to-market represent off-balance sheet risk because, to the extent Cleco and Cleco Power have an open position, they are exposed to the risk that fluctuating market prices may adversely affect their financial condition or results of operations upon settlement. Original value represents the fair value of the positions at the time originated.

Cleco

Cleco's total indebtedness as of December 31, 2003, and 2002, was as follows:

The amounts payable under long-term debt agreements for each year through 2008 and thereafter are listed below:

The weighted average interest rate on short-term debt at December 31, 2003, was 2.82% compared to 2.74% at December 31, 2002.

Cleco Power's total indebtedness as of December 31, 2003, and 2002, was as follows:

Short-term bank loans	$	-	$	107,000

First mortgage bonds
Series X, 9.5%, due 2005	$	60,000	$	60,000
Senior notes, 5.375%, due 2013		75,000		-
Pollution control revenue bonds, 5.875%, due 2029, callable after September 1, 2009		61,260		61,260
Total bonds		196,260		121,260

Medium-term notes
6.55%, due 2003		-		15,000
7.00%, due 2003		-		10,000
6.20%, due 2006		15,000		15,000
6.32%, due 2006		15,000		15,000
6.95%, due 2006		10,000		10,000
6.53%, due 2007		10,000		10,000
7.00%, due 2007		25,000		25,000
7.50%, due 2007		15,000		15,000
6.52%, due 2009		50,000		50,000
Total medium-term notes		140,000		165,000

Insured quarterly notes
6.05%, due 2012, callable after June 1, 2004		50,000		50,000
6.125%, due 2017, callable after March 1, 2005		25,000		25,000
Total insured quarterly notes		75,000		75,000
Gross amount of long-term debt		411,260		361,260
Less:
Amount due within one year		-		(25,000)
Unamortized premium and discount, net		(684)		(743)

Total long-term debt, net	$	410,576	$	335,517

The amounts payable under long-term debt agreements for each year through 2008 and thereafter are listed below:

At December 31, 2003, Cleco Power had no outstanding short-term debt. At December 31, 2002, there was outstanding short-term debt and the weighted average interest rate was 2.32%.

Cleco has two separate revolving credit facilities totaling $185.0 million and one credit facility totaling $36.8 million. Compensating balances are required for one of the facilities.

Cleco Corporation has a revolving credit facility totaling $105.0 million. This is a 364-day facility, which provides that borrowings outstanding on the maturity date may be converted into a nine-month term loan. The commitment fees for this facility are based upon Cleco Corporation's lowest secured debt ratings and are currently 0.30%. The facility is scheduled to expire in May 2004. This facility provides for working capital and other needs. If Cleco Power or Midstream default under their respective facilities, then Cleco Corporation would be considered in default under this facility. Perryville's default on the Senior Loan Agreement, which is discussed further in Note 27 - "Perryville," is not considered a default under this new credit facility. As of December 31, 2003,

Cleco Corporation was in compliance with the covenants in this credit facility. Off-balance sheet commitments entered into by Cleco with third parties for certain types of transactions between those parties and Cleco's subsidiaries, other than Cleco Power, reduce the amount of credit available to Cleco Corporation under the facility by an amount equal to the stated or determinable amount of the primary obligation. At December 31, 2003, there was $50.0 million drawn on the facility, leaving $55.0 million available. The $55.0 million at December 31, 2003, was further reduced by off-balance sheet commitments of $22.5 million, leaving available capacity of $32.5 million. An uncommitted line of credit with a bank in an amount up to $5.0 million also is available to support Cleco Corporation's working capital needs.

On June 25, 2001, Midstream entered into a $36.8 million uncollateralized credit facility. The 364-day facility was scheduled to terminate in June 2002, but was extended through September 30, 2002. On August 30, 2002, Midstream's credit facility was amended and restated, including new terms for principal and interest payments through March 31, 2004. The interest rate on this credit facility resets quarterly, is based on LIBOR plus 3.00%, including commitment fees, and was 4.125% at December 31, 2003. Under the terms of Midstream's line of credit, $1.8 million of APH's cash is restricted. At December 31, 2003, there was an outstanding draw in the amount of $17.8 million under this credit facility. As of December 31, 2003, Midstream was in compliance with the covenants in this credit facility. This facility requires that net proceeds from any sale of the Perryville assets first must be applied to any outstanding borrowings under this credit facility.

Cleco Power has a revolving credit facility totaling $80.0 million. This facility provides that borrowings outstanding on the maturity date may be converted into a nine-month term loan. This facility will provide working capital and other needs. Commitment fees are based upon Cleco Power's lowest secured debt rating and are currently 0.25%. The facility is scheduled to expire in May 2004. At December 31, 2003, there were no outstanding draws under this credit facility. As of December 31, 2003, Cleco Power was in compliance with the covenants in this credit facility.

The first mortgage bonds are collateralized by the LPSC-jurisdictional property, plant and equipment ($960.4 million as of December 31, 2003) owned by Cleco Power. In the various parishes (counties) that contain such property, a lien is filed with the clerk of court. Before Cleco Power can sell any of this property, it must obtain a release signed by the trustee.

Perryville's Senior Loan Agreement is considered short-term and is classified in the current liabilities section of the balance sheet due to defaults under the Senior Loan Agreement. The Senior Loan Agreement is collateralized with the Perryville power plant assets ($164.5 million as of December 31, 2003) held by Perryville. At December 31, 2003, the principal balance of the Senior Loan Agreement was $133.0 million. Perryville's obligations under the Subordinated Loan Agreement, including the accrual of additional interest, have been indefinitely suspended due to the Mirant Debtors' bankruptcy and MAEM's failure to make payments under the Perryville Tolling Agreement. At December 31, 2003, the amount outstanding under the Subordinated Loan Agreement was $98.7 million. The Mirant Debtors asserted that the Perryville Tolling Agreement was rejected as of September 15, 2003. On January 28, 2004, Perryville entered into an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. and entered into a power purchase agreement to sell the output of the Perryville facility to Entergy Services, Inc. To facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The outstanding amounts due under the Senior Loan Agreement were deemed accelerated upon the bankruptcy filings by Perryville and PEH. As a result of the commencement of such bankruptcy cases and by virtue of the automatic stay under the U.S. Bankruptcy Code, the lenders' ability to exercise their remedies under the Senior Loan Agreement, including, but not limited to, their ability to foreclose on the mortgage or assume ownership of the Perryville facility, are significantly limited and would require approval of the Bankruptcy Court. For additional information on the Senior Loan Agreement, the Subordinated Loan Agreement, and the Mirant Debtors' bankruptcy, see Note 27 - "Perryville." For additional information on the sale agreement, power purchase agreement and bankruptcy filings, see Note 30 - "Subsequent Events - Perryville."

Evangeline's only long-term debt is the senior secured bonds, which are due in 2019. If Williams Energy fails to perform its obligation under the Evangeline Tolling Agreement, Evangeline's senior secured bonds could be affected. Under provisions of the bonds issued by Evangeline, the bondholders have the right to cause the entire outstanding principal amount ($202.8 million as of December 31, 2003) plus accrued interest to be immediately due and payable upon a default under the Evangeline Tolling Agreement by Williams Energy. The senior secured bonds are collateralized with the Evangeline generation station assets ($201.4 million as of December 31, 2003) held by Evangeline. The bonds issued by Evangeline are nonrecourse to Cleco Corporation.

On April 28, 2003, Cleco Corporation issued $100.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 7.0%. The notes mature on May 1, 2008. The net proceeds from the notes offering were used to repay outstanding borrowings under Cleco Corporation's revolving credit facility. The notes were issued pursuant to Cleco Corporation's debt shelf registration statement (Registration No. 333-33098). No additional debt securities may be offered and sold under this shelf registration statement.

On April 28, 2003, Cleco Power issued $75.0 million aggregate principal amount of its senior unsecured notes at an interest rate of 5.375%. The notes mature on May 1, 2013. The net proceeds from the notes offering were used to repay outstanding borrowings under Cleco Power's revolving credit facility. The notes were issued pursuant to Cleco Power's debt shelf registration statement (Registration No. 333-52540). Cleco Power has issued a total of $150.0 million in aggregate principal amount of debt securities pursuant to the shelf registration statement, leaving $50.0 million available for future issuance.

On October 6, 2003, Cleco Corporation filed a shelf registration statement (Registration No. 333-109506) providing for

the issuance of up to $200.0 million of debt securities, common stock, preferred stock, or any combination thereof. In addition, on October 6, 2003, Cleco Power filed a shelf registration statement (Registration No. 333-109507) providing for the issuance of up to $150.0 million of debt securities. These shelf registration statements have not yet been declared effective by the SEC.

In connection with incentive compensation plans in effect during the three-year period ended December 31, 2003, certain officers and key employees of Cleco were awarded shares of restricted Cleco Corporation common stock. The cost of the restricted stock awards, as measured by the market value of the common stock at the time of the grant, is recorded as compensation expense during the periods, generally three years, in which the restrictions lapse. As of December 31, 2003 and 2002, Cleco has $2.6 million and $2.5 million, respectively, recorded as unamortized deferred compensation costs included in common equity. During the year ended December 31, 2003, Cleco recorded a reduction in compensation expense related to this plan of $1.6 million. During the years ended December 31, 2002 and 2001, Cleco recorded compensation expense related to this plan of $6.6 million and $5.0 million, respectively. As of December 31, 2003, the number of shares of restricted stock previously granted for which restrictions had not lapsed totaled 373,847 shares.

Cleco Corporation records no charge to expense with respect to the granting of options at fair market value or above to employees or directors. Options may be granted to certain officers, key employees, or directors of Cleco. During 2003, Cleco Corporation granted options exercisable for 41,250 shares of common stock to directors and granted options exercisable for 22,550 shares of common stock to key employees. The directors' options have an exercise price approximately equal to the fair market value of the stock at grant date, are immediately exercisable, and expire after ten years. The employees' options have an exercise price approximately equal to the fair market value of the stock at grant date, vest one-third each year, beginning on the third anniversary of the grant date, and expire after ten years. In accordance with APB Opinion No. 25, no compensation expense for stock options granted has been recognized.

Changes in incentive shares for the three-year period ended December 31, 2003, were as follows:

			Incentive Share
	Option Price		Unexercised	Available for
	per Share		Option Shares	Future Grants

Balance, January 1, 2001			1,250,162	1,325,904

Options exercised	$	15.9375	(6,668)	-
Options exercised	$	16.1250	(3,600)	-
Options forfeited	$	16.1250	(30,000)	30,000
Options forfeited	$	19.205 to 21.580	(140,000)	140,000
Options granted (directors)	$	22.6875	10,000	(10,000)
Options granted (directors)	$	23.2500	3,334	(3,334)
Options granted (directors)	$	22.2500	25,000	(25,000)
Options granted - basic (employees)	$	22.2500	215,000	(215,000)
Options granted - basic (employees)	$	20.3750	9,000	(9,000)
Restricted stock granted			-	(120,016)
Restricted stock forfeited			-	(5,183)

Balance, December 31, 2001			1,332,228	1,108,371

Options exercised	$	16.1300	(24,000)	-
Options forfeited	$	16.1300	(20,000)	20,000
Options forfeited	$	22.2500	(26,099)	26,099
Options forfeited	$	17.3200	(1,333)	1,333
Options forfeited	$	24.2500	(13,333)	13,333
Options forfeited - premium (employees)	$	19.205 to 21.580	(100,666)	100,666
Options forfeited - premium (employees)	$	20.620 to 23.170	(16,000)	16,000
Options granted - (directors)	$	18.1250	22,500	(22,500)
Options granted - (directors)	$	24.0000	20,000	(20,000)
Options granted - basic (employees)	$	24.2500	82,100	(82,100)
Restricted stock granted			-	(147,447)
Restricted stock forfeited			-	10,189

Balance, December 31, 2002			1,255,397	1,023,944

Options exercised	$	15.9375	(5,000)	-
Options exercised	$	16.2500	(2,500)	-
Options forfeited	$	16.1250	(27,600)	27,600
Options forfeited	$	18.4400	(2,400)	2,400
Options forfeited	$	22.2500	(8,000)	8,000
Options forfeited	$	24.2500	(5,500)	5,500
Options granted (directors)	$	14.8750	15,000	(15,000)
Options granted (directors)	$	16.2500	26,250	(26,250)
Options granted - basic (employees)	$	16.2500	13,550	(13,550)
Options granted - basic (employees)	$	16.3750	9,000	(9,000)
Restricted stock granted			-	(176,266)
Restricted stock forfeited			-	91,022

Balance, December 31, 2003			1,268,197	918,400

The following table summarizes information about employee and director stock options outstanding at December 31, 2003:

							Weighted				Weighted Average
						Number	Average				Remaining
	Range of		Number			Exercisable at	Exercise				Contractual Life
	Exercise Price		Outstanding			12/31/2003	Price				In Years
$		15.9380		18,338	18,338			$	15.938	4.33
$		15.9380		10,000	10,000			$	15.938	5.38
$		16.1250		217,800	145,200			$	16.125	5.56
$		19.205 to 21.580		472,134	314,756			$	20.380	5.56
$		15.9380		556	556			$	15.938	5.96
$		17.3150		26,667	22,222			$	17.315	6.33
$		20.620 to 23.170		38,000	12,667			$	21.883	6.33
$		18.4400		35,400	11,800			$	18.440	6.58
$		21.960 to 24.675		54,000	18,000			$	23.305	6.58
$		22.6875		10,000	10,000			$	22.688	7.33
$		23.2500		3,334	3,334			$	23.250	7.42
$		22.2500		205,901	25,000			$	22.250	7.58
$		20.3750		9,000	-			$	20.375	7.76
$		24.2500		63,267	-			$	24.250	8.30
$		24.0000		20,000	-			$	24.000	8.33
$		18.1250		22,500	22,500			$	18.125	8.56
$		14.8750		15,000	15,000			$	14.875	9.32
$		16.2500		37,300	23,750			$	16.250	9.57
$		16.3750		9,000	-			$	16.375	9.76

Various debt agreements contain covenants that restrict the amount of retained earnings that may be distributed as dividends to common shareholders. The most restrictive covenant requires Cleco Corporation's total indebtedness be less than or equal to 75% of total capitalization. At December 31, 2003, approximately $126.8 million of retained earnings was not restricted.

In July 2000, Cleco Corporation's Board of Directors adopted the Shareholder Rights Plan (Rights Plan). Under the Rights Plan, the holders of common stock as of August 14, 2000, received a dividend of one right for each share of common stock held on that date. In the event an acquiring party accumulates 15% or more of Cleco Corporation's common stock, the rights would, in essence, allow the holder to purchase Cleco Corporation's common stock at half the current fair market value. Cleco Corporation generally would be entitled to redeem the rights at $0.01 per right at any time until the tenth day following the time the rights become exercisable. The rights expire on July 30, 2010.

In January 2000, Cleco Corporation's Board of Directors adopted the ESPP. Shareholders approved the plan in April 2000, and the plan was implemented effective October 1, 2000.

Regular, full-time, and part-time employees of Cleco Corporation and its participating subsidiaries, except officers, general managers, and employees who own 5% or more of Cleco Corporation's stock, may participate in the ESPP. An eligible employee enters into an option agreement to become a participant in the ESPP. Under the agreement, the employee authorizes payroll deductions in an amount not less than $10 but not more than $350 each pay period. Payroll deductions are accumulated during a calendar quarter and applied to the purchase of common stock at the end of each quarter, which is referred to as an "offering period." Pending the purchase of common stock, payroll deductions remain as general assets of Cleco. No trust or other fiduciary account has been established in connection with the ESPP. At the end of each offering period, payroll deductions are automatically applied to the purchase of shares of common stock. The number of shares of common stock purchased is determined by dividing each participant's payroll deductions during the offering period by the option price of a share of common stock.

A maximum of 684,000 shares of common stock may be purchased under the ESPP, subject to adjustment for changes in the capitalization of Cleco Corporation. The Compensation Committee of Cleco Corporation's Board of Directors administers the ESPP. The Compensation Committee and the Board of Directors each possess the authority to amend the ESPP, but shareholder approval is required for any amendment that increases the number of shares covered by the ESPP. As of December 31, 2003, there were 549,867 shares of common stock left to be purchased under the ESPP.

On April 27, 2001, Cleco Corporation shareholders approved a two-for-one stock split of Cleco Corporation's common stock. As a result of the stock split, Cleco Corporation's 50,000,000 authorized shares of $2 par value common stock were reclassified into 100,000,000 authorized shares of $1 par value common stock. The two-for-one stock split of Cleco Corporation's common stock was effective for shareholders of record at the close of business on May 7, 2001. After the stock split, Cleco Corporation had approximately 45.0 million shares of common stock outstanding. The effect of the stock split has been recognized in all share and per share data in the accompanying consolidated financial statements, notes to the financial statements, and supplemental financial data.

On May 8, 2002, Cleco Corporation issued 2.0 million shares of common stock in a public offering. Net proceeds from the issuance were approximately $44.3 million.

In 1991, Cleco Corporation began a common stock repurchase program, in which up to $30.0 million of common stock may be repurchased. At December 31, 2003, approximately $16.1 million of common stock was available for repurchase under this program. Purchases are made on a discretionary basis in the open market or otherwise, at times and in amounts as determined by management, subject to market conditions, legal requirements, and other factors. The purchases may not be announced in advance and may be made in the open market or in privately negotiated transactions. Cleco Corporation did not purchase any common stock under the repurchase plan in 2003 or 2002, but did purchase $3.0 million of common stock during 2001. There is no expiration date for the program.

Within the ESOP, each share of Cleco Corporation 8.125% Convertible Preferred Stock Series of 1991 is convertible into 9.6 shares of Cleco Corporation common stock. The annual dividend rate on the Cleco Corporation ESOP preferred stock is generally the higher of (a) $8.125 per share or (b) 9.6 times the Cleco Corporation common stock annual dividend.

The amount of total capitalization reflected in Cleco Corporation's Consolidated Financial Statements has been reduced by an amount of deferred compensation expense related to the shares of convertible preferred stock that have not yet been allocated to ESOP participants. The amounts shown in Cleco Corporation's Consolidated Financial Statements for preferred dividend requirements in 2003, 2002, and 2001 have been reduced by approximately $187,000, $266,000, and $326,000, respectively, to reflect the benefit of the income tax deduction for dividend requirements on unallocated shares held by the ESOP.

Upon involuntary liquidation of their stock, preferred shareholders are entitled to receive par value for shares held before any distribution is made to common shareholders. Upon voluntary liquidation, preferred shareholders are entitled to receive the redemption price per share applicable at the time such liquidation occurs, plus any accrued dividends.

Information about the components of preferred stock capitalization is as follows:

			BALANCE		BALANCE		BALANCE		BALANCE
			JAN. 1,		DEC. 31,		DEC. 31,		DEC. 31,
(Thousands, except share amounts)			2001	CHANGE	2001	CHANGE	2002	CHANGE	2003

Cumulative preferred stock,
		$100 par value
	Not subject to mandatory redemption
		4.50%	$ 1,029	$ -	$ 1,029	$ -	$ 1,029	$ -	$ 1,029
	Convertible, Series of 1991,
		Variable rate	27,061	(764)	26,297	(748)	25,549	(1,254)	24,295
			$ 28,090	$ (764)	$ 27,326	$ (748)	$ 26,578	$ (1,254)	$ 25,324

Deferred compensation related to convertible preferred stock held by the ESOP			$ (12,994)	$ 1,656	$ (11,338)	$ 2,268	$ (9,070)	$ 2,463	$ (6,607)

Cumulative preferred stock,
		$100 par value
	Number of shares
		Authorized	1,352,000	-	1,352,000	-	1,352,000	-	1,352,000
		Issued and outstanding	280,900	(7,640)	273,260	(7,480)	265,780	(12,540)	253,240

Cumulative preferred stock
		$25 par value
	Number of shares authorized
		(None outstanding)	3,000,000		3,000,000		3,000,000		3,000,000

Preferred stock, other than the convertible preferred stock held by the ESOP, is redeemable at Cleco Corporation's option, subject to 30 days' prior written notice to shareholders. The convertible preferred stock is redeemable at any time at Cleco Corporation's option. If Cleco Corporation were to elect to redeem the convertible preferred stock, shareholders could elect to receive the optional redemption price or convert the preferred stock into common stock. The redemption provisions for the various series of preferred stock are shown in the following table.

Most employees are covered by a noncontributory, defined benefit pension plan. Benefits under the plan reflect an employee's years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last 10 years of employment with Cleco Corporation. Cleco Corporation's policy is to base its contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the Internal Revenue Service's full funding limitation. A discretionary contribution of $2.9 million was made during 2003. No contributions to the pension plan were made during 2002 or 2001. Currently, a contribution required by funding regulations is not expected during 2004. A discretionary contribution may be made during 2004; however, the decision to make a contribution and the amount, if any, has not been determined. Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.

Cleco Corporation's retirees and their dependents are eligible to receive medical, dental, vision, and life insurance benefits (other benefits). Cleco Corporation recognizes the expected cost of these benefits during the periods in which the benefits are earned.

The employee pension plan and other benefits obligation plan assets and funded status as determined by the actuary at December 31, 2003, and 2002, are presented in the following table.

			Pension Benefits				Other Benefits
			2003		2002		2003		2002
					(Thousands)
Change in benefit obligation
	Benefit obligation at beginning of year	$	189,384	$	161,111	$	31,829	$	22,288
	Service cost		5,354		4,653		1,771		1,309
	Interest cost		12,292		11,502		2,102		1,828
	Plan participants' contributions		-		-		451		432
	Amendments		-		166		-		-
	Special termination benefits		-		1,599		-		150
	Curtailment loss (gain)		-		987		-		(918)
	Actuarial loss		21,994		18,631		3,617		8,614
	Expenses paid		(1,330)		(982)		-		-
	Benefits paid		(9,618)		(8,283)		(2,248)		(1,874)
	Benefit obligation at end of year		218,076		189,384		37,522		31,829

Change in plan assets
	Fair value of plan assets at beginning of year		167,978		191,950		-		-
	Actual return on plan assets		33,271		(14,707)		-		-
	Employer contribution		2,900		-		-		-
	Expenses paid		(1,330)		(982)		-		-
	Benefits paid		(9,618)		(8,283)		-		-
	Fair value of plan assets at end of year		193,201		167,978		-		-

Funded status			(24,875)		(21,406)		(37,522)		(31,829)
	Unrecognized net actuarial loss		36,890		30,453		11,036		7,877
	Unrecognized transition obligation/(asset)		(37)		(1,355)		4,208		4,597
	Unrecognized prior service cost		9,500		10,486		-		-
	Prepaid (accrued) benefit cost	$	21,478	$	18,178	$	(22,278)	$	(19,355)

Employee pension plan assets are invested in publicly traded domestic common stocks, including Cleco Corporation common stock; U.S. government, federal agency and corporate obligations; an international equity fund, commercial real estate funds; and pooled temporary investments. The table below shows a breakdown of the plan assets by investment category based on market values at December 31.

The employee pension plan accumulated benefit obligation as determined by the actuary at December 31, 2003, and 2002, is presented in the following table.

The components of net periodic pension and other benefits cost (income) for 2003, 2002, and 2001 are as follows:

	Pension Benefits			Other Benefits
	2003	2002	2001	2003	2002	2001
	(Thousands)
Components of periodic benefit costs
Service cost	$ 5,354	$ 4,653	$ 3,932	$ 1,771	$ 1,309	$ 1,076
Interest cost	12,292	11,502	10,697	2,102	1,828	1,484
Expected return on plan assets	(17,714)	(18,687)	(17,404)	-	-	-
Special termination benefits	-	1,599	-	-	150	-
Curtailment loss	-	987	-	-	-	-
Amortization of transition obligation (asset)	(1,318)	(1,318)	(1,318)	389	492	513
Prior period service cost amortization	986	1,062	1,067	-	-	-
Net (gain) loss amortization	-	(635)	(1,650)	458	47	(2)
Net periodic benefit cost (income)	$ (400)	$ (837)	$ (4,676)	$ 4,720	$ 3,826	$ 3,071

The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows:

In the fourth quarter of 2002, Cleco recognized a restructuring charge of $10.2 million. A portion of the restructuring charge included a curtailment loss of $1.0 million, special termination benefits of $1.6 million related to the pension plan, and special termination benefits of $0.2 million related to

other benefits. For more information about the restructuring charge, see Note 20 - "Restructuring Charge."

Cleco Corporation's retirement committee has established investment performance objectives of the pension plan assets. Over a three to five year period, the objectives are for the pension plan's annualized total return to:

In order to meet the objectives and to control risk, the retirement committee has established guidelines that the investment managers must follow.

All portfolios are prohibited from utilizing derivatives (such as options or futures), short sales, and leveraging portfolio positions through borrowings or other encumbrances of the pension plan's assets.

The retirement committee has established the following investment asset allocation target percentages for the pension plan assets.

The expected return on plan assets was determined by examining the risk profile of each target category as compared to the expected return on that risk, within the parameters determined by the retirement committee. The result was compared to the expected rate of return of other comparable plans to ensure Cleco Corporation's estimation was within a reasonable range. In assessing the risk as compared to return profile, historical returns as compared to risk was one factor considered. The historical risk compared to returns was adjusted for the expected future long-term relationship between risk and return. The adjustment for the future risk compared to returns was, in part, subjective and not based on any measurable or observable events.

At December 31, 2003, and 2002, the pension plan held 28,292 shares of Cleco Corporation common stock. None of the plan participants' future annual benefits are covered by insurance contracts.

The assumed health care cost trend rates used to measure the expected cost of other benefits were 11.0% in 2003, 11.0% in 2002, and 9.0% in 2001. The rate declines to 4.5% by 2010 and remains at 4.5% thereafter. Assumed health care cost trend rates have a significant effect on the amount reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on other benefits:

On December 8, 2003, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

Paragraph 40 of SFAS No. 106 requires presently enacted changes to relevant laws to be considered in current period measurements of post-retirement benefit costs and benefit obligations. In accordance with FASB Staff Position SFAS No. 106-1, Cleco has elected to defer the recognition of the Act. The benefit obligation and the periodic costs for other benefits disclosed for 2003 do not reflect the impact of passage of the Act. Authoritative guidance on the accounting for the subsidy part of the Act has not been issued. When it is issued, the accounting guidance will contain transition requirements for entities that deferred recognition of the Act. The transition guidance could require entities that deferred recognition of the Act to change previously reported information. The nature of the transition guidance and its timing currently are uncertain. Management is evaluating the Act and the impact of amending the current benefit plan in light of the Act.

Certain key executives and key managers are covered by a SERP. The SERP is a non-qualified, non-contributory, defined benefit pension plan. Benefits under the plan reflect an employee's years of service, age at retirement, and the sum of the highest base salary paid out of the last five calendar years and the average of the three highest bonuses paid during the last 60 months prior to retirement, reduced by benefits received from any other defined benefit pension plan. Cleco Corporation does not fund the SERP liability, but instead pays for current benefits out of the general funds available. Cleco Power has formed a Rabbi Trust designated as the beneficiary for life insurance policies issued on the SERP participants. Proceeds from the life insurance policies are expected to be used to pay SERP participant's life insurance benefits, as well as future SERP payments. However, since this is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency. No contributions to the SERP were made during the three-year period ended December 31, 2003. Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.

The SERP's assets and funded status, as determined by the actuary at December 31, 2003, and 2002, are presented in the following table.

		SERP Benefits
		2003		2002
			(Thousands)
Change in benefit obligation
	Benefit obligation at beginning of year	$	16,018	$	11,525
	Service cost		564		606
	Interest cost		1,155		952
	Amendments		911		(197)
	Actuarial loss		2,616		3,677
	Benefits paid		(768)		(545)
	Benefit obligation at end of year		20,496		16,018

Funded status			(20,496)		(16,018)
	Unrecognized net actuarial loss		9,293		7,111
	Unrecognized prior service cost		762		(95)
	Accrued benefit cost	$	(10,441)	$	(9,002)

Amounts recognized in the statement of financial position consist of:
	Accrued benefit costs	$	(17,018)	$	(13,026)
	Intangible asset		762		-
	Accumulated other comprehensive income		5,815		4,024
	Net amount recognized	$	(10,441)	$	(9,002)

The SERP's accumulated benefit obligation, as determined by the actuary at December 31, 2003, and 2002, is presented in the following table.

The components of the net SERP cost for 2003, 2002, and 2001 are as follows, along with assumptions used.

To calculate periodic costs and the benefit obligation, the SERP plan uses the same discount rate and average rate of compensation increase as the employee pension plan for the same time periods. The SERP plan also uses the same measurement dates. The expected return on plan assets is not applicable since the SERP plan has no assets.

During 2003 and 2002, Cleco recorded a reduction in other comprehensive income of $1.8 million and $4.0 million, respectively, net of the associated increase tax benefit of $0.7 million and $1.5 million. The reduction was due to the recognition of an additional minimum pension liability for the SERP, as defined by SFAS No. 87. The accumulated other comprehensive loss, net of income tax, associated with the recognition of the minimum pension liability is $3.6 million.

Most employees are eligible to participate in a 401(k) savings and investment plan. Cleco Corporation makes matching contributions to 401(k) Plan participants by allocating shares of convertible preferred stock held by the ESOP. Compensation expense related to the 401(k) Plan is based upon the value of shares of preferred stock allocated to ESOP participants and the amount of interest incurred by the ESOP, less dividends on unallocated shares held by the ESOP. At December 31, 2003, and 2002, the ESOP had allocated to employees 195,042 and 181,329 shares, respectively.

For the year ended December 31, 2003, federal income tax benefit is more than the amount computed by applying the statutory federal rate to book loss before tax. For the years ended December 31, 2002 and 2001, federal income tax expense is less than the amount computed by applying the statutory federal rate to book income before tax. The differences are as follows:

	For the year ended December 31,
			2003					2002					2001
	(Thousands, except for %)
		Amount			%		Amount			%		Amount			%
Book (loss) income before tax	$ (58,903)			100.0		$ 114,118			100.0		$ 110,629			100.0
Tax at statutory rate on book (loss) income before tax..	(20,616)			35.0		39,941			35.0		38,720			35.0
Increase (decrease):
Tax effect of AFUDC	(2,216)			3.8		(1,421)			(1.2)		(2,452)			(2.2)
Amortization of investment tax credits	(1,729)			2.9		(1,743)			(1.5)		(1,765)			(1.6)
Tax effect of prior-year tax benefits not deferred	3,537			(6.0)		391			0.3		797			0.7
Other, net	321			(0.6)		971			0.8		(673)			(0.6)
Total federal income tax (benefit) expense	(20,703)			35.1		38,139			33.4		34,627			31.3
Current and deferred state income tax (benefit) expense, net of federal benefit for state income tax (benefit) expense	(3,271)			5.6		4,104			3.6		3,729			3.4
Total federal and state income tax (benefit) expense	$ (23,974)			40.7		$ 42,243			37.0		$ 38,356			34.7

	For the year ended December 31,
		2003		2002		2001
	(Thousands)
Current federal income tax (benefit) expense		$	(18,365)	$	(35,026)	$	40,448
Deferred federal income tax expense (benefit)			997		72,876		(5,903)
Amortization of accumulated deferred investment tax credits			(1,729)		(1,743)		(1,765)
Total federal income tax (benefit) expense			(19,097)		36,107		32,780
Current state income tax expense (benefit)			2,384		(48)		6,571
Deferred state income tax (benefit) expense			(7,261)		6,184		(995)
Total state income tax (benefit) expense			(4,877)		6,136		5,576
Total federal and state income tax (benefit) expense		$	(23,974)	$	42,243	$	38,356
Income tax expense (benefit) from loss on disposal of segment
Federal current		$	-	$	-	$	(2,624)
Federal deferred			-		-		1,522
State current			-		-		(610)
State deferred			-		-		437
Total tax benefit from loss on disposal of segment		$	-	$	-	$	(1,275)
Total federal and state income tax (benefit) expense		$	(23,974)	$	42,243	$	37,081

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2003, and 2002, was comprised of the tax effect of the following:

	At December 31,
	2003				2002
	Current		Noncurrent		Current		Noncurrent
	(Thousands)
Depreciation and property basis differences	$	-	$	(247,628)	$	-	$	(246,816)
State net operating tax losses		-		8,532		-		2,513
SERP - Other comprehensive income		-		2,140		-		1,548
AFUDC		-		(34,661)		-		(30,328)
Investment tax credits		-		10,818		-		13,426
SFAS No. 109 adjustments		-		(69,428)		236		(43,799)
Post retirement benefits other than pension		628		5,782		4,365		5,302
Other		916		(242)		(772)		(865)
Accumulated deferred federal and state income taxes	$	1,544	$	(324,687)	$	3,829	$	(299,019)

Management considers it more likely than not that all deferred tax assets will be realized. Consequently, deferred tax assets have not been reduced by a valuation allowance.

The state net operating tax loss consists of $48.3 million of carryforwards that expire in 2017 and $111.2 million of carryforwards that expire in 2018. Deferred state tax benefits are available to the extent that Cleco has state taxable income prior to expiration. Although Cleco has not currently provided a valuation allowance to reduce the state net operating tax loss, a valuation may be provided in the future if estimates of future taxable state income are reduced.

Cleco Power

Federal income tax expense is less than the amount computed by applying the statutory federal rate to book income before tax, as follows:

	For the year ended December 31,
	2003				2002				2001
	(Thousands, except for %)
		Amount		%		Amount		%			Amount		%
Book income before tax	$ 86,854		100.0		$ 91,746		100.0			$ 90,428		100.0
Tax at statutory rate on book income before tax	30,399		35.0		32,111		35.0			31,649		35.0
Increase (decrease):
Tax effect of AFUDC	(2,216)		(2.6)		(1,421)		(1.5)			(2,452)		(2.7)
Amortization of investment tax credits	(1,729)		(2.0)		(1,743)		(1.9)			(1,765)		(2.0)
Tax effect of prior-year tax benefits not deferred.	3,537		4.1		390		.40			797		0.9
Other, net	(458)		(0.5)		(339)		(.40)			(49)		(0.1)
Total federal income tax expense	29,533		34.0		28,998		31.6			28,180		31.1
Current and deferred state income tax expense, net of federal benefit for state income tax expense	313		0.4		3,174		3.5			3,110		3.4
Total federal and state income tax expense	$ 29,846		34.4		$ 32,172		35.1			$ 31,290		34.5

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2003, and 2002, was comprised of the tax effect of the following:

	At December 31,
	2003					2002
	Current		Noncurrent		Current				Noncurrent
	(Thousands)
Depreciation and property basis differences	$	-	$	(221,818)	$		-	$		(213,584)
SERP - Other comprehensive income		-		921			-			572
AFUDC		-		(34,661)			-			(30,328)
Investment tax credits		-		10,818			-			13,426
SFAS No. 109 adjustments		-		(69,428)			236			(43,799)
Post retirement benefits other than pension		3,583		370			4,271			418
Other		(1,230)		(73)			(855)			(910)
Accumulated deferred federal and state income taxes	$	2,353	$	(313,871)	$		3,652	$		(274,205)

Management considers it more likely than not that all deferred tax assets will be realized. Consequently, deferred tax assets have not been reduced by a valuation allowance.

Regulatory assets and liabilities, net recorded for deferred taxes at December 31, 2003, and 2002, were $93.1 million and $65.3 million, respectively. Regulatory assets and liabilities will be realized over the accounting lives of the related properties to the extent past ratemaking practices are continued by regulators.

Cleco

Cleco has determined that its reportable segments are based on Cleco's method of internal reporting, which disaggregates its business units by first-tier subsidiary. Reportable segments were determined by applying SFAS No. 131. Cleco's reportable segments are Cleco Power, Midstream, and Other. The Other segment consists of the parent company, a shared services subsidiary, an investment subsidiary, and the discontinued operations of UTS. The Other segment subsidiaries operate within Louisiana and Delaware.

Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco's Chief Executive Officer (the chief operating decision-maker) with discrete financial information and, at least quarterly, present discrete financial information to Cleco's Board of Directors. Each reportable segment prepared budgets for 2003 that were presented to and approved by Cleco's Board of Directors. The reportable segments exceeded the quantitative thresholds as defined in SFAS No. 131.

The financial results of Cleco's segments are presented on an accrual basis. Management evaluates the performance of its segments and allocates resources to them based on segment profit (loss) before preferred stock dividends. Material intersegment transactions occur on a regular basis.

					Unallocated
					Items,
		Cleco			Reclassifications
	2003	Power	Midstream	Other	& Eliminations	Consolidated

Revenue
	Electric operations	$ 676,002	$ -	$ -	$ -	$ 676,002
	Tolling operations	-	98,726	-	-	98,726
	Energy trading, net	626	(2,764)	-	1,283	(855)
	Energy operations	-	71,639	-	-	71,639
	Other operations	30,013	711	242	(279)	30,687
	Electric customer credits	(1,562)	-	-	-	(1,562)
Intersegment revenue		2,209	205	40,052	(42,466)	-
Total operating revenue		$ 707,288	$ 168,517	$ 40,294	$ (41,462)	$ 874,637

Depreciation expense		$ 54,084	$ 22,399	$ 1,067	$ -	$ 77,550
Impairments of long-lived assets		$ -	$ 156,250	$ -	$ -	$ 156,250
Interest charges		$ 28,774	$ 39,408	$ 17,516	$ (14,255)	$ 71,443
Interest income		$ 1,335	$ 633	$ 14,563	$ (14,151)	$ 2,380
Equity investment from investees		$ -	$ 31,631	$ -	$ -	$ 31,631
Federal and state income taxes (benefit) expense		$ 29,846	$ (51,807)	$ (1,807)	$ (206)	$ (23,974)
Segment profit (loss) ⁽¹⁾		$ 57,008	$ (85,313)	$ (6,624)	$ -	$ (34,929)

Additions to long-lived assets (other-after allocation)		$ 68,507	$ 4,846	$ 1,158	-	$ 74,511
Segment assets		$ 1,378,916	$ 790,660	$ 649,774	$ (659,924)	$ 2,159,426

(1) Reconciliation of segment profit (loss) to consolidated profit:
			Segment loss		$ (34,929)
			Unallocated items
			Preferred dividends		(1,861)
			Net loss applicable
			to common stock		$ (36,790)

					Unallocated
					Items,
		Cleco			Reclassifications
	2002	Power	Midstream	Other	& Eliminations	Consolidated

Revenue
	Electric operations	$ 568,102	$ -	$ -	$ -	$ 568,102
	Tolling operations	-	90,260	-	-	90,260
	Energy trading, net	(752)	2,421	-	6	1,675
	Energy operations	-	30,050	-	1	30,051
	Other operations	29,331	4,655	88	(38)	34,036
	Electric customer credits	(2,900)	-	-	-	(2,900)
Intersegment revenue		1,708	366	33,371	(35,445)	-
Total operating revenue		$ 595,489	$ 127,752	$ 33,459	$ (35,476)	$ 721,224

Depreciation expense		$ 52,233	$ 15,989	$ 935	$ -	$ 69,157
Impairments of long-lived assets		$ -	$ 3,587	$ -	$ -	$ 3,587
Interest charges		$ 29,091	$ 31,750	$ 13,533	$ (13,765)	$ 60,609
Interest income		$ 933	$ 442	$ 13,833	$ (13,632)	$ 1,576
Equity investment from investees		$ -	$ 16,204	$ -	$ -	$ 16,204
Federal and state income taxes (benefit) expense		$ 32,172	$ 12,740	$ (2,495)	$ (174)	$ 42,243
Segment profit (loss) ⁽¹⁾		$ 59,574	$ 14,660	$ (2,359)	$ -	$ 71,875

Additions to long-lived assets (other-after allocation)		$ 87,321	$ 97,974	$ (1,170)	$ -	$ 184,125
Segment assets		$ 1,338,445	$ 978,947	$ 631,389	$ (604,225)	$ 2,344,556

(1) Reconciliation of segment profit (loss) to consolidated profit:
			Segment profit		$ 71,875
			Unallocated items
			Preferred dividends		(1,872)
			Net income applicable
			to common stock		$ 70,003

Cleco Power is a vertically integrated, regulated electric utility operating within Louisiana and is viewed as one unit by management. Discrete financial reports are prepared only at the company level. This approach is consistent with the standards applicable to segment reporting as defined by SFAS No. 131.

Note 12 - Accrual of Electric Customer Credits

Cleco's reported earnings for December 31, 2003, 2002, and 2001 reflect accruals of $1.6 million, $2.9 million and $1.8 million, respectively, within Cleco Power for electric customer credits that may be required under terms of an earnings review settlement reached with the LPSC in 1996. The 1996 LPSC settlement, and a subsequent amendment, set Cleco Power's rates until September 30, 2004. As part of the settlement, Cleco Power is allowed to retain all regulated earnings up to a 12.25% return on equity, and to share equally with customers as credits on their bills all regulated earnings between 12.25% and 13% return on equity. All regulated earnings above a 13% return on equity are credited to customers. The amount of credits due customers, if any, is determined by the LPSC annually based on results for each 12-month period ended September 30. The settlement provides for such credits to be made on customers' bills the following summer. The LPSC's preliminary report for the cycle ended September 30, 2001, required a $0.6 million refund, which was credited to customers' bills in September 2002. Cleco anticipates receiving the final report for the cycle ended September 30, 2001, by March 31, 2004. The LPSC has not yet issued its preliminary report for the cycle ended September 30, 2002, and Cleco has not yet made its filing for the cycle ended September 30, 2003. Management is unable to predict what Cleco Power's allowed return on equity will be after September 30, 2004.

Cleco Power's Balance Sheets at December 31, 2003 and 2002, under the line item other deferred credits, reflect accruals of $5.0 million and $3.3 million, respectively, for estimated electric customer credits related to the 12-month cycles ended September 30, 2003, 2002, and 2001. These amounts were recorded as a reduction in revenue due to the nature of the customer credits. The accrual is based upon the original 1996 settlement, the resolution of annual issues as agreed between Cleco and the LPSC, and Cleco's assessment of issues that remain outstanding.

Equity investment in investees represents Midstream's $264.1 million investment in Acadia, which is owned 50% by Midstream and 50% by Calpine. Midstream's portion of earnings from Acadia for the year ended December 31, 2003, $31.6 million, is included in the $264.1 million equity investment in Acadia.

Cleco reports its investment in Acadia on the equity method of accounting, as defined in APB Opinion No. 18.

The table below presents the components of Midstream's equity investment in Acadia.

Midstream's equity, as reported in the balance sheet of Acadia at December 31, 2003, was $296.6 million. The difference of $32.5 million between the equity in investee and Midstream's equity represents $19.5 million of interest capitalized on funds contributed to Acadia, as well as other miscellaneous charges related to the construction of the Acadia facility, as indicated in the table above, offset by $52.0 million as a result of different accounting treatment used by the partnership entities for allocation of termination agreement income. The cash distributions of $52.5 million were used to pay interest and repay principal on debt at Cleco Corporation relating to this investment. In May 2003, Acadia terminated its 580-MW, 20-year tolling agreement with Aquila Energy in return for a cash payment of $105.5 million from Aquila Energy. Acadia made a $105.5 million distribution to Calpine. In exchange for this distribution, Calpine entered into a new 580-MW tolling contract with Acadia and assumed the original ending date of the Aquila Energy tolling agreement, which is June 30, 2022. Calpine now markets all of the output from Acadia under the terms of this new contract and an existing 20-year tolling agreement. The Second Amended and Restated Limited Liability Company Agreement of Acadia, entered into in connection with the restructuring of the tolling arrangement, provides for APH's receipt of priority cash distributions and earnings as its consideration for the restructuring. Also, Cleco will have more credit support available in the event Calpine does not fulfill its obligations under either tolling agreement. Calpine has posted letters of credit totaling $33.2 million as of December 31, 2003. An additional $6.8 million was posted on January 22, 2004, which increased the total letters of credit issued by Calpine to their required $40.0 million. These letters of credit have various expiration terms, of which $13.0 million will expire on May 9, 2006, $12.0 million will expire on December 31, 2006, and $15.0 million will remain in effect for the duration of the tolling agreement. The table below contains unaudited summarized financial information for Acadia.

Cleco Energy owns 50% of Hudson SVD LLC, which indirectly owns and operates natural gas pipelines in Louisiana. Hudson also owns controlling interest in an entity that owns and operates a pipeline system in Texas. As of December 31, 2003, Cleco Energy had no remaining equity investment in Hudson SVD LLC due to an impairment taken in December 2003. For additional information on the impairment, see Note 24, "Impairments of Long-Lived Assets."

Under the terms of the Evangeline Tolling Agreement, the tolling counterparty has the right to own, dispatch, and market all of the electric generation capacity produced by Evangeline, and is responsible for providing the required natural gas to the facility. Midstream collects a fee from the tolling counterparty for operating and maintaining the tolled facility. The tolling agreement has terms that extend until at least 2020. The tolling agreement is accounted for as an operating lease and the revenue is recognized as described in Note 2 - "Summary of Significant Accounting Policies - Revenue and Fuel Costs - Tolling Revenue."

Prior to MAEM's rejection of the Perryville Tolling Agreement, MAEM paid Perryville a fixed fee and a variable fee for operating and maintaining the facility. MAEM also paid a quarterly amount to Perryville, which represented its share of Perryville's quarterly parts and maintenance expenses under Perryville's long-term maintenance contract with General Electric Corporation. This amount was based upon Perryville's run hours and factored starts for each quarter. The Perryville Tolling Agreement was accounted for as an operating lease. On January 28, 2004, Perryville reached an agreement to sell its 718-MW power plant to Entergy Louisiana, Inc. and entered into a power purchase agreement. To facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. For additional information on the Perryville Tolling Agreement, see Note 27 - "Perryville." For information on the sale agreement, power purchase agreement, and bankruptcy filings, see Note 30 - "Subsequent Events - Perryville."

The following table contains an analysis of Cleco's property being utilized under operating leases:

The following is a schedule for Evangeline, by years, of future minimum rental payments (assumes no change to the tested capacity or heat rate of the plants) required under the Evangeline tolling agreement:

Future rental payments have not been adjusted for contingent items such as bonuses or penalties, which may change the actual amounts received from the tolling counterparty under the tolling agreement. For the year ended December 31, 2003, tolling rental revenue of $98.7 million was recognized, including contingent rents of approximately $8.3 million. For the years ended December 31, 2002, and 2001, contingent rents were approximately $9.4 million and $4.2 million, respectively. The tolling rental revenue of $98.7 million includes 12 months of Evangeline revenue and Perryville revenue until September 14, 2003.

The following is a schedule of operating leases that Cleco maintains in the ordinary course of business activities. The majority of Cleco's operating leases are for line construction and operating vehicles and for rail cars for coal deliveries, both utilized by Cleco Power. The remaining leases provide for office and operating facilities and office equipment. These leases have various terms and expiration dates from one to 20 years. The following table is a summary of expected operating lease payments for the years indicated.

Evangeline and Perryville changed their accounting estimates relating to useful lives effective July 1, 2001, and October 1, 2002, respectively. The estimated service lives for the majority of Evangeline's plant assets were extended from 27 to 46 years, and the estimated service lives for Perryville's plant assets were extended from 35 to 46 years. The changes were based upon studies performed by independent third party engineering firms. In addition to Perryville's asset lives being extended during 2002, component depreciation escalated depreciation expense for the year, offsetting what would otherwise have been a decline in depreciation due to the extension in the assets' lives. As a result of the above changes, net income applicable to common stock for 2001 increased $0.7 million, or $0.02 per diluted share, and decreased $0.3 million for 2002, or $0.01 per diluted share.

On November 22, 2002, a lawsuit was filed in the Ninth Judicial District Court, Rapides Parish, state of Louisiana, on behalf of a class of persons or entities who purchased Cleco Corporation's common stock during a specified period of time, hereinafter referenced as the Class Period. Cleco Corporation refers to this lawsuit as the Securities Litigation. In the Securities Litigation, the plaintiff alleges that Cleco Corporation issued a number of materially false and misleading statements during the Class Period, among other purposes, in order to cause the price of Cleco Corporation's stock to rise artificially. The plaintiff alleges that, during the Class Period, Cleco Corporation failed to disclose the existence of the round-trip trades that Cleco Corporation disclosed in its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002. The plaintiff also alleges that Cleco Corporation's financial information was not prepared in conformity with accounting principles generally accepted in the United States of America during the Class Period. The defendants removed the lawsuit to the United States District Court for the Western District of Louisiana. In May 2003, the lawsuit was dismissed without prejudice, allowing the plaintiff to re-file the lawsuit subject to certain stipulations and restrictions. On November 13, 2003, the plaintiff again filed suit in the 9^th Judicial District Court, parish of Rapides, state of Louisiana. Cleco Corporation has again removed the suit to the United States District Court for the Western District of Louisiana and has requested that the suit be dismissed pursuant to federal law. The court has not yet ruled on Cleco Corporation's Motion to Dismiss. Based on information currently available to management, Cleco Corporation does not believe the Securities Litigation will have a material adverse effect on Cleco's financial condition or results of operations.

On April 18, 2003, a Shareholder's Derivative Complaint was filed by a shareholder of Westar, in the United States District Court for the District of Kansas. The defendants named in the complaint are Westar, its Board of Directors, its former Chief Executive Officer, President and Chairman, and Cleco Corporation. The complaint alleges violations of Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder, and, in addition, breaches of fiduciary duties owed to Westar, and/or for aiding and abetting such breaches. The complaint asserts that Cleco Corporation aided and abetted the director defendants' breaches of fiduciary duties by engaging in round-trip trades with Westar. The complaint seeks the award of unspecified compensatory damages against the defendants and the plaintiff's costs and disbursements of the lawsuit. The complaint has been amended, but the claims against Cleco Corporation have not changed substantively. The lawsuit has been stayed by agreement of all parties and the court. Management is unable to estimate the impact on Cleco's financial condition or results of operations.

On July 24, 2003, a petition was filed in the 27^th Judicial District Court, parish of St. Landry, by several Cleco Power customers. The named defendants are Cleco Corporation, Cleco Power, Midstream, Marketing & Trading, Evangeline, Acadia, and Westar. The plaintiffs are seeking class action status on behalf of all Cleco Power's retail customers, and their petition centers around Cleco's trading activities first disclosed by Cleco in November 2002. The plaintiffs allege, among other things, that the defendants' conduct was in violation of Louisiana antitrust law. They seek treble damages, restitution, injunctive and other relief. The suit, which is in its formative stages, has been stayed by agreement of all parties until the time that any party requests the court to take up and rule upon the motion filed by the LPSC Staff to stay the case. Accordingly, management is unable to estimate

the impact of this suit on Cleco's financial condition or results of operations.

Cleco is involved in regulatory, environmental, and legal proceedings before various courts, regulatory commissions, and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. In several lawsuits, Cleco has been named as a defendant by individuals who claim injury due to exposure to asbestos while working at sites in central Louisiana. Most of the claimants were workers who participated in the construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by Cleco. Cleco's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Cleco's management believes that the disposition of these matters will not have a material adverse effect on the Registrants' financial condition, results of operations, or cash flow.

	At December 31, 2003
Subsidiaries/Affiliates	Face amount		Reductions		Net amount		Reductions to the amount available to be drawn on Cleco Corporation's credit facility
	(Thousands)
Cleco Corporation guarantee issued to APH's plant construction contractor	$	167	$	-	$	167	$	167

Cleco Corporation obligation under Perryville's debt service reserve		7,342		-		7,342		7,342

Cleco Corporation subordinated guarantee issued to Midstream lender		17,750		-		17,750		-

Cleco Corporation guarantees issued to various Marketing & Trading's and Cleco Energy's counterparties		105,750		72,000		33,750		-

Cleco Corporation obligations under standby letter of credit issued to Evangeline Tolling Agreement counterparty		15,000		-		15,000		15,000

Cleco Power obligations under Lignite Mining Agreement		25,895		-		25,895		-

Total	$	171,904	$	72,000	$	99,904	$	22,509

If Acadia cannot pay the contractor who built its plant, Cleco Corporation will be required to pay 50% of the current amount outstanding. At December 31, 2003, Cleco Corporation's 50% portion of the contractor's current amount outstanding was approximately $0.2 million. The guarantee on the Acadia construction contracts will cease upon full payment of those contracts. Management expects Acadia to have the ability to pay its contractor as scheduled and does not expect Cleco Corporation to pay on behalf of Acadia. However, under the covenants associated with Cleco Corporation's credit facility, the current monthly amount due the Acadia contractor reduces the amount Cleco Corporation can borrow under its credit facility.

If Perryville is unable to make principal and interest payments to its lenders, Cleco Corporation will be required to pay up to $7.3 million on behalf of Perryville under a guarantee issued in connection with the replacement of Perryville's construction loan in the fourth quarter of 2002. However, if Cleco Corporation's long-term senior unsecured debt is rated below BBB- by Standard & Poor's or Baa3 by Moody's, Cleco Corporation will be required to post a letter of credit in the amount of $7.4 million. For information on the Mirant Debtors' bankruptcy impact on the Senior Loan Agreement, see Note 27 - "Perryville."

When Midstream entered into a $36.8 million credit facility, Cleco Corporation entered into a subordinated guarantee with the lender. Under the terms of the guarantee, Cleco Corporation will pay principal and interest if Midstream is unable to pay. At December 31, 2003, there was $17.8 million outstanding under the facility. The subordinated guarantee does not reduce the amount Cleco can borrow under its credit facility, because it is subordinate to Cleco Corporation's other liabilities. The Midstream credit facility is due March 31, 2004.

Cleco Corporation has issued guarantees to Marketing & Trading's counterparties in order to facilitate energy trading and to Cleco Energy's counterparties in order to facilitate energy operations. In conjunction with the guarantees issued, Marketing & Trading has received guarantees from certain counterparties and has entered into netting agreements whereby Marketing & Trading is only exposed to the net open position with each trading counterparty. The guarantees issued and received expire at various times. The balances of net guarantees for Marketing & Trading

and Cleco Energy do not affect the amount Cleco Corporation can borrow under its credit facility. The total amount of guaranteed net open positions with all of Marketing & Trading and Cleco Energy's counterparties over $20.0 million reduces the amount Cleco Corporation can borrow under its credit facility. At December 31, 2003, the total guaranteed net open positions for Cleco Energy were $2.1 million, so the borrowing restriction in Cleco's credit facility was not affected. As counterparties and amounts traded change, corresponding changes will be made in the level of guarantees issued by Cleco Corporation. As of September 4, 2003, all of Marketing & Trading's forward positions were closed; therefore, Cleco Corporation's level of guarantees will decrease as these guarantees are terminated.

As part of a lignite mining agreement entered into in 2001, Cleco Power and SWEPCO, joint owner with Cleco Power of Dolet Hills Unit 1, have agreed to pay the lignite miner's loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered. At December 31, 2003, Cleco Power's 50% exposure was approximately $25.9 million. The lignite mining contract is in place until 2011 and does not affect the amount Cleco Corporation can borrow under its credit facility.

The following table summarizes the expected termination date of the guarantees and standby letter of credit:

Cleco Corporation was previously obligated under guarantees relating to the Perryville Tolling Agreement and the Acadia Tolling Agreement with Aquila Energy. These obligations terminated when the tolling agreements terminated, in September 2003 and May 2003, respectively.

Cleco Corporation had no unconditional long-term purchase obligations at December 31, 2003. Cleco Power has several unconditional long-term purchase obligations related to the purchase of lignite, energy capacity, and energy delivery facilities. The aggregate amount of payments required under such obligations at December 31, 2003 is as follows:

Payments under these agreements for the years ended December 31, 2003, 2002, and 2001 were $16.9 million, $15.8 million, and $16.3 million, respectively.

In the second half of 2002, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit. The audit commenced in March 2003 and includes Fuel Adjustment Clause filings for January 2001 through December 2002, although a portion of the data requested for the audit relates to periods prior to 2001. A Cleco Power customer has intervened and is involved in the LPSC fuel audit proceeding. The audit, pursuant to the Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497, is required to be performed not less than

every other year; however, this is the first LPSC Fuel Adjustment Clause audit of Cleco Power. LPSC-jurisdictional revenue recovered by Cleco Power through its Fuel Adjustment Clause for the audit period of January 2001 through December 2002 was $567.1 million. The LPSC Staff expects to issue its preliminary findings and recommendations related to the fuel audit proceeding by March 31, 2004.

For information regarding an additional contingency, see Note 19 - "Review of Trading Activities."

Cleco has accrued for liabilities to third parties, employee medical benefits, storm damages, and deductibles under insurance policies that it maintains on major properties, primarily generation stations and transmission substations. Consistent with regulatory treatment, annual charges to operating expenses to provide a reserve for future storm damages are based upon the average amount of noncapital, uninsured storm damages experienced by Cleco Power during the previous six years.

In December 2000, management decided to sell substantially all of the assets of UTS and discontinue its operations. On March 31, 2001, management signed an asset purchase agreement to sell UTS to Quanta for approximately $3.1 million in cash and assumption of an operating lease for equipment of approximately $11.6 million. Quanta acquired the trade names under which UTS operated, crew tools, equipment under the operating lease, contracts, inventory relating to certain contracts, and work force in place. UTS retained approximately $2.2 million in accounts receivable, net of allowance for uncollectibles, and equipment under the operating lease with an aggregate unamortized balance of approximately $2.8 million.

For the year 2001, the $2.0 million loss on disposal of a segment, net of income taxes, resulted primarily from actual operating losses in 2001 in excess of estimated operating losses for 2001 that were included in the loss on disposal of a segment for 2000; the $1.3 million loss on the auction of equipment in June 2001 and subsequent extinguishment of the operating lease; and the final asset and receivable settlement agreement signed in November 2001.

At December 31, 2003, UTS had no assets or liabilities and no impact on Cleco's Financial Statements, and the agreed-upon indemnifications had expired without incidents.

Cleco

Cleco Corporation could be subject to possible adverse consequences if any of Cleco's remaining counterparties fail to perform their obligation under their respective tolling agreements, or if Cleco Corporation or its affiliates are not in compliance with loan agreements or bond indentures. Cleco's remaining tolling counterparties are Williams Energy and CES. The following list is not all-inclusive, but represents examples of possible adverse consequences resulting from the nonperformance of Cleco's tolling counterparties and certain defaults resulting from noncompliance with debt covenant agreements or bond indentures:

Cleco Power supplies a portion of its customers' electric power requirements from generation facilities owned by the Company. In addition to power obtained from power purchase agreements, Cleco Power purchases power from other utilities and marketers to supplement its generation at times of relatively high demand or when the purchase price of power is less than Cleco Power's cost of generation. Because of its location on the transmission grid, Cleco Power relies on one main supplier of electric transmission, and constraints sometimes limit the amount of purchased power it can import into its system.

In the third quarter of 2002, Cleco reviewed certain energy trading activities, including transactions between Cleco Power and certain Midstream companies. These activities and transactions may have violated PUHCA, as well as various statutes and regulations administered by the FERC and the LPSC.

Cleco contacted the appropriate regulatory authorities, including the staffs of the FERC and the LPSC, and held discussions with them concerning indirect sales of test power by Evangeline to Cleco Power, a regulated affiliate utility, other indirect acquisitions of purchased power by Cleco Power from Marketing & Trading, Cleco Power's indirect sales of power to Marketing & Trading, and other transactions between Cleco Power and Marketing & Trading. These discussions led to formal investigatory proceedings by the FERC and the LPSC, with which Cleco cooperated. These proceedings have entailed discovery measures by the agencies with jurisdiction over the referenced energy trading transactions and energy trading transactions in general between Cleco's power marketer subsidiaries. At the same time, Cleco conducted its own internal investigations of Cleco's subsidiaries' energy trading activities for regulatory compliance. On July 25, 2003, the FERC issued its order approving the Consent Agreement between the FERC Staff and Cleco which settled the FERC's investigation into certain transactions. For more information about the Consent Agreement and the FERC settlement, see Note 25 - "FERC Settlement." The continuing LPSC investigation may result in determinations of possible or apparent violations in addition to those described in this Note and in Note 25 - "FERC Settlement."

The indirect sales of test power by Evangeline occurred just prior to the commercial operation date of that plant in 2000. More specifically, Evangeline sold test power directly to a third party to be resold to Cleco Power. In addition, Marketing & Trading purchased test power in 2002 from Acadia and sold some of this power to a third party to be resold to Cleco Power. Cleco Power's purchases from these third parties were at the same volumes and same prices as the third parties' purchases from Evangeline or Marketing & Trading and as Marketing & Trading's purchases from Acadia. It appears some of these transactions may have potentially exceeded the pricing standards of the LPSC. Management is unable to predict the remedial actions that may be taken with respect to these transactions by the LPSC. For information about the FERC settlement concerning these transactions, see Note 25 - "FERC Settlement."

During the years 1999 through 2002, Marketing & Trading and Cleco Power engaged in transactions in which power was sold indirectly between Marketing & Trading and Cleco Power through the use of a third party. In these transactions, Marketing & Trading would either indirectly buy power from, or sell power to Cleco Power through the use of a third party. It appears some of these transactions may have potentially exceeded the pricing standards of the LPSC and its guidance concerning affiliate relations. Management is unable to predict the remedial actions that may be taken with respect to these transactions by the LPSC and cannot reasonably estimate Cleco's minimum probable contingency for these transactions. For information about the FERC settlement concerning these transactions, see Note 25 - "FERC Settlement."

From 1999 through mid-January 2002, the same personnel performed the trading operations of Cleco Power and Marketing & Trading. Management believes this relationship and certain

transactions described in this Note may be reviewed in Cleco Power's pending LPSC fuel audit. For additional information on the fuel audit, see Note 16 - "Securities Litigation and Other Commitments and Contingencies." For information about the FERC settlement concerning this issue, see Note 25 - "FERC Settlement."

Cleco Power has recorded reserves that cover the estimated amount of potential refund to customers relating to credits received from Marketing & Trading and Evangeline, as required by the Consent Agreement. Reserves have not been established for any other item relating to the current LPSC fuel audit, because management is unable to predict the actions that may be taken by the LPSC and cannot reasonably estimate Cleco's minimum probable contingency for the fuel audit. For information about the penalties and remedies contained in the Consent Agreement, see Note 25 - "FERC Settlement."

On September 24, 2002, Cleco announced a companywide organizational restructuring. During the fourth quarter of 2002, 123 employees accepted severance (117 actually severed), and 37 employees accepted an early retirement package. The majority of these employees left during the fourth quarter of 2002, resulting in 154 fewer employees. The following table shows the type of charges incurred and the remaining balance in the associated liability accounts, where appropriate, that was still to be paid as of December 31, 2003.

The restructuring charge is presented in a separate line item entitled "Restructuring Charge" in the "Operating Expenses" section of Cleco's Statements of Operations. As a result of this restructuring, no business segment or component of a business segment qualified as a discontinued operation.

The following table shows the type of charges incurred, the amounts paid, the decrease in the amount originally recorded as a restructuring charge and the remaining balance in the associated liability accounts, where appropriate, that is still to be paid as of December 31, 2003, for Cleco Power.

The restructuring charge is presented in a separate line item entitled "Restructuring Charge" in the "Operating Expenses" section of Cleco Power's Statements of Income. As a result of this restructuring, no business segment or component of a business segment qualified as a discontinued operation.

On June 20, 2002, Midstream purchased Mirant's 50% ownership interest in Perryville. Midstream paid Mirant $54.6 million in cash as repayment of project debt, Mirant's invested capital to date, and other miscellaneous costs. The terms of the agreement required Cleco Corporation to retire $48.0 million in project debt owed to Mirant and assume Mirant's total equity commitment of up to $19.5 million. Cleco Corporation used a combination of newly issued common equity and short-term debt to fund its acquisition of Mirant's interest in Perryville. Cleco Corporation discontinued the equity method of accounting effective July 1, 2002, and consolidated Perryville's assets and liabilities as of June 30, 2002. Perryville's revenue and expenses were reported in the Statement of Operations beginning July 1, 2002. As of December 31, 2003 and 2002, Perryville's assets and liabilities were $224.2 million and $232.3 million, respectively. For additional information regarding Perryville, see Note 27 - "Perryville."

Perryville, formerly a joint venture between Midstream and Mirant, completed constructing a 718-MW, natural gas-fired power plant in Perryville, Louisiana, on June 30, 2002. A 156-MW combustion turbine operating in simple cycle became operational on July 1, 2001. Commercial operation of the 562-MW combined-cycle unit began on July 1, 2002. As of December 31, 2003, Perryville had spent $321.1 million constructing the plant, including capitalized interest. Long-term nonrecourse financing was received during June 2001 in the form of a construction note. The construction note converted to a five-year term note on October 1, 2002, after construction of Perryville was completed. For additional information regarding the Perryville financing, see Note 6 - "Debt."

Cleco's consolidated pro forma results, as if the acquisition had occurred on January 1, 2002, are shown below.

The following is the Perryville Balance Sheet as of June 30, 2002, after Midstream purchased Mirant's 50% ownership interest in Perryville.

During a review of an affiliate gas transportation contract, Cleco determined that gas transportation charges billed by a subsidiary of Cleco Energy to Cleco Power may have exceeded the wholesale subsidiary's cost of providing such services to Cleco Power, plus a reasonable rate of return. As such, these transactions have potentially exceeded the pricing standards of the LPSC for affiliate transactions.

Midstream recorded a charge of $6.4 million for these transactions. Additionally, Cleco Power accrued interest expense of $1.4 million for a potential refund to its customers and had discussions with the staff of the LPSC regarding these transactions. In the second half of 2002, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit. The audit commenced in March 2003, pursuant to the Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497, which requires an audit be performed no less frequently than every other year; however, this is the first LPSC fuel adjustment clause audit of Cleco Power. Management is not able to predict the results of the LPSC fuel audit. For additional information about Cleco Power's ongoing LPSC fuel audit, see Note 16 - - "Securities Litigation and Other Commitments and Contingencies."

Cleco Corporation and Cleco Power have agreed to contractual terms that require them to pay third parties if certain triggering events occur. These contractual terms are generally defined as guarantees in FIN 45. Guarantees issued or modified after December 31, 2003, that fall within the initial recognition scope of FIN 45 are required to be recorded as a liability. Outstanding guarantees that fall within the disclosure scope of FIN 45 are required to be disclosed for all accounting periods ending after December 15, 2003. Generally, Cleco's guarantees are not required to be recorded on the balance sheet; however, Cleco Power does have one guarantee recorded on its balance sheet, as described in the following paragraph.

Cleco Power entered into a new pension plan trustee agreement on June 30, 2003, in conjunction with a change of pension plan trustees. A provision of the new pension plan trustee agreement requires Cleco Power to indemnify the new trustee for any damages it has to pay due to past actions of prior trustees. The indemnification does not contain a specific maximum payment amount; however, management has estimated that the probable future payments under this guarantee are approximately $53,000.

In its bylaws, Cleco Corporation has agreed to indemnify directors, officers, and employees who are made a party to a pending or completed suit, arbitration, investigation, or other proceeding whether civil, criminal, or administrative if the basis of inclusion arises as the result of acts conducted in the discharge of their official capacity. Cleco Corporation has purchased various insurance policies to reduce the risks associated with the indemnification. In its Operating Agreement (Operating Agreement of Cleco Power LLC, dated December 13, 2000, amended October 24, 2003), Cleco Power provides for the same indemnifications as described above.

Cleco Corporation issued a guarantee on behalf of Acadia to Acadia's construction contractor. If Acadia cannot pay the contractor that built its plant, Cleco Corporation is obligated to pay 50% of the contractor's current amount outstanding. At December 31, 2003, Cleco Corporation's 50% portion of the contractor's current amount outstanding was approximately $0.2 million. Acadia began commercial operation during the third quarter of 2002, and this guarantee will terminate upon full payment of the Acadia construction contract.

Cleco Corporation has issued guarantees and letters of credit to support the activities of Perryville, Midstream, Evangeline, Cleco Energy, and Marketing & Trading. These commitments are not within the scope of FIN 45, since these are guarantees of performance by wholly owned subsidiaries. For information regarding these commitments, see Note 16 - "Securities Litigation and Other Commitments and Contingencies."

As part of a lignite mining agreement entered into in 2001, Cleco Power and SWEPCO have agreed to pay the lignite miner's loan and lease principal obligations when due if the lignite miner does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered. At December 31, 2003, Cleco Power's 50% exposure was approximately $25.9 million. The lignite mining contract is in place until 2011.

Generally, neither Cleco nor Cleco Power has recourse that would enable them to recover amounts paid under the guarantees. The one exception is the insurance contracts associated with the indemnifications issued to directors, officers, and employees. There are no assets held as collateral or third parties that either Cleco or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees.

SFAS No. 144 requires long-term assets to be reviewed for potential impairment whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Due to such events surrounding several groups of long-lived assets, an analysis of probability-weighted future cash flows under possible scenarios proved the carrying value of certain assets to be greater than the undiscounted future cash flows. Therefore, impairment charges were required to reduce the carrying value to fair value, which was determined by current market indicators of transactions between willing buyers and sellers or the discounted future cash flows from those assets. At December 31, 2002 and 2003, the differences between Cleco's carrying values and its fair values for the impaired long-lived assets were $3.6 million ($2.2 million after tax) and $156.3 million ($96.1 million after tax), respectively. The impaired assets are part of the Midstream reporting segment. These charges are presented in a separate line item in the "Operating Expenses" section of Cleco Corporation's Consolidated Financial Statements.

For the year ended December 31, Cleco incurred asset impairment charges in its companies as follows:

Cleco Energy holds oil and natural gas reserves in Texas. The reserves were purchased in 1998 as a part of the purchase of Sabine Texican Pipeline Co., Inc. and are categorized as proved producing, proved nonproducing, and proved undeveloped reserves. In 2002, Cleco Energy engaged an independent petroleum engineer to compute estimated reserves and future net cash flow analysis of the proved oil and natural gas reserves. The independent petroleum engineer used geologic and financial data provided by Cleco Energy and definitions approved by the Society of Petroleum Engineers, Inc. to analyze the proved reserves. The report provided by the independent petroleum engineer consisted of an estimate of annual oil and natural gas production, an estimate of future prices, and an estimate of future costs. The sum of the undiscounted estimate of net cash flows was lower than the carrying value of the proved oil and gas reserves, which resulted in the determination that the assets were impaired and were required to be written down to their fair market value. The major change in the assumption used in the independent petroleum engineer's report for 2002 as compared to the 2001 assessment was a rise in projected expenses and capital costs required to produce revenue from the proved reserves. The fair value of the proved reserves was determined by using the discounted estimated net future cash flows.

In December 2003, following the loss of Cleco Energy's largest industrial customer and Cleco's decision to focus Cleco's business strategy on core assets; the decision was made to potentially scale down operations and contribute substantially all of the assets to a joint venture or sell substantially all of the assets. Therefore, the carrying value of Cleco Energy's assets was compared to its undiscounted, probability-weighted, future cash flows. The analysis of probability weighting of future cash flows under possible scenarios, as required by SFAS No. 144, changed due to the decision to scale down operations. As a result of the change in probability weighting of Cleco Energy's undiscounted future cash flows, management believes that the carrying value of Cleco Energy's long-lived assets is impaired; therefore, the carrying value of these assets was reduced to fair value.

Perryville owns and operates a 718-MW natural gas-fired power plant near Perryville, Louisiana. The Perryville facility consists of approximately 562 MW of combined-cycle capacity and approximately 156 MW of peaking capacity. In July 2001, Perryville entered into the Perryville Tolling Agreement, a 21-year capacity and energy agreement for Perryville's entire capacity with MAEM, a subsidiary of Mirant. Prior to the July 14, 2003, filing by the Mirant Debtors for voluntary protection under Chapter 11 of the U.S. Bankruptcy Code, the carrying value of the Perryville facility was compared to its undiscounted, probability-weighted, future cash flows. Due to the Mirant Debtors' bankruptcy and subsequent rejection of the Perryville Tolling Agreement, the difference between Perryville's carrying value and its fair value as determined by current market indicators of transactions between willing buyers and sellers resulted in an impairment charge of $134.8 million ($82.9 million after tax) in the second quarter of 2003. On December 31, 2003, based on continuing negotiations to sell the Perryville facility and the subsequent signing of a sale agreement, the carrying value of the Perryville facility was further reduced to the agreed upon sale price. At December 31, 2003, the difference between Perryville's carrying value and the anticipated sale proceeds resulted in an additional impairment charge of $13.2 million ($8.1 million after tax). For additional information regarding Perryville, the Mirant Debtors' bankruptcy, and damage claims, see Note 27 - "Perryville." For information on the sale agreement, see Note 30 - "Subsequent Events - Perryville."

On July 25, 2003, the FERC issued an order approving a Consent Agreement between the FERC Staff and Cleco that settled the FERC investigation that commenced after Cleco's disclosure in November 2002 of certain energy marketing and trading practices. By its terms, the Consent Agreement was effective on August 24, 2003 (the Effective Date). As a part of the settlement, Cleco agreed to the following penalties and remedies.

Cleco has substantially completed the items that were stipulated in the FERC Consent Agreement and required to be complied with to date. On October 23, 2003, the FERC granted an extension of time to comply with the requirement of the Consent Agreement, regarding the separation of Cleco Power's trading floors, as referred to above. On January 3, 2004, Cleco Power separated its trading floors within the extended timeframe. Additional requirements will be due on future dates and are expected to be satisfied based on the guidelines set forth in the Consent Agreement. On October 17, 2003, Marketing & Trading notified the FERC of its termination of all contractual obligations. In addition, the civil penalty required to be paid to FERC and refunds to Cleco Power were made during the third quarter of 2003. Cleco Power will refund approximately $1.2 million to customers through fuel cost adjustments over a 12-month period that began in August 2003. Cleco expects to work with the LPSC in the coming months to determine the appropriate regulatory treatment for any remaining funds.

Effective July 1, 1999, Cleco Power entered into service agreements with affiliates that provide Cleco Power access to professional services and goods. The services and goods are charged to Cleco Power at management's estimate of fair market value or fully loaded cost, with the exception of Support Group, which charges only fully loaded cost in order to comply with Cleco's affiliate policy. Cleco Power reviewed certain transactions between Cleco Power and certain Midstream companies. These transactions have potentially exceeded the pricing standards of the LPSC. For additional information on these transactions, see Note 19 - "Review of Trading Activities" and Note 22 - "Gas Transportation Charge." In June 2003, CLE Intrastate transferred its natural gas interconnections at Rodemacher and Teche power stations with Trunkline Gas Company, Louisiana Intrastate Pipeline Company, and ANR Pipeline Company to Cleco Power. The pipeline interconnections allow Cleco Power to access various additional natural gas supply markets, which helps to maintain a more economical fuel supply for Cleco Power's customers.

A summary of charges from each affiliate included in the Statements of Income of Cleco Power follows:

		For the year ended December 31,
		2003	2002	2001
		(Thousands)
Cleco Corporation
	Other operations	$ 45	$ 49	$ 163
Support Group
	Other operations	24,474	21,315	28,274
	Maintenance	4,042	1,295	87
	Restructuring charge	(96)	1,079	-
	Taxes other than income taxes	87	-	-
	Other income and deductions	571	434	8
Midstream
	Other operations	8	984	1,202
	Restructuring charge	-	84	-
Evangeline
	Fuel and power purchased	(111)	-	-
	Other operations	(36)	-	613
	Maintenance	-	3	-
	Other income and deductions	5	-	-
Marketing & Trading
	Fuel and power purchased	(1,070)	-	100
	Other operations	(2)	934	4,369
	Restructuring charge	-	67	-
Generation Services
	Other operations	50	654	666
	Maintenance	9	1,537	1,822
	Restructuring charge	-	84	-
Cleco Energy
	Fuel and power purchased	100	(5,151)	2,093
	Other operations	1	24	-
APH
	Other operations	-	-	2
Diversified Lands LLC
	Other income and deductions	49	-	-
Perryville
	Other operations	(2)	-	-
	Other income and deductions	13	-	-
UTS
	Other operations	-	-	306
	Maintenance	-	-	3

Cleco Power also entered into agreements to provide goods and services to affiliated companies. The goods and services are charged by Cleco Power at fully loaded cost or management's estimate of fair market value, whichever is higher, in order to comply with Cleco's affiliate policy. Following is a reconciliation of Cleco Power's affiliate revenue:

Cleco Power had the following affiliate receivable and payable balances associated with the service agreements between Cleco Power and its affiliates:

			At December 31,
			2003				2002
		Accounts		Accounts		Accounts		Accounts
		Receivable		Payable		Receivable		Payable
			(Thousands)
Cleco Corporation		$	15,536	$	20,224	$	260	$	1,456
Support Group			1,185		4,318		721		6,032
Midstream			14		21		32		56
Evangeline			5		1		101		-
Marketing & Trading			21		10		95		1,044
Generation Services			99		9		90		267
Cleco Energy			49		2		3		31
Diversified Lands LLC			24		-		811		-
CLE Intrastate			-		-		7,058		52
Perryville			11		-		-		-
Others			108		109		125		188
	Total	$	17,052	$	24,694	$	9,296	$	9,126

For the years ended December 31, 2003 and 2002, Cleco Power paid cash dividends to Cleco Corporation of approximately $44.4 million and $51.3 million, respectively.

Affiliates that participate in the defined benefit pension plan sponsored by Cleco Power transfer their liability and an equal amount of cash on a periodic basis to Cleco Power. The table below shows the amounts transferred by affiliates during 2003 and 2002:

payments from MAEM, Perryville was entitled to collect and MAEM was obligated to pay amounts associated with variable operating and maintenance expenses based on MAEM's dispatch of the facility. Payments received from MAEM under the Perryville Tolling Agreement were, at the time, Perryville's only source of revenue. Mirant and MAI provided limited guarantees that supported MAEM's obligations under the Perryville Tolling Agreement.

On July 14, 2003, the Mirant Debtors filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas. Under the terms of the Perryville Tolling Agreement, Perryville invoiced MAEM for $4.5 million of tolling revenue and $1.8 million of long-term service agreement reimbursement for June 2003 tolling services. Perryville recorded a reserve for uncollectible accounts of $6.3 million at June 30, 2003, and a $2.3 million reserve at September 30, 2003, as a result of MAEM's failure to remit pre-petition amounts that were due on July 21, 2003, and August 21, 2003, respectively. Perryville invoiced MAEM for $5.0 million and $2.0 million of tolling revenue for August and September post-petition tolling services, respectively, prior to MAEM's rejection of the Perryville Tolling Agreement as described below. Perryville recorded a reserve for uncollectible accounts of $5.3 million at September 30, 2003, and $1.8 million at December 31, 2003, for a portion of August and September activity. These charges, collectively $15.7 million, are included in the "Operating Expenses" section of the Financial Statements. No amounts due to or from Mirant have been netted by Perryville under the Perryville Tolling Agreement.

On August 29, 2003, the Mirant Debtors filed a motion with the U.S. Bankruptcy Court pursuant to section 365 of the U.S. Bankruptcy Code seeking authority to reject the Perryville Tolling Agreement. The Mirant Debtors have asserted that the Perryville Tolling Agreement was rejected as of September 15, 2003. Upon the rejection of the Perryville Tolling Agreement, MAEM's rights and obligations under such agreement were terminated. In connection with the rejection of the Perryville Tolling Agreement, Perryville has asserted in excess of $1.0 billion in damage claims against the Mirant Debtors in their bankruptcy cases. For information on the impairment of Perryville's long-lived assets, see Note 24 - "Impairments of Long-Lived Assets."

The bankruptcy filing by the Mirant Debtors resulted in an event of default under Perryville's Senior Loan Agreement. This event of default gave the lenders holding an aggregate of at least 66-2/3% of the outstanding senior loan the right, but not the obligation, to declare immediately due and payable any outstanding principal and interest, which at December 31, 2003, was $133.0 million. Accordingly, Perryville's Senior Loan Agreement debt is considered short-term and is classified in the current liabilities section of the balance sheet. As required under the Senior Loan Agreement, Perryville gave timely notice of the event of default to KBC, the agent bank. At December 31, 2003, remedies available to the lenders during the existence of an event of default included foreclosure on PEH's membership interest in Perryville, as well as on Perryville's assets, including without limitation, cash in any restricted accounts related to the Senior Loan Agreement. Perryville's Senior Loan Agreement is nonrecourse to Cleco Corporation other than (i) a guarantee of the current year's debt service requirement, which at December 31, 2003, was $7.3 million and (ii) a possible conditional guarantee described below in "- Perryville's Subordinated Loan Agreement." The default should have no impact on any other credit facility or financing arrangement of Cleco Corporation or its other subsidiaries.

On January 28, 2004, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The outstanding amounts due under the Senior Loan Agreement were deemed accelerated upon the bankruptcy filings by Perryville and PEH. As a result of the commencement of such bankruptcy cases and by virtue of the automatic stay under the U.S. Bankruptcy Code, the lenders' ability to exercise their remedies under the Senior Loan Agreement, including, but not limited to, their ability to foreclose on the mortgage or assume ownership of the Perryville facility, are significantly limited and would require approval of the Bankruptcy Court. For additional information on the bankruptcy filings, see Note 30 - "Subsequent Events - Perryville."

As a result of the Mirant Debtors' bankruptcy and MAEM's failure to make payments under the Perryville Tolling Agreement, all obligations of Perryville to make principal and interest payments under the Subordinated Loan Agreement, as well as the accrual of additional interest, have been indefinitely suspended. As of December 31, 2003, the amount outstanding under the Subordinated Loan Agreement was $98.7 million.

To the extent there are obligations owed by Perryville to MAI under the Subordinated Loan Agreement, Perryville may (subject to the provisions of the U.S. Bankruptcy Code), but is not required to, elect to exercise a right of set off of any amounts due under the Subordinated Loan Agreement against Perryville's damage claims against MAI's limited guarantee in support of MAEM's obligations. MAI has waived any such right of set off. Pursuant to the Senior Loan Agreement, in connection with Perryville exercising a right of set off and receiving cash distributions, Perryville would be obligated to prepay its obligations under the Senior Loan Agreement in an amount equal to the present value of all recoveries that otherwise would be payable to Perryville by the Mirant Debtors with respect to the amount of set off under any plans of bankruptcy proceedings for the Mirant Debtors or scheduled distributions to creditors involving the Mirant Debtors were the right of set off not invoked. In such event and prior to receiving cash distributions, Perryville also would be required to cause Cleco Corporation to provide credit support in the form of a guarantee of Perryville's prepayment obligation in an amount equal to 50% of the amount to be set off, not to exceed $50.0 million. This credit support must be provided in the form of a letter of credit if Cleco Corporation does not have or maintain an

investment grade credit rating while the obligation is outstanding. Failure by Cleco Corporation to provide the credit support could trigger a power of attorney empowering the lenders to waive Perryville's right of set off. To the extent that Perryville waives its right of set off and set off is nevertheless effectuated, despite Perryville's and MAI's waiver of their rights of set off, Perryville is required to prepay to its lenders an amount equal to 25% of any amount set off. The extent to which Perryville and the Mirant Debtors can exercise any setoff right which they may have under the relevant documents or otherwise is subject to the U.S. Bankruptcy Code and Bankruptcy Court approval.

On January 28, 2004, Perryville reached an agreement to sell, subject to the Bankruptcy Court approval, its 718-MW power plant to Entergy Louisiana, Inc. For information on the pending sale of the Perryville facility, see Note 30 - "Subsequent Events - Perryville."

Facility Operation Subsequent to MAEM's Rejection of the Perryville Tolling Agreement

In December 2003, Perryville recorded tolling revenue of $0.6 million for energy sold during the month. On January 28, 2004, Perryville and Entergy Services, Inc. entered into a power purchase agreement (the "Power Purchase Agreement"), under which Entergy Services, Inc. has exclusive rights to the output of the Perryville facility for a limited time period. The Power Purchase Agreement was approved by the Bankruptcy Court and the LPSC, and became effective on February 17, 2004. For information about the Power Purchase Agreement, see Note 30 - "Subsequent Events - Perryville."

Prior to the July 14, 2003, bankruptcy filing by the Mirant Debtors, the carrying value of the Perryville facility was compared to its undiscounted, probability-weighted, future cash flows. Due to the Mirant Debtors' bankruptcy and subsequent rejection of the Perryville Tolling Agreement, the difference between Perryville's carrying value and its fair value as determined by current market indicators of transactions between willing buyers and sellers resulted in an impairment charge of $134.8 million ($82.9 million after tax) in the second quarter of 2003. On December 31, 2003, based on continuing negotiations to sell the Perryville facility and the subsequent signing of a sale agreement, the carrying value of the Perryville facility was further reduced to the agreed upon sale price. At December 31, 2003, the difference between Perryville's carrying value and its fair value resulted in an additional impairment charge of $13.2 million ($8.1 million after tax). For additional information regarding Perryville's impairment, see Note 24 - "Impairments of Long-Lived Assets."

On December 3, 2003, Perryville filed a motion in the Mirant Debtors' bankruptcy cases seeking allowance and immediate payment of an administrative expense claim in the amount of approximately $7.2 million. This administrative expense claim arises out of post-petition services performed by Perryville under the Perryville Tolling Agreement prior to its rejection by MAEM. Currently, there is no hearing date scheduled with respect to this claim and Perryville's motion is still pending before the bankruptcy court.

On December 15, 2003, Perryville filed damage claims against MAEM due to the rejection of the Perryville Tolling Agreement and against Mirant and MAI under their respective limited guarantees. The rejection damage claims are in excess of $1.0 billion against MAEM, $98.7 million against MAI, and $177.2 million against Mirant under its limited guaranty.

Cleco has recorded an asset retirement obligation (liability) in accordance with SFAS No. 143 that became effective on January 1, 2003. SFAS No. 143 requires an entity to record an asset retirement obligation when there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. Cleco Power determined that a liability exists for cleanup and closing costs of solid waste facilities associated with its power stations that use lignite and coal for fuel. Due to the indeterminate life of the power station using coal, an asset retirement obligation was not recorded. However, Cleco Power was able to reasonably estimate the obligation associated with the power station using lignite as fuel, based on the amount of lignite reserves available to fuel the station, and recorded an asset retirement obligation for the related cleanup and closure costs. At December 31, 2003, this liability is estimated at $0.3 million and is included in other deferred credits. Due to an absence of contractual, regulatory, or other legally enforceable requirements to incur costs to retire assets, Midstream did not record an asset retirement obligation.

At the point the liability for asset retirement is incurred, SFAS No. 143 requires capitalization of the costs to the related asset, property, plant and equipment, net. For asset retirement obligations existing at the time of adoption, the statement requires capitalization of costs at the level that existed at the point of incurring the liability. These capitalized costs are depreciated over the same period as the related property. At the date of adoption, the depreciation expense for past periods was recorded as a regulatory asset in accordance with SFAS No. 71 because Cleco Power believes the LPSC will allow it to recover these costs in future rates. Current depreciation of the asset retirement cost is also being deferred as a regulatory asset under SFAS No. 71.

The initial liability is accreted to its present value each period. Cleco Power defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers.

Prior to the adoption of SFAS No. 143, Cleco Power did not recover in rates any allowances for closure costs for any assets in use or retired and has not recognized any additional depreciation or utilized depreciation rates that included a negative salvage component.

If SFAS No. 143 had been in effect in 2002, there would have been no impact on earnings per share for the year ended December 31, 2002, net of income tax effect. Since a change in earnings per share would not have occurred, pro forma earnings per share disclosures are not presented.

The table below discloses the pro forma asset retirement obligation during the twelve months ended December 31, 2002 for Cleco Power as if SFAS No. 143 had been effective 2002.

The following table shows costs as of January 1, 2003, and changes to the asset retirement obligation and accumulated depreciation during the twelve months ended December 31, 2003.

As of December 31, 2003, Cleco Power's regulatory asset, included in other deferred charges, is the total accumulated accretion of $234,000 and accumulated depreciation of $31,000 for a total of $265,000.

Quarterly information for Cleco for 2003 and 2002 is shown in the following table. The sum of the 2002 quarterly diluted net income per common share does not equal the year-end diluted net income per common share, as shown on the Consolidated Statements of Operations, due to the weighted-average dilutive effect of 2.0 million common shares issued on May 8, 2002.

		2003
		(Thousands, except per share amounts)
		1^st	2^nd	3^rd	4^th
		Quarter	Quarter	Quarter	Quarter
Operating revenue		$ 187,449	$ 218,036	$ 276,628	$ 192,524
Operating income (loss)		$ 35,150	$ (95,848)	$ 48,184	$ (6,126)
Net income (loss) applicable to common stock		$ 17,336	$ (66,858)	$ 23,342	$ (10,610)
Basic net income (loss) per average common share		$ 0.37	$ (1.42)	$ 0.49	$ (0.23)
Diluted net income (loss) per average common share		$ 0.36	$ (1.42)	$ 0.48	$ (0.23)
Dividends paid per common share		$ 0.225	$ 0.225	$ 0.225	$ 0.225
Closing market price per share
	High	$ 15.09	$ 17.66	$ 17.18	$ 18.29
	Low	$ 10.64	$ 12.23	$ 14.88	$ 15.86

		2002
		(Thousands, except per share amounts)
		1^st	2^nd	3^rd	4^th
		Quarter	Quarter	Quarter	Quarter
Operating revenue as previously reported		$ 220,264	$ 370,624	$ 224,589	$ 173,715
Adjustments:
	Adjustments due to EITF 02-3	(70,588)	196,482	-	-
	Other	-	-	(898)	-
Operating revenue adjusted		$ 149,676	$ 174,142	$ 223,691	$ 173,715
Operating income		$ 33,070	$ 38,729	$ 66,390	$ 18,807
Net income applicable to common stock		$ 13,581	$ 17,317	$ 36,392	$ 2,713
Basic net income per average common share		$ 0.30	$ 0.38	$ 0.77	$ 0.06
Diluted net income per average common share		$ 0.29	$ 0.36	$ 0.74	$ 0.06
Dividends paid per common share		$ 0.220	$ 0.225	$ 0.225	$ 0.225
Closing market price per share
	High	$ 22.94	$ 23.78	$ 21.43	$ 15.87
	Low	$ 19.90	$ 20.58	$ 11.67	$ 9.58

Cleco Corporation's common stock is listed for trading on the New York and Pacific stock exchanges under the ticker symbol "CNL." Cleco Corporation's preferred stock is not listed on any stock exchange. On December 31, 2003, Cleco had 8,693 common shareholders and 100 preferred shareholders, as determined from the records of the transfer agent.

On January 23, 2004, Cleco Corporation's Board of Directors declared a quarterly dividend of $0.225 per share payable February 15, 2004, to common shareholders of record on February 2, 2004. Preferred dividends also were declared payable March 1, 2004, to preferred shareholders of record on February 15, 2004.

Quarterly information for Cleco Power for 2003 and 2002 is shown in the following table.

		2003
		(Thousands, except per share amounts)
		1^st	2^nd	3^rd	4^th
		Quarter	Quarter	Quarter	Quarter
Operating revenue		$ 145,503	$ 172,131	$ 225,045	$ 164,609
Operating income		$ 28,651	$ 31,946	$ 29,488	$ 24,528
Net income applicable to member's equity		$ 15,937	$ 15,253	$ 13,909	$ 11,909
Distributions or dividends paid to Cleco		$ 14.6	$ 15.9	$ -	$ 13.9

		2002
		(Thousands, except per share amounts)
		1^st	2^nd	3^rd	4^th
		Quarter	Quarter	Quarter	Quarter
Operating revenue as previously reported		$ 129,283	$ 153,186	$ 178,352	$ 140,315
Adjustments:
	Adjustments due to EITF No. 02-3	$ (916)	$ (4,731)	$ -	$ -
Operating revenue adjusted		$ 128,367	$ 148,455	$ 178,352	$ 140,315
Operating income		$ 28,246	$ 31,106	$ 35,585	$ 22,692
Net income applicable to member's equity		$ 14,097	$ 15,381	$ 19,719	$ 10,377
Distributions or dividends paid to Cleco		$ 16.9	$ 14.1	$ -	$ 20.3

On January 28, 2004, Perryville reached an agreement (the "Sale Agreement") to sell its 718-MW power plant to Entergy Louisiana, Inc. ("ELI") and also entered into a power purchase agreement (the "Power Purchase Agreement") with Entergy Services, Inc. ("ESI") to purchase the output of the Perryville facility until the earlier to occur of (i) the closing date of the sale to ELI or (ii) December 31, 2004. The Sale Agreement, which is subject to the Bankruptcy Court approval, provides for conditions customary to closing, including requisite regulatory approvals, as well as other covenants, representations, and warranties. If certain conditions to closing are not satisfied or waived on or before September 30, 2005, the Sale Agreement may be terminated. Cleco Corporation provided a limited guaranty to ELI for Perryville's performance obligations under the Sale Agreement, the Power Purchase Agreement and other ancillary agreements related to the sale.

On January 28, 2004, to facilitate an orderly sales process, Perryville and PEH filed voluntary petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. Neither Cleco Corporation nor any of its other subsidiaries were included in the filings. Perryville and PEH are debtors and debtors in possession, and are continuing to operate their business under the U.S. Bankruptcy Code. Based upon the Bankruptcy Court's approval, Perryville and PEH will use existing cash sourced from restricted cash accounts held in the debtor in possession accounts (the "DIP Accounts") and operating revenue from the Power Purchase Agreement to maintain operations at the Perryville facility. On February 3, 2004, the Bankruptcy Court approved the use by Perryville and PEH, on an interim basis, of approximately $0.6 million of cash collateral in the restricted cash accounts ("Cash Collateral") to maintain and operate their business, provide the lenders adequate protection, and reimburse the lenders for certain expenses incurred through February 12, 2004.

On February 26, 2004, the Bankruptcy Court entered a final cash collateral order (the "Cash Collateral Order"). The Cash Collateral Order provided for the transfer of up to $6.1 million (subject to certain adjustments) of additional restricted cash to the DIP Accounts for post-petition expenses, including routine operations and maintenance, inventory, goods and services, costs reasonably necessary to obtain regulatory approval and other necessary approvals in connection with the Power Purchase Agreement and Sale Agreement, adequate protection payments, professional fees and expenses, and certain pre-petition expenses of the lenders for professional services. Revenue from the Power Purchase Agreement also will be deposited into the DIP Accounts to provide additional cash for Perryville's use. The Cash Collateral Order stipulated payment of quarterly interest and principal payments under the Senior Loan Agreement, set forth early termination events, and also granted a replacement lien to the lenders. In the event that Perryville cannot pay its quarterly principal payments, Cleco Corporation, if demanded by Perryville, is obligated under its guarantee to pay up to $7.4 million of these payments. The Cash Collateral Order also stipulated that the lenders should not take any action to delay the closing of the Sale Agreement, shall support the Sale Agreement, and shall refrain from seeking relief of the automatic stay under the U.S. Bankruptcy Code for so long as the order is in effect. Subject to the occurrence of the early termination events set forth therein, the Cash Collateral Order terminates on the earlier of September 30, 2005 and payment by Perryville of all amounts (other than the amount of default interest waived under the Cash Collateral Order) due and payable under the Senior Loan Agreement.

Pursuant to the terms of the Sale Agreement, Perryville has agreed to sell its operating assets and property to ELI for $170.0 million (subject to certain adjustments). The assets to be sold to ELI do not include Perryville's claims against the Mirant Debtors or any other cash-related assets of Perryville. It is anticipated that the proceeds from the sale to ELI will be sufficient to repay the Senior Loan Agreement and all current obligations of Perryville and PEH. The sale to ELI, which is expected to be completed by December 2004, is contingent upon obtaining necessary approvals from the FERC, the LPSC, the SEC and the Bankruptcy Court; a final inspection by ELI and its ability to recover all of its costs in acquiring the Perryville power plant through base rates, fuel adjustment charges or other such rates or regulatory treatment as deemed solely acceptable to ELI; and satisfaction of other customary closing conditions. On January 29, 2004, Perryville and PEH filed a motion seeking approval of certain bidding procedures for solicitation of higher or better offers for the Perryville assets pursuant to a sale under section 363 of the U.S. Bankruptcy Code. This motion is scheduled to be heard by the Bankruptcy Court in early March 2004. If certain milestones related to the bankruptcy proceedings and items set forth in the Sale

Agreement are not met, ELI will have the right to terminate the sale transaction, and would be entitled to liquidated damages from Perryville ranging between $5.0 million and $10.0 million. These potential liquidated damage obligations have been guaranteed by Cleco Corporation, in the event that they are not paid by Perryville.

Also, on January 28, 2004, ESI signed a Power Purchase Agreement to purchase the output of the Perryville plant through the earlier to occur of (i) the closing of the sale to ELI or (ii) December 31, 2004. ESI has the option to extend the Power Purchase Agreement through September 30, 2005; however, the Power Purchase Agreement automatically terminates upon termination of the Sale Agreement. The Power Purchase Agreement provides that ESI will supply natural gas to the Perryville facility and is exclusively entitled to all capacity and energy output from the facility. Under the Power Purchase Agreement, Perryville is obligated to provide energy conversion services, with specified performance parameters, when requested by ESI. Existing personnel will continue to operate the facility through the closing of the sale to ELI. Perryville received necessary approvals of the Power Purchase Agreement from the LPSC and the Bankruptcy Court and began operating under the agreement on February 17, 2004. Based on the terms of the Power Purchase Agreement, Perryville is anticipated to receive payments sufficient for Perryville and PEH to maintain their operations.

Perryville's and PEH's financial results are included in Cleco Corporation's consolidated results at December 31, 2003. However, generally accepted accounting principles specifically require that any entity, whose financial statements were previously consolidated with those of its parent, that files for protection under the U.S. Bankruptcy Code, whether solvent or insolvent, must be prospectively deconsolidated from the parent and presented on the cost method. The cost method will require Cleco Corporation to present the net assets of Perryville and PEH at January 28, 2004, as an investment and not recognize any income or loss from Perryville or PEH in Cleco's results of operations during the reorganization period. This investment has a negative cost basis of approximately $8.1 million as of January 28, 2004, and will be subject to periodic reviews for recoverability. When Perryville emerges from its bankruptcy proceedings, the subsequent accounting will be determined based upon the applicable facts and circumstances existing at such time, including the terms of any plan of reorganization or liquidation.

Cleco Corporation has assessed Perryville's and PEH's liquidity position as a result of the bankruptcy filing and anticipates that Perryville can continue to fund its operating activities and capital requirements for the foreseeable future. However, the ability of Perryville to continue as a going concern is dependent upon its ability to complete the sale of its facility to ELI. As a result of the bankruptcy filings and related events, there are no assurances that the carrying value of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded.

Perryville and PEH routinely engage in affiliate transactions with other entities within Cleco in the ordinary course of business. As a result of its bankruptcy filings, Perryville and PEH are precluded from paying dividends to equity holders and making payments on any pre-bankruptcy filing accounts or notes payable that are due and owing to any other entity within Cleco (the "Pre-Petition Affiliate Payables") and other creditors during the pendency of the bankruptcy case. As of December 31, 2003, Perryville and PEH had Pre-Petition Affiliate Payables to other entities of Cleco in the aggregate amount of approximately $3.5 million.

In 2003, Cleco Power issued a RFP for up to 750 MW of generation supply to replace existing power purchase agreements with Williams Energy and Dynegy that expire in 2004 and 2005. There were no winning proposals selected from the RFP, but on January 30, 2004, Cleco Power agreed to terms for a one-year contract to purchase 500 MW of capacity from CES starting in January 2005. Cleco Power anticipates that this contract will be executed by late March 2004 and expects that the 500 MW from CES will fill the shortfall left by the Williams Energy and Dynegy contracts expiring at the end of 2004; however, Cleco Power continues to evaluate meeting capacity requirements through its IRP team and plans to issue a new RFP in mid-2004. The contract with CES is subject to certification approval by the LPSC, which approval is expected to be obtained in mid-2004.

In February 2004, Cleco Power filed a notice of intent to issue a new RFP with the LPSC. The RFP informational filing is expected to be made during the second quarter of 2004. Thereafter, Cleco Power will work with the LPSC to determine the final RFP process and schedule.

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

          None.

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, the Registrants' management has evaluated, as of the end of the period covered by this Report, with the participation of the Registrants' chief executive officer and chief financial officer, the effectiveness of the Registrants' disclosure controls and procedures as defined by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Disclosure Controls). Based on that evaluation, such officers concluded that the Registrants' Disclosure Controls were effective as of the date of that evaluation.

During the Registrants' fourth fiscal quarter, there have been no changes to the Registrants' internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Registrants' internal control over financial reporting.

Disclosure Controls are controls and procedures that are designed to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure Controls include, without limitation, controls and procedures designed to ensure that such information is accumulated and communicated to the Registrants' management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

The Registrants' management, including the chief executive officer and chief financial officer, does not expect that their Disclosure Controls will prevent all errors and all fraud. A control system, including the Registrants' Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Cleco's board of directors has determined that Mr. W. Larry Westbrook, who serves as the Chairman of the Audit Committee of the Board of Directors, fulfills the requirements for an independent, audit committee financial expert for both Cleco Corporation and Cleco Power.

Cleco Corporation and Cleco Power have adopted a code of conduct that applies to their principal executive officer, principal financial officer, principal accounting officer and all persons performing similar functions. This code of conduct is posted on Cleco's homepage on the Internet's World Wide Web located at http://www.cleco.com. This code of conduct is also available free of charge by requests sent to: Shareholder Services, Cleco at P.O. Box 5000, Pineville LA 71361-5000.

Cleco

The information set forth, (i) under the caption "Proposal - Election of Four Class I Directors" and (ii) under the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's Proxy Statement dated March 18, 2004 relating to the Annual Meeting of Shareholders to be held on April 23, 2004, filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 (2004 Proxy Statement), is incorporated herein by reference. See also "Part I - Executive Officers of the Registrants."

The information called for by Item 10 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

The information set forth, (i) under the subcaptions "Organization and Independence of the Board of Directors" and "Compensation of the Board of Directors" under the caption "Proposal - Election of Four Class I Directors" and (ii) under the caption "Executive Compensation" in the 2004 Proxy Statement (excluding the information required by paragraphs (k) and (l) of Item 402 of Regulation S-K) is incorporated herein by reference.

The information called for by Item 11 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information set forth, (i) under the caption "Security Ownership of Directors and Management" and (ii) under the caption "Security Ownership of Certain Beneficial Owners" in the 2004 Proxy Statement is incorporated herein by reference.

Cleco has compensation plans under which equity securities of Cleco Corporation are authorized for issuance as approved by security holders. Cleco does not have such plans that have not been approved by security holders. The table below provides information about compensation plans under which equity securities of Cleco Corporation are authorized for issuance at December 31, 2003.

Plan Category			Number of securities to be issued upon exercise of outstanding options, warrants or rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

			(a)	(b)	(c)
Equity compensation plans approved by security holders
Employee Stock Purchase Plan........................................................................			7,903	$14.025	549,867 (1)
Long-term incentive compensation plans......................................................			1,268,197	$19.923	653,123 (2)
Total..........................................................................................................................			1,276,100	$19.886	1,202,990

	(1)	The number of options in column (a) for the Employee Stock Purchase Plan represents the number of options granted at December 31, 2003, based on employee withholdings and the option grant calculation under the plan.
	(2)	Stock options and restricted stock can be issued pursuant to the 2000 LTICP. This plan requires the number of securities available to be issued to be reduced by the number of options and the number of restricted shares previously awarded, net of forfeitures. At December 31, 2003, there were 376,347 shares of restricted stock awarded, net of forfeitures, pursuant to the 2000 LTICP. New options or restricted stock cannot be issued pursuant to the 1990 LTICP, which expired in December 1999. However, stock options issued prior to December 1999 under the 1990 LTICP remain outstanding until they expire.

For additional information on compensation plans using equity securities, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 7 - Common Stock." This information should be read in conjunction with the Consolidated Financial Statements and related Notes thereto.

The information called for by Item 12 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

The information set forth under the caption "Proposal - Election of Four Class I Directors - Interests of the Board of Directors" in the 2004 Proxy Statement is incorporated herein by reference.

The information called for by Item 13 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Cleco

The information set forth under "Report of the Audit Committee - Principal Accountant Fees and Services" regarding fees paid to Cleco's independent auditors in the 2004 Proxy Statement is incorporated herein by reference.

Cleco Power

Aggregate fees for professional services rendered for Cleco Power by PricewaterhouseCoopers LLP as of or for the years ended December 31, 2003 and 2002 were as follows:

The Audit fees for 2003 and 2002 were for professional services rendered for the audits of Cleco Power's financial statements; the review of those financial statements included in Cleco Power's quarterly reports on Form 10-Q; issuance of comfort letters; a security review of new financial software; and assistance with review of documents filed with the SEC.

The Audit Related fees billed during 2003 and 2002 were for assurance and other services related to employee benefit plan audits.

Tax fees billed during 2003 and 2002 were for services related to tax compliance reviews, and tax planning and tax advice, including assistance with and representation in tax audits and appeals; tax services for employee benefit plans; and requests for rulings or technical advice from tax authorities.

  All Other fees billed during 2002 were for services rendered for financial information systems implementation and design.

          Based on the review and discussions referred to above, the Audit Committee approved the inclusion of Cleco Power's audited financial statements in this Report.

The Audit Committee of Cleco Power's board of managers has established a policy requiring its pre-approval of all audit and non-audit services provided by its independent auditors. The policy requires the general pre-approval of annual audit services and specific pre-approval of all other permitted services. In determining whether to pre-approve permitted services, the Audit Committee considers whether such services are consistent with SEC rules and regulations. Furthermore, requests for pre-approval for services that are eligible for general pre-approval must be detailed as to the services to be provided.

None of the audit and non-audit services described above were approved by the Audit Committee pursuant to the waiver of pre-approval provisions set forth in applicable rules of the SEC.

		Form 10-K Annual Report
	Report of Independent Auditors	55
15(a)(1)	Consolidated Statements of Operations for the years ended December 31, 2003, 2002, and 2001	56
	Consolidated Balance Sheets at December 31, 2003 and 2002	57
	Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001	58
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002, and 2001	59
	Consolidated Statements of Changes in Common Shareholders' Equity for the years ended December 31, 2003, 2002, and 2001	60
	Notes to the Financial Statements	67
	Report of Independent Auditors	61
	Financial Statements of Cleco Power
	Cleco Power Statements of Income for the years ended December 31, 2003, 2002, and 2001	62
	Cleco Power Balance Sheets at December 31, 2003 and 2002	63
	Cleco Power Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001	64
	Cleco Power Statements of Comprehensive Income for the years ended December 31, 2003, 2002, and 2001	65
	Cleco Power Statements of Changes in Common Shareholders' Equity and Member's Equity for the years ended December 31, 2003, 2002, and 2001	65
15(a)(2)	Financial Statement Schedules
	Schedule I - Financial Statements of Cleco Corporation
	Condensed Statements of Operations for the years ended December 31, 2003, 2002, and 2001	111
	Condensed Balance Sheets at December 31, 2003 and 2002	112
	Condensed Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001	113
	Condensed Statement of Changes in Common Shareholders' Equity for the years ended December 31, 2003, 2002, and 2001	114
	Notes to the Condensed Financial Statements	115
	Schedule II - Valuation and Qualifying Accounts
	Cleco Corporation	116
	Cleco Power	116
	Financial Statement Schedules other than those shown in the above index are omitted because they are either not required or are not applicable or the required information is shown in the Consolidated Financial Statements and Notes thereto.
15(a)(3)	List of Exhibits	107

The Exhibits designated by an asterisk are filed herewith. The Exhibits not so designated have been previously filed with the SEC and are incorporated herein by reference. The Exhibits designated by two asterisks are management contracts and compensatory plans and arrangements required to be filed as Exhibits to this Report.

				For the year ended December 31,
				2003		2002		2001
				(Thousands)
Operating revenue
	Equity (loss) income of subsidiaries		$	(29,715)	$	74,209	$	74,152
	Subsidiary revenue			-		-		62
	Other income			14,117		13,183		10,859
		Total operating (loss) revenue		(15,598)		87,392		85,073

Expenses and other deductions
	Administrative and general			3,666		3,093		1,716
	Taxes other than income taxes			334		415		1,029
	Subsidiary costs			924		982		-
	Income tax benefit			(2,938)		(2,371)		(1,992)
	Interest			17,345		13,398		12,047
		Expenses and other deductions		19,331		15,517		12,800

(Loss) income from continuing operations
	before preferred dividends			(34,929)		71,875		72,273

Discontinued operations
	Loss on disposal of segment, net of income taxes			-		-		(2,035)
		Total discontinued operations		-		-		(2,035)

(Loss) income before preferred dividends				(34,929)		71,875		70,238
Preferred dividend requirements, net				1,861		1,872		1,876

Net (loss) income			$	(36,790)	$	70,003	$	68,362

The accompanying notes are an integral part of the condensed financial statements.

						At December 31,
						2003		2002
						(Thousands)
Assets
	Current assets
		Cash and cash equivalents			$	24,220	$	44,971
		Receivable from subsidiaries				37,593		27,079
		Notes receivable from subsidiaries				238,252		278,610
		Taxes receivable				34,611		1,304
		Other current assets				7,040		3,458
	Total current assets					341,716		355,422

	Investment in subsidiaries					486,243		524,815
	Other assets					2,116		2,562
	Deferred charges					4,760		1,895
		Total assets			$	834,835	$	884,694

Liabilities and shareholders' equity
	Current liabilities
		Short-term debt			$	50,000	$	171,550
		Long-term debt due within one year				-		202
		Accounts payable				602		1,567
		Interest accrued				2,088		1,246
		Payable to subsidiaries				76,591		27,423
		Deferred credits				1,504		1,073
		Other current liabilities				2,582		1,660
		Total current liabilities				133,367		204,721
	Long-term debt					200,000		99,995
		Total liabilities				333,367		304,716

Shareholders' equity
	Preferred stock
		Not subject to mandatory redemption				25,324		26,578
		Deferred compensation related to preferred stock held by ESOP				(6,607)		(9,070)
			Total preferred stock not subject to mandatory redemption			18,717		17,508
	Common shareholders' equity
		Common stock, $1 par value, authorized 100,000,000 shares,
			issued 47,299,119 shares at December 31, 2003, and 47,065,152
			shares at December 31, 2002			47,299		47,065
		Premium on common stock				154,928		152,745
		Retained earnings				286,797		366,073
		Treasury stock, at cost, 115,484 and 29,959 shares
			at December 31, 2003 and 2002, respectively			(2,493)		(579)
		Accumulated other comprehensive loss				(3,780)		(2,834)
			Total common shareholders' equity			482,751		562,470
				Total shareholders' equity		501,468		579,978

Total liabilities and shareholders' equity					$	834,835	$	884,694

The accompanying notes are an integral part of the condensed financial statements.

			For the year ended December 31,
			2003	2002	2001
Operating activities			(Thousands)
	Net (loss) income before preferred dividends		$ (34,929)	$ 71,875	$ 70,238
	Noncash items included in net (loss) income
		Equity losses (earnings) of subsidiaries	29,715	(74,209)	(74,152)
		Loss from disposal of segment, net of tax	-	-	2,035
	Changes in assets and liabilities
		Accounts receivable from subsidiaries	(10,514)	(22,431)	3,328
		Taxes receivable	(33,307)	2,083	(132)
		Accounts payable to subsidiaries	49,168	27,423	-
		Accounts payable	(965)	1,029	(71)
		Interest accrued	842	454	62
		Other, net	(1,153)	597	2,251
		Net cash (used in) provided by operating activities	(1,143)	6,821	3,559

Investing activities
	Reductions (additions) to property, plant and equipment		-	856	(57)
	Investment in subsidiaries		(58,771)	(51,218)	44,713
	Distribution from subsidiaries		64,895	51,300	52,791
	Notes receivable from subsidiaries		40,358	(29,369)	(127,336)
	Cash transferred from restricted accounts, net		-	-	15,809
		Net cash provided by (used in) investing activities	46,482	(28,431)	(14,080)

Financing activities
	Sale of common stock		-	44,300	-
	Conversion of options to common stock		120	-	-
	Issuance of common stock under employee stock purchase plan		(44)	-	-
	Repurchase of common stock		(67)	(105)	(3,017)
	Issuance of long-term debt		100,000	-	-
	Repayment of long-term debt		(202)	(377)	(356)
	(Decrease) increase in short-term debt		(121,550)	57,617	59,713
	Dividends paid on common and preferred stock, net		(44,347)	(43,056)	(41,031)
		Net cash (used in) provided by financing activities	(66,090)	58,379	15,309

Net (decrease) increase in cash and cash equivalents			(20,751)	36,769	4,788
Cash and cash equivalents at beginning of period			44,971	8,202	3,414
Cash and cash equivalents at end of period			$ 24,220	$ 44,971	$ 8,202

Supplementary cash flow information
	Interest paid (net of amount capitalized)		$ 14,857	$ 11,976	$ 8,805

Supplementary noncash financing activity
	Issuance of treasury stock		$ -	$ 1,507	$ 2,125
	Issuance of treasury stock - LTICP and ESOP plan		$ 2,734	$ -	$ -

The accompanying notes are an integral part of the condensed financial statements.

CLECO CORPORATION
(PARENT COMPANY ONLY)
STATEMENT OF CHANGES IN
COMMON SHAREHOLDERS' EQUITY

				Long-Term
				Debt Payable				Accumulated
			Premium	in Company				Other	Total
	Common Stock		on Common	Common	Retained	Treasury Stock		Comprehensive	Common
	Shares	Amount	Stock	Stock	Earnings	Shares	Cost	Loss	Equity
	(Thousands, except share and per share amounts)
BALANCE, JANUARY 1, 2001	45,065,152	$ 45,065	$112,477	$ 519	$ 308,047	(73,072)	$(1,188)	$ -	$ 464,920
Treasury shares purchased						(148,432)	(3,017)		(3,017)
Issuance of treasury stock			(750)			87,304	1,606		856
Directors' restricted stock			(13)				13		-
Dividend requirements, preferred stock, net					(1,876)				(1,876)
Payment in common stock				(519)		31,958	519		-
Cash dividends paid, common stock,
$0.870 per share					(39,155)				(39,155)
Net income from continuing operations					72,273				72,273
Loss from discontinued operations					(2,035)				(2,035)
BALANCE, DECEMBER 31, 2001	45,065,152	45,065	111,714	-	337,254	(102,242)	(2,067)	-	491,966
Issuance of common stock	2,000,000	2,000	42,300						44,300
Treasury shares purchased						(5,784)	(105)		(105)
Issuance of treasury stock			(1,260)			78,067	1,584		324
Directors' restricted stock			(9)				9		-
Dividend requirements, preferred stock, net					(1,872)				(1,872)
Cash dividends paid, common stock,
$0.895 per share					(41,184)				(41,184)
Net income from continuing operations					71,875				71,875
Other comprehensive income, net of tax								(2,834)	(2,834)
BALANCE, DECEMBER 31, 2002	47,065,152	47,065	152,745	-	366,073	(29,959)	(579)	(2,834)	562,470
Common stock issued for compensatory plans	233,967	234	2,247						2,481
Incentive shares forfeited						(91,022)	(2,022)		(2,022)
Issuance of treasury stock			(58)			5,497	102		44
Directors' restricted stock			(6)				6		-
Dividend requirements, preferred stock, net					(1,861)				(1,861)
Cash dividends paid, common stock,
$0.900 per share					(42,486)				(42,486)
Net loss from continuing operations					(34,929)				(34,929)
Other comprehensive income, net of tax								(946)	(946)
BALANCE, DECEMBER 31, 2003	47,299,119	$ 47,299	$154,928	$ -	$286,797	(115,484)	$(2,493)	$ (3,780)	$482,751
The accompanying notes are an integral part of the condensed financial statements.

Cleco Corporation (Parent Company Only) Notes to the Condensed Financial Statements

Cleco Corporation is an exempt holding company under PUHCA. Its major, first-tier subsidiaries consist of Cleco Power and Midstream.

Cleco Power contains the LPSC jurisdictional generation, transmission, and distribution electric utility operations serving Cleco's traditional retail and wholesale customers. Another subsidiary, Midstream, owns and operates merchant generation stations and merchant natural gas pipelines, invests in joint ventures that own and operate merchant generation stations, and engages in energy management activities.

The accompanying financial statements have been prepared to present the financial position, results of operations and cash flows of Cleco Corporation on a stand-alone basis as a holding company, and excluding the financial position, results of operations and cash flows of its subsidiaries. Investments in subsidiaries and other investees are stated at cost plus equity in undistributed earnings from date of acquisition. These financial statements should be read in conjunction with Cleco Corporation's consolidated financial statements.

Cleco Corporation has a credit facility totaling $105.0 million. This facility is a 364-day facility, which provides that borrowings outstanding on the maturity date may be converted into a nine-month term loan. The commitment fees for this facility are based upon Cleco Corporation's lowest secured debt ratings and are currently 0.30%. The facility is scheduled to expire in May 2004. This facility provides working capital and other needs. If Cleco Power or Midstream defaults under their respective facilities, then Cleco Corporation would be considered in default under this facility. Perryville's default on the Senior Loan Agreement, which is discussed further in Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 27 - Perryville," is not considered a default under this credit facility. As of December 31, 2003, Cleco was in compliance with the covenants in this credit facility. Off-balance sheet commitments entered into by Cleco with third parties for certain types of transactions between those parties and Cleco's subsidiaries, other than Cleco Power, reduce the amount of credit available to Cleco Corporation under the facility by an amount equal to the stated or determinable amount of the primary obligation. At December 31, 2003, there was $50.0 million drawn on the facility, leaving $55.0 million available. The $55.0 million at December 31, 2003, was further reduced by off-balance sheet commitments of $22.5 million, leaving available capacity of $32.5 million. An uncommitted line of credit with a bank in an amount up to $5.0 million is also available to support Cleco Corporation's working capital needs.

The amounts payable under long-term debt agreements for each year through 2008 and thereafter are listed below:

Cleco Corporation received $44.4 million and $51.3 million in cash dividends from Cleco Power during the years 2003 and 2002, respectively.

CLECO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2003, 2002 and 2001

CLECO POWER
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2003, 2002 and 2001

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Louisiana (State or other jurisdiction of incorporation or organization)	72-1445282 (I.R.S. Employer Identification No.)
2030 Donahue Ferry Road, Pineville, Louisiana (Address of principal executive offices)	71360-5226 (Zip Code)
Registrant's telephone number, including area code: (318) 484-7400

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, $1.00 par value, and associated rights to purchase Preferred Stock		New York Stock Exchange Pacific Exchange

Securities registered pursuant to Section 12(g) of the Act:


Title of each class
4.50% Cumulative Preferred Stock, $100 Par Value Convertible Cumulative Preferred Stock, $100 Par Value, Series of 1991

Louisiana (State or other jurisdiction of incorporation or organization)	72-0244480 (I.R.S. Employer Identification No.)
2030 Donahue Ferry Road, Pineville, Louisiana (Address of principal executive offices)	71360-5226 (Zip Code)
Registrant's telephone number, including area code: (318) 484-7400

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
6.52% Medium-Term Notes due 2009		New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act:


Title of each class
Membership Interests

Modified LTP Agreement	Long-term program parts, shop repairs, and scheduled outage services contract, dated December 15, 2003, between Evangeline and Siemens Westinghouse Power Corporation
MW	Megawatt(s) as applicable
MWh	Megawatt-hour(s) as applicable
NOx	Nitrogen oxides
Not meaningful	A percentage comparison of these items is not statistically meaningful, either because the percentage difference is greater than 1,000%, or because the comparison involves a positive number and a negative number.
PEH	Perryville Energy Holdings LLC, a wholly owned subsidiary of Midstream
Perryville	Perryville Energy Partners, L.L.C., a wholly owned subsidiary of PEH, and its 718-MW natural gas-fired power plant near Perryville, Louisiana
Perryville Tolling Agreement	Capacity Sale and Tolling Agreement between Perryville and MAEM
PJM	Pennsylvania - New Jersey - Maryland interconnection
PUHCA	Public Utility Holding Company Act of 1935
PURPA	Public Utility Regulatory Policies Act of 1978
Quanta	Quanta Services, Inc.
RFP	Request for Proposal
RTO	Regional Transmission Organization
SEC	Securities and Exchange Commission
Senior Loan Agreement	Construction and Term Loan Agreement, dated as of June 7, 2001, between Perryville and KBC, as Agent Bank
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS No. 13	Accounting for Leases
SFAS No. 29	Determining Contingent Rentals
SFAS No. 58	Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method
SFAS No. 71	Accounting for the Effects of Certain Types of Regulation
SFAS No. 87	Employers' Accounting for Pensions
SFAS No. 94	Consolidation of All Majority Owned Subsidiaries
SFAS No. 106	Employers' Accounting for Postretirement Benefits Other Than Pensions
SFAS No. 109	Accounting for Income Taxes
SFAS No. 123	Accounting for Stock-Based Compensation
SFAS No. 131	Disclosures about Segments of an Enterprise and Related Information
SFAS No. 132	Employers' Disclosures about Pensions and Other Postretirement Benefits (revised 2003)
SFAS No. 133	Accounting for Derivative Instruments and Hedging Activities
SFAS No. 143	Accounting for Asset Retirement Obligations
SFAS No. 144	Accounting for the Impairment or Disposal of Long-Lived Assets
SFAS No. 149	Amendment of Statement 133 on Derivative Instruments and Hedging Activities
SFAS No. 150	Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity
SPP	Southwest Power Pool
SMD	Standard Market Design
SO₂	Sulfur dioxide
Subordinated Loan Agreement	Subordinated Loan Agreement, dated as of August 23, 2002, between Perryville and MAI
Support Group	Cleco Support Group LLC, a wholly owned subsidiary of Cleco Corporation
SWEPCO	Southwestern Electric Power Company
Teche	Teche Electric Cooperative, Inc.
Tolling Agreements	Reference to one or more of the following: Evangeline Tolling Agreement, Perryville Tolling Agreement, Aquila Tolling Agreement, and Calpine Tolling Agreements
UtiliTech	Utility Construction & Technology Solutions LLC
Utility Group	Cleco Utility Group Inc. (predecessor to Cleco Power)
UTS	UTS, LLC (successor entity to UtiliTech)
VAR	Value-at-risk
Williams	Williams Power Company, Inc.
Williams Energy	Williams Energy Marketing & Trading Company

	TABLE OF CONTENTS
		Page
GLOSSARY OF TERMS		3
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS		5

PART I
ITEM 1.	Business
	General	6
	Operations	7
	Regulatory Matters, Industry Developments, and Franchises	11
ITEM 2.	Properties	15
ITEM 3.	Legal Proceedings	16
ITEM 4.	Submission of Matters to a Vote of Security Holders	17


	Executive Officers of the Registrants	17


PART II
ITEM 5.	Market for Cleco Corporation's Common Equity, Cleco Power's Membership Interests and Related Stockholder Matters	19
ITEM 6.	Selected Financial Data	20
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	51
ITEM 8.	Financial Statements and Supplementary Data	56
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	103
ITEM 9A.	Controls and Procedures	103


PART III
ITEM 10.	Directors and Executive Officers	104
ITEM 11.	Executive Compensation	104
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
ITEM 13.	Certain Relationships and Related Transactions	105
ITEM 14.	Principal Accountant Fees and Services	105


PART IV
ITEM 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	106
	Signatures	117

Abbreviation or Acronym	Definition
1935 FPA	1935 Federal Power Act
401(k) Plan	Savings and Investment Plan
Acadia	Acadia Power Partners, LLC and its 1,160-MW combined-cycle, natural gas-fired power plant near Eunice, Louisiana, 50% owned by Midstream and 50% owned by Calpine
AFUDC	Allowance for Funds Used During Construction
APB	Accounting Principles Board
APB Opinion No. 18	The Equity Method of Accounting for Investments in Common Stock
APB Opinion No. 25	Accounting for Stock Issued to Employees
APH	Acadia Power Holdings LLC, a wholly owned subsidiary of Midstream
Aquila Energy	Aquila Energy Marketing Corporation
Aquila Tolling Agreement	Capacity Sale and Tolling Agreement between Acadia and Aquila Energy
ARB No. 51	Accounting Research Bulletin Consolidated Financial Statements
Bankruptcy Court	U.S. Bankruptcy Court for the Western District of Louisiana in Alexandria
Calpine	Calpine Corporation
Calpine Tolling Agreements	Capacity Sale and Tolling Agreements between Acadia and CES
CES	Calpine Energy Services, L.P.
CLE Intrastate	CLE Intrastate Pipeline Company LLC, a wholly owned subsidiary of Midstream
Cleco	Cleco Corporation and its subsidiaries, including Cleco Power LLC
Cleco Energy	Cleco Energy LLC, a wholly owned subsidiary of Midstream
Cleco Power	Cleco Power LLC, a wholly owned subsidiary of Cleco Corporation
Consent Agreement	Stipulation and Consent Agreement, dated as of July 25, 2003, between Cleco and the FERC Staff
CPS	Coughlin Power Station
Dynegy	Dynegy Power Marketing, Inc.
EITF	Emerging Issues Task Force of the FASB
EITF No. 02-3	Accounting for Contracts Involved in Energy Trading and Risk Management Activities
EITF No. 98-10	Accounting for Contracts Involved in Energy Trading and Risk Management Activities
Entergy	Entergy Corporation
EPA	Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
ESPP	Employee Stock Purchase Plan
Evangeline	Cleco Evangeline LLC, a wholly owned subsidiary of Midstream, and its 775-MW combined-cycle, natural gas-fired power plant located in Evangeline Parish, Louisiana
Evangeline Tolling Agreement	Capacity Sale and Tolling Agreement between Evangeline and Williams Energy
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation No.
FIN 45	Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others
FIN 46	Consolidation of Variable Interest Entities - an Interpretation of Accounting Research Bulletin No. 51
FIN 46R	Consolidation of Variable Interest Entities - an Interpretation of Accounting Research Bulletin No. 51 (revised December 2003)
FSP SFAS No. 106-1	FASB Staff Position Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003
Generation Services	Cleco Generation Services LLC, a wholly owned subsidiary of Midstream
IRP	Integrated Resource Planning
ISO	Independent System Operator
KBC	KBC Bank N.V.
kWh	Kilowatt-hour
LDEQ	Louisiana Department of Environmental Quality
LIBOR	London Inter-Bank Offer Rate
LPSC	Louisiana Public Service Commission
LTICP	Long-Term Incentive Compensation Plan
LTP	Long-term program parts, shop repairs, and scheduled outage services contract between Evangeline and Siemens Westinghouse Power Corporation
MAEM	Mirant Americas Energy Marketing, LP
MAI	Mirant Americas, Inc., a wholly owned subsidiary of Mirant
Marketing & Trading	Cleco Marketing & Trading LLC, a wholly owned subsidiary of Midstream
Midstream	Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Corporation
Mirant	Mirant Corporation
Mirant Debtors	Mirant, MAEM, MAI, and certain other Mirant subsidiaries
MMBtu	Million British thermal units

	Factors affecting utility operations such as unusual weather conditions or other natural phenomena; catastrophic weather-related damage; unscheduled generation outages; unusual maintenance or repairs; unanticipated changes to fuel costs, reliance on natural gas as a component of Cleco's generation fuel mix, gas supply costs or availability constraints due to higher demand, shortages, transportation problems or other developments; environmental incidents; or power transmission or gas pipeline system constraints;
	Completion of the pending sale of Perryville;
	Outcome of Perryville and PEH's bankruptcy process;
	Resolution of damage claims asserted against the Mirant Debtors in their bankruptcy proceedings as a result of the rejection of the Perryville Tolling Agreement;
	Nonperformance by and creditworthiness of counterparties under tolling and power purchase agreements, and energy service arrangements, or the restructuring of those agreements and arrangements, including possible termination;
	Increased competition in power markets, including effects of industry restructuring or deregulation, transmission system operation or administration, retail wheeling, wholesale competition, retail competition, or cogeneration;
	Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments made under traditional regulation, the frequency and timing of rate increases, the results of periodic fuel audits, the results of RFPs, and the formation of RTOs and the implementation of SMD;
	Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the Public Company Accounting Oversight Board, the FERC, the LPSC or similar entities with regulatory or accounting oversight;
	Economic conditions, including inflation rates and monetary fluctuations;
	Credit ratings of Cleco Corporation, Cleco Power, and Evangeline;
	Changing market conditions and a variety of other factors associated with physical energy, financial transactions, and energy service activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rates, and warranty risks;
	Acts of terrorism;
	Availability or cost of capital resulting from changes in Cleco, interest rates, and securities ratings or market perceptions of the electric utility industry and energy-related industries;
	Employee work force factors, including work stoppages and changes in key executives;
	Legal and regulatory delays and other obstacles associated with mergers, acquisitions, capital projects, reorganizations, or investments in joint ventures;
	Costs and other effects of legal and administrative proceedings, settlements, investigations, claims and other matters; and
	Changes in federal, state, or local legislative requirements, such as changes in tax laws or rates, regulating policies or environmental laws and regulations.

Generating Station	Generating Unit #	Year of initial operation	Net Capacity (MW)	Type of fuel used for generation ⁽¹⁾
Franklin Gas Turbine		1973	7	gas
Teche Power Station	1	1953	23	gas
	2	1956	48	gas
	3	1971	359	gas/oil (standby)
Rodemacher Power Station	1	1975	440	gas/oil (standby)
	2	1982	157 ⁽²⁾	coal/gas
Dolet Hills Power Station	1	1986	325 ⁽³⁾	lignite
Total generating capability			1,359

(1) When oil is used on a standby basis, capacity may be reduced.
(2) Represents Cleco Power's 30% ownership interest in the capacity of Rodemacher Unit 2, a 523-MW generating unit.
(3) Represents Cleco Power's 50% ownership interest in the capacity of Dolet Hills Unit 1, a 650-MW generating unit.

Period	Thousand MWh	Percent of total energy requirements
2003	5,044	50
2002	5,405	55
2001	5,536	60
2000	6,254	66
1999	6,376	73

	Lignite		Coal		Gas		Fuel Oil
Year	Cost per kWh (cents)	Percent of generation	Cost per kWh (cents)	Percent of generation	Cost per kWh (cents)	Percent of generation	Cost per kWh (cents)	Percent of generation	Weighted average cost per kWh (cents)
2003	1.672	47.1	1.625	17.3	6.079	34.8	7.178	0.8	3.242
2002	1.625	43.1	1.482	16.6	3.894	40.3	5.899	*	2.517
2001	1.735	40.9	1.519	14.4	5.170	42.9	5.776	1.8	3.250
2000	1.556	37.0	1.507	16.8	4.678	45.7	4.318	0.5	2.988
1999	1.574	28.5	1.490	17.2	2.745	54.3	-	-	2.196

* less than 1/10 of one percent

Period	Thousand MWh	Percent of total energy requirements
2003	5,132	50
2002	4,482	45
2001	3,739	40
2000	3,255	34
1999	2,359	27

Natural gas supplier	2003 purchases (MMBtu)	Average amount purchased per day (MMBtu)	Percent of total gas used
American Electric Power	7,306,000	20,000	27.28
Cinergy	5,121,000	14,000	19.10
BP Amoco	3,707,000	10,200	13.92
Occidental Energy Marketing	3,091,000	8,500	11.60
Murphy Oil USA	2,438,000	6,700	9.14
Others	5,091,000	13,900	18.96
Total	26,754,000	73,300	100.00

	Evangeline, which owns and operates a 775-MW combined-cycle natural gas-fired power plant.
	APH, which owns 50% of Acadia, a 1,160-MW combined-cycle natural gas-fired power plant.
	PEH, which owns 100% of Perryville, a 718-MW natural gas-fired power plant consisting of a 156-MW simple-cycle unit and a 562-MW combined-cycle unit. Perryville and PEH filed for voluntary protection under Chapter 11 of the U.S. Bankruptcy Code in January 2004 in connection with the pending sale of the Perryville facility to Entergy Louisiana, Inc. For additional information on the sale and the bankruptcy filings, see Part II, Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 30 - Subsequent Events - Perryville."
	Generation Services, which offers power station operations and maintenance services. Its main customers are Evangeline and Perryville.
	Cleco Energy, which manages natural gas pipelines, natural gas production, and natural gas procurement in Texas and Louisiana.
	CLE Intrastate, which owns a natural gas interconnection that allows Evangeline to access the natural gas supply market.
	Marketing & Trading, which provided energy management services prior to May 2003.

Generating Station	Generating Unit #	Commencement of commercial operation	Net Capacity (MW)	Type of fuel used for generation
Evangeline	6	2000	264	gas
	7	2000	511	gas
Perryville	1	2002	562 ⁽²⁾	gas
	2	2001	156 ⁽²⁾	gas
Acadia	1	2002	290 ⁽¹⁾	gas
	2	2002	290 ⁽¹⁾	gas
Total generating capability			2,073


(1) Represents APH's 50% ownership interest in the capacity of Acadia.
(2) Committed to be sold.

	deregulation of retail electricity sales;
	the ability of electric utilities to recover stranded costs;
	the repeal or modification of PUHCA;
	the repeal or modification of PURPA;
	the unbundling of vertically integrated electric utility companies into separate business segments or companies (e.g., generation, transmission, distribution, and retail energy service);
	the role of electric utilities, independent power producers and competitive bidding in the purchase, construction and operation of new generating capacity;
	the pricing of transmission service on an electric utility's transmission system;
	FERC's assessment of market power and utilities' ability to buy generation assets;
	mandatory transmission reliability standards;
	the power of eminent domain within the FERC; and
	the organization of and participation in RTOs.

Distribution/Dividend Amount		Date Paid
	$10.6 million	February 15, 2001
	$ 8.8 million	May 15, 2001
	$12.3 million	August 15, 2001
	$21.1 million	November 15, 2001
	$16.9 million	February 15, 2002
	$14.1 million	May 15, 2002
	$20.3 million	November 15, 2002
	$14.6 million	February 15, 2003
	$15.9 million	May 15, 2003
	$13.9 million	November 15, 2003

	Cleco Power, an electric utility regulated by the LPSC and the FERC, among other regulators, and
	Midstream, a merchant energy subsidiary that owns and operates merchant generation stations and merchant natural gas pipelines, and engages in energy management activities.

	resolution of Cleco Power's long-term capacity needs,
	renewal or extension of Cleco Power's rate plan,
	outcome of pending LPSC fuel audit of Cleco Power,
	ongoing credit condition of Acadia and Evangeline tolling agreement counterparties and the performance of the tolling agreements by such counterparties, and
	completion of the sale of the Perryville facility.

	deregulation;
	retail wheeling (the transmission of power directly to a retail customer, as opposed to transmission via the interconnected transmission facilities of one or more intermediate facilities);
	possible transfer of transmission facilities to a RTO;
	other legislative and regulatory changes;
	cost of power impacted by the price of natural gas;
	retention of large industrial customers and municipal franchises;
	changes in electric rates compared to customers' ability to pay; and
	access to transmission systems.

	higher capacity payments,
	higher maintenance expense, and
	higher depreciation expense.

	higher base revenue from retail and wholesale customer sales and energy management services,
	lower losses from energy trading,
	higher transmission revenue,
	lower electric customer credits, and
	the absence of an organizational restructuring charge in 2003.

	19% in the first quarter,
	22% in the second quarter,
	42% in the third quarter, and
	17% in the fourth quarter.

	impairments of long-lived assets,
	lower margins from energy trading,
	lower other operations revenue,
	higher other operations expense,
	higher maintenance expense,
	higher depreciation expense, and
	higher interest charges.

	higher tolling revenue,
	the absence of an organizational restructuring charge in 2003, and
	higher equity income from investees.

	higher base revenue from retail customer sales,
	lower operating expenses, and
	higher wholesale revenue.

These were partially offset by:

	lower losses from energy trading,
	lower interest income,
	higher interest charges, and
	the organizational restructuring charge.

	higher tolling revenue,
	decreased purchases for energy operations, and
	higher equity income from investees.

	These were partially offset by:

	lower margins from energy trading, net,
	decreased energy operations revenue,
	the organizational restructuring charge,
	higher gas transportation charges,
	a deferred tax adjustment, and
	impairment of long-lived assets.

	The LPSC determines the ability of Cleco Power to recover prudent costs incurred in developing long-lived assets. If the LPSC were to rule that the cost of current or future long-lived assets was imprudent and not recoverable, Cleco Power could be required to write down the imprudent cost and incur a corresponding impairment loss. At December 31, 2003, the carrying value of Cleco Power's long-lived assets was $1.0 billion. Currently, Cleco Power has concluded that none of its long-lived assets is impaired.
	Cleco Power has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At December 31, 2003, Cleco Power had $113.0 million in regulatory assets, net of regulatory liabilities. Actions by the LPSC could limit the recovery of these regulatory assets, causing Cleco Power to record a loss on some or all of the regulatory assets. For additional information on the LPSC and regulatory assets, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Regulation," Note 3 - "Regulatory Assets and Liabilities," and "- Financial Condition - Regulatory Matters - Lignite Deferral."
	The LPSC determines the amount and type of fuel and purchased power costs that Cleco Power can charge customers through the fuel adjustment clause. Changes in the determination of allowable costs already incurred by Cleco Power could cause material changes in fuel revenue. Additionally, Cleco Power currently is undergoing a periodic fuel audit by the LPSC. For the years ended December 31, 2003, 2002, and 2001, Cleco Power reported fuel revenue of $364.0 million, $262.7 million, and $304.3 million, respectively. For additional information on the LPSC and the fuel adjustment clause, see "- Financial Condition - Retail Rates of Cleco Power," "- Results of Operations - Significant Factors Affecting Cleco Power - Fuel and purchased power are primarily affected by the following factors" and "- Financial Condition - Regulatory Matters - Fuel Audit."

	At December 31,
Subsidiary		2003			2002
				(Thousands)
Cleco Corporation (Holding Company Level)
Bank loans		$	50,000		$	171,550
Cleco Power
Bank loans			-			107,000
Midstream
Bank loans			150,787			36,750
Total		$	200,787		$	315,300

	Long-term Maintenance Agreements: Cleco has entered into long-term maintenance agreements with third party manufacturers that provide for fixed and variable maintenance costs associated with Cleco's merchant power plants. Midstream's equity investment in investee's long-term maintenance agreement represents Midstream's 50% ownership interest. For additional information regarding equity investment in investees, see Item 8, "Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 -Equity Investment in Investees."

	Fuel Contracts: To supply a portion of the fuel requirements for Cleco Power's generating plants, Cleco has entered into various commitments to obtain and deliver coal, lignite, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. Generally, fuel and purchased power expenses are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to customers substantially all such charges. For additional information regarding fuel contracts, see Part I, Item 1, "Business - Operations - Cleco Power - Fuel and Purchased Power."

	Power Purchase Agreements: Cleco Power has entered into agreements with energy suppliers for purchased power to meet system load and energy requirements, replace generation from Cleco Power owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Cleco Power has also entered into agreements to purchase transmission capacity. For additional information regarding power purchase agreements, see "- Regulatory Matters - Purchased Power" below.

	Purchase orders: Cleco has entered into purchase orders in the course of normal business activities.

		Amount of Commitment Expiration Per Period
		Net amount committed		Less than one year		1-3 years		4-5 years			More than 5 years
	(Thousands)
Guarantees		$	84,904	$	59,009	$	-	$	-	$		25,895
Standby letter of credit			15,000		-		-		-			15,000
Total commercial commitments		$	99,904	$	59,009	$	-	$	-	$		40,895

	accelerated tax depreciation for transmission lines,
	reduction in the cost recovery period for pollution control equipment,
	provisions to create a mandatory reliability organization,
	provisions to streamline the federal permitting process for transmission projects and to set deadlines for the designation of transmission corridors,
	provisions that will allow a company that sells transmission assets to a FERC-approved RTO or ISO to defer the gain on those assets by recognizing the gain ratably over an eight-year period,
	FERC's concerns over market power,
	limited backstop transmission citing authority for FERC,
	reform of PURPA's mandatory purchase obligation, and
	repeal of PUHCA.

	For the year ended December 31, 2003						At December 31,
	High		Low		Average		2003			2002
	(Thousands)						(Thousands)
Marketing & Trading	$	14.6	$	-	$	1.3	$	-	$		5.7
Cleco Power	$	7.3	$	-	$	0.1	$	-	$		-
Cleco Energy	$	343.9	$	6.7	$	145.6	$	97.7	$		29.3
Consolidated	$	343.9	$	6.9	$	147.0	$	97.7	$		35.0

To the Shareholders and Board
of Directors of Cleco Corporation:

Note 1	The Company	Cleco Corporation and Cleco Power
Note 2	Summary of Significant Accounting Policies	Cleco Corporation and Cleco Power
Note 3	Regulatory Assets and Liabilities	Cleco Corporation and Cleco Power
Note 4	Jointly Owned Generation Units	Cleco Corporation and Cleco Power
Note 5	Fair Value of Financial Instruments	Cleco Corporation and Cleco Power
Note 6	Debt	Cleco Corporation and Cleco Power
Note 7	Common Stock	Cleco Corporation
Note 8	Preferred Stock	Cleco Corporation
Note 9	Pension Plan and Employee Benefits	Cleco Corporation and Cleco Power
Note 10	Income Tax Expense	Cleco Corporation and Cleco Power
Note 11	Disclosures About Segments	Cleco Corporation and Cleco Power
Note 12	Accrual of Electric Customer Credits	Cleco Corporation and Cleco Power
Note 13	Equity Investment in Investees	Cleco Corporation
Note 14	Operating Leases	Cleco Corporation and Cleco Power
Note 15	Change in Accounting Estimate	Cleco Corporation
Note 16	Securities Litigation and Other Commitments and Contingencies	Cleco Corporation and Cleco Power
Note 17	Discontinued Operations	Cleco Corporation
Note 18	Risks and Uncertainties	Cleco Corporation and Cleco Power
Note 19	Review of Trading Activities	Cleco Corporation and Cleco Power
Note 20	Restructuring Charge	Cleco Corporation and Cleco Power
Note 21	Acquisition	Cleco Corporation
Note 22	Gas Transportation Charge	Cleco Corporation and Cleco Power
Note 23	Disclosures About Guarantees	Cleco Corporation and Cleco Power
Note 24	Impairments of Long-Lived Assets	Cleco Corporation
Note 25	FERC Settlement	Cleco Corporation and Cleco Power
Note 26	Affiliate Transactions	Cleco Power
Note 27	Perryville	Cleco Corporation
Note 28	Accounting for Asset Retirement Obligation	Cleco Corporation and Cleco Power
Note 29	Miscellaneous Financial Information (Unaudited)	Cleco Corporation and Cleco Power
Note 30	Subsequent Events	Cleco Corporation