Cleco Corporate 10K 2002 Annual report | SEC Filing

EXHIBIT 13

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

In this report Cleco, (which includesCleco Corporation and all of its regulated and unregulated subsidiaries) is, sometimes, referred to in the first person as "we," "our," or "us."

GENERAL

We are a holding company that is exempt from regulation, subject to certain limited exceptions, as a public utility holding company under the Public Utility Holding Company Act of 1935. We have three continuing business segments and one discontinued business segment. The continuing business segments are:

	Cleco Power LLC (Cleco Power) is an electric utility regulated by the Louisiana Public Service Commission (LPSC) and the Federal Energy Regulatory Commission (FERC), which determine the rates it can charge its customers. Cleco Power serves approximately 261,000 customers in 104 communities in central and southeastern Louisiana.
	Cleco Midstream Resources LLC (Midstream) is an unregulated subsidiary with operations in Louisiana and Texas. Midstream owns and operates wholesale generation stations and wholesale natural gas pipelines, invests in joint ventures that own and operate wholesale generation stations, and engages in energy management activities.
	Our other segment consists of the holding company, a shared services subsidiary, and an investment subsidiary.

The discontinued business segment is UTS, LLC (UTS), formerly known as Utility Construction & Technology Solutions LLC (UtiliTech). UTS was a utility line construction business. We decided to sell substantially all assets of UTS in December 2000. Revenue and expenses associated with UTS are netted and shown on our Consolidated Statements of Income as a loss from discontinued operations. For additional information on selling substantially all of the UTS assets, see the Notes to the Consolidated Financial Statements, Note 17 - "Discontinued Operations."

Certain reclassifications have been made to the 2001 and 2000 consolidated financial statements to conform to the presentation used in the 2002 consolidated financial statements. These reclassifications had no effect on net income applicable to common stock or total common shareholders' equity.

RESULTS OF OPERATIONS

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)%
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 %

*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. For these reasons, we refer here and in other portions of this discussion to such percentage comparisons as being "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 the Notes to the Consolidated Financial Statements, Note 20 - "Restructuring Charge," Note 22 - "Gas Transportation Charges," and Note 24 - "Impairment of Long-Lived Asset," 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 our unregulated power plants, as well as increased generation from our third unregulated 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 the Notes to the Consolidated Financial Statements, Note 20 - "Restructuring Charge," Note 22 - "Gas Transportation Charges," and Note 24 - "Impairment of Long-Lived Asset," respective ly.

A companywide organizational restructuring was completed in the fourth quarter of 2002. As a result of the restructuring, our workforce was reduced by 160 employees. The costs associated with restructuring, consisting mainly of early retirement and voluntary 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 us in future years through reductions in operating expenses. For additional information on the restructuring charge, see the Notes to the Consolidated Financial Statements, Note 20 - "Restructuring Charge."

Income tax expense increased $3.9 million, or 10.1%, in 2002 compared to 2001. Our 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 the Notes to the Consolidated Financial Statements, Note 17 - "Discontinued Operations."

General Factors Affecting Cleco Power

Revenue is primarily affected by the following factors:

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 revenue 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. We anticipate discussions with the LPSC staff regarding the status of the plan will begin in late 2003. For additional information on Cleco Power's rate stabilization plan, see "- Financial Condition - Retail Rates of Cleco Power."

Energy trading, net, generally is affected by supply and demand in the market, the financial viability of our marketing and trading counterparties, and the volatility in market prices. During the third quarter of 2002, we began an assessment of our speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and we determined, in light of market conditions and other factors, that Cleco Power would discontinue speculative trading activities. Most of our exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions we entered into specifically to offset those open positions. For additional information on energy trading, net, see "- Financial Condition - Financial Risk Management."

Our residential customers' demand for electricity is largely affected by weather. Weather is generally 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.

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

Kilowatt-hour (kWh) sales to retail electric customers have grown an average of 3.4% annually over the last five years, but we expect them to range from 0.5% to 1.0% 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:

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 Regional Transmission Organization (RTO),
	other legislative and regulatory changes,
	retention of large industrial customers and municipal franchises,
	changes in electric rates compared to customers' ability to pay, and
	access to transmission systems.

Fuel and power purchased are primarily affected by the following factors:

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.

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 (representing about 93% of its total fuel costs) and the FERC. The LPSC staff has informed Cleco Power that it is planning to conduct a periodic fuel audit beginning in the first quarter of 2003. The audit, pursuant to the Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497, is required to be performed no less frequently than every other year; however, this will be the first LPSC fuel adjustment clause audit of Cleco Power. Cleco Power has not been informed which time period will be covered by the aud it, nor is management able to predict the results of the LPSC fuel audit. Recovery of fuel adjustment clause costs is subject to refund until final approval is received from the LPSC upon completion of the periodic audit. LPSC-jurisdictional revenue recovered by Cleco Power through its fuel adjustment clause for the three years, five years, and seven years ending December 31, 2002, was $811.5 million, $1,189.4 million, and $1,531.5 million, respectively.

An earnings review settlement reached with the LPSC in 1996 sometimes requires accruals for estimated customer credits, depending on our level of earnings. The amount of credit due customers, if any, is determined annually by the LPSC based on results for the 12-month period ending September 30 of each year. Cleco Power accrued $2.9 million in 2002 for estimated customer credits compared to $1.8 million in 2001. The $2.9 million accrual relates to the 12-month cycles ended September 30, 2001, 2002, and 2003. For additional information on the accrual for estimated customer credits, see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

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 power contracts with two power marketing companies, Williams Energy Marketing & Trading Company (Williams Energy) and Dynegy Power Marketing, Inc. (Dynegy), for a total of 705 megawatts (MW) of capacity in 2002 and in 2003, increasing to 760 MW of capacity in 2004, decreasing to 100 MW of capacity in 2005. Because substantially all of the contracts expire on December 31, 2004, Cleco Power is currently evaluating its long-term capacity and energy needs. Cleco Power anticipates it will initiate a solicitation during the first quarter of 2003 to identify existing or new generation resources, including new power purchase contracts, to replace the Williams Energy contracts and the Dynegy contract. Pursuant to the LP SC's 1983 General Order governing the construction and/or procurement of generation capacity, Cleco Power is required to make an informational filing with the LPSC to substantiate that securing such generation resources is in the public interest. Cleco Power anticipates making such a filing during the first quarter of 2003 and will continue to evaluate supply options through the first half of 2003. As part of that process, Cleco Power will also evaluate the possibility of acquiring additional generation facilities, including one or more of Midstream's unregulated power plants. In addition to the power obtained under long-term contracts, Cleco Power purchases power from other utilities and other marketers 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. However, transmission capacity must be available to transport the purchased power to Cleco Power's system in order for it to be able to utilize the power. During 2002, 45.4% of Cleco Power's energy requirements was met with purchased power, up from 40.3% in 2001 and 34.2% in 2000.

In future years, 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 bring 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 - Purchased Power."

Other expenses are primarily affected by the following factors:

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 expenses are primarily 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 are generally affected by payroll taxes and ad valorem taxes.

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 $59.5 million compared to $59.1 million for 2001. Factors contributing to the slight increase include:

	higher base revenue from retail customer sales,
	lower operating expenses, and
	higher wholesale revenue.

These were partially offset by:

	lower margins from energy trading, net,
	lower interest income,
	higher interest expense, and
	the organizational restructuring charge.

	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)%
Estimated customer credits	(2,900)	(1,800)	(1,100)	61.1%
Energy trading, net	(752)	1,456	(2,208)	*
Energy operations	30	-	30	*
Other operations	29,301	30,813	(1,512)	(4.9)%
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	150,400	139,913	10,487	7.5%
Other operations	63,484	82,479	(18,995)	(23.0)%
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%
Interest income	$ 933	$ 6,498	$ (5,565)	(85.6)%
Interest expense	$ 29,091	$ 26,819	$ 2,272	8.5%

* 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 on-system 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 degree-days and heating degree-days in 2002 and 2001 varied from normal conditions and from the prior yearfor cooling degree-days and heating degree-days for 2002 and 2001. Before 2002, Cleco Power used an internally generated temperature reading to determine cooling and heating degree-days. In the fourth quarter of 2002, Cleco Power began to use temperature data collected by the National Oceanic and Atmospheric Administration (NOAA) for this purpose. Cooling and heating degree-days for 2001 and 2000 have been adjusted to reflect the change in the temperature data source.

	For the year ended December 31,
	2002	2001
Cooling degree-days
Increase/(Decrease) from Normal	2.6 %	(5.1)%
Increase/(Decrease) from Prior Year	5.1 %	(11.4)%
Heating degree-days
Increase/(Decrease) from Normal	3.8 %	1.2 %
Increase/(Decrease) from Prior Year	13.1 %	(5.2)%

Base

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 the addition of a second wholesale customer in January 2002.

Fuel Cost Recovery

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 "- General Factors Affecting Cleco Power - Fuel and power purchased are primarily affected by the following factors," above.

Estimated Customer Credits

Revenue for 2002 was decreased by a $2.9 million accrual for estimated customer credits compared to a $1.8 million accrual in 2001. For additional information on the accrual for estimated customer credits, see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

Energy Trading, Net

For 2002 compared to 2001, the increase in power and gas volumes traded was primarily due to expansion of Cleco Power's power and gas trading portfolio. During the third quarter of 2002, we began an assessment of our speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and we determined, in light of market conditions and other factors, that Cleco Power would discontinue speculative trading activities. Most of our exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions we entered into specifically to offset those open positions. Volumes and associated net revenue will continue to be affected by those positions during 2003. A summary of power and natural gas traded by Cleco Power for the periods indicated appears below.

	For the year ended December 31,
	2002	2001	Change
Power (Million kWh)	240.2	5.0	*
Natural gas (MMBtu)	3,385,000	2,634,766	28.5 %

* Not meaningful

Generally, Cleco Power's energy trading transactions are considered nonhedging derivatives under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, which requires that the transactions be reported at fair market value or "marked-to-market." The chart below presents the components of energy trading, net.

	Energy Trading, Net For the year ended December 31,
	2002	2001	Variance	Change
	(Thousands)
Energy trading margins	$ (153)	$ 1,403	$ (1,556)	*
Mark-to-market	(599)	53	(652)	*
Energy trading, net	$ (752)	$ 1,456	$ (2,208)	*

* Not meaningful

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, and our efforts in the fourth quarter of 2002 to mitigate most of our exposure to the market following our decision to discontinue speculative trading activities and volatility in power and natural gas prices in 2002. For additional information on the premiums on certain gas put options, see "- Financial Condition - Regulatory Matters - Gas Put Options."

Issue 1 of Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," 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. We adopted EITF No. 02-3 effective July 1, 2002. For additional information regarding our adoption of EITF No. 02-3, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

In October 2002, the EITF rescinded EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," 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 "marked-to-market." Instead of using EITF No. 98-10, energy contracts will now be evaluated using SFAS No. 133, as amended, in order to determine whether mark-to-market accounting is appropriate. For additional information on the rescission of EITF No. 98-10, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

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

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 million British thermal units (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 that had not been collected previously from utility customers. From 2001 to 2002, power purchased for utility customers increased $10.5 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 $16.6 million, or 15.3%, decrease in other operations and maintenance expenses for 2002 compared to 2001 was primarily du e 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 expenses 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 the Notes to the Consolidated 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 and Expenses

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. Because the recovery of the fuel-related costs was a one-time adjustment, we do not expect interest income in future periods to be as large as it was in 2001. Interest expense increased $2.3 million, or 8.5%, primarily due to interest related to gas transportation charges. For additional information regarding gas transportation charges, see the Notes to the Consolidated Financial Statements, Note 22 - "Gas Transportation Charges."

General Factors Affecting Midstream

Revenue is primarily affected by the following factors:

Most of Midstream's revenue is derived from its power plant operations, energy operations, and energy trading, net.

Revenue from wholly owned power plant operations is derived primarily from tolling operations. Tolling revenue is generally affected by the availability of the subject facility to operate, the amount of replacement power provided to the tolling counterparty, and overall performance under the tolling contract. 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 are reflected in equity income from investees.

Tolling revenue is partially derived from a 775-MW combined-cycle, natural gas-fired power plant (Evangeline) through the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling Agreement) between Cleco Evangeline LLC (Evangeline LLC) and Williams Energy. Tolling revenue is also derived from a 725-MW, natural gas-fired power plant (Perryville) through the Tolling Agreement between Perryville Energy Partners LLC (PEP) and Mirant Americas Energy Marketing, L.P. (MAEM) (Perryville Tolling Agreement). Through an investment in Acadia Power Partners LLC (APP), equity earnings are derived primarily from a 1,160-MW combined-cycle, natural gas-fired power plant (Acadia) that is jointly owned (50-50) by Midstream and Calpine Corporation (Calpine). Acadia's output is sold through two separate tolling agreements: one between Aquila Energy Marketing Corporation (Aquila Energy) and APP (Aqu ila Tolling Agreement), and the other between Calpine Energy Services, L.P. (CES) and APP (Calpine Tolling Agreement). We use the term "tolling agreements" to refer to one or more of these: the Evangeline Tolling Agreement, the Perryville Tolling Agreement, the Aquila Tolling Agreement and the Calpine Tolling Agreement . For additional information on Acadia, Perryville, and the tolling agreements related to those facilities, see "- Financial Condition - New Power Plants."

Evangeline LLC, PEP, and APP have certain performance obligations under their respective tolling agreements that expose us to possible adverse financial penalties and requirements. 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,
	paying scheduled interest and principal payments on debt,
	maintaining plant operating 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.

If the physical plants fail to operate within specified requirements, Cleco 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 us to power commodity price volatility and transmission constraints. If we do not meet our obligations under the tolling agreements, or if economical purchase power and transmission are not available, our financial condition and results of operations could be materially adversely affected.

Under the Evangeline Tolling Agreement, Williams Energy pays Evangeline LLC 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 our operating leases, see "Critical Accounting Policies" and the Notes to the Consolidated Financial Statements, Note 14 - "Operating Leases." Evangeline Tolling Agreement revenue is not recognized evenly throughout the year; it varies with physical usage of the plant. Evangeline LLC's 2002 revenue was recognized in the following manner:

	19% in the first quarter,
	22% in the second quarter,
	41% in the third quarter, and
	18% in the fourth quarter.

Revenue for 2003 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" and the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Revenue and Fuel Costs - Tolling Revenue."

Under the Perryville Tolling Agreement, MAEM pays PEP a fixed fee and a variable fee for operating and maintaining the facility. MAEM also pays a quarterly amount to PEP, which represents its share of PEP's quarterly parts and maintenance expenses under PEP's long-term maintenance contract with General Electric Corporation (PEP LTP). This amount is based upon PEP's run hours and factored starts for each quarter. The Perryville Tolling Agreement is accounted for as an operating lease. For additional information on our operating leases, see "Critical Accounting Policies," and the Notes to the Consolidated Financial Statements, Note 14 - "Operating Leases." Perryville Tolling Agreement revenue is recognized evenly throughout the year. For additional information on recognition of revenue from the Perryville Tolling Agreement, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Revenue and Fuel Costs - Tolling Revenue."

Under the Aquila Tolling Agreement, Aquila Energy pays APP a fixed fee and a variable fee for operating and maintaining the facility. Under the Calpine Tolling Agreement, CES pays APP 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 are recognized evenly throughout the year.

The parent companies of our tolling counterparties are The Williams Companies, Inc., Mirant Corporation (Mirant), Aquila, 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 credit watch for possible further downgrade by one or more rating agencies. The bonds issued by Evangeline LLC to finance the Evangeline facility were downgraded below investment grade by Moody's Investors Service (Moody's) on October 2, 2002, to Ba3. In its press release announcing this downgrade, Moody's stated that the deterioration in The Williams Companies, Inc. credit rating had in turn exerted downward pressure on Evangeline LLC's rating. On November 27, 2002, the bond s were further downgraded by Moody's to B3.

The following list discusses some possible adverse consequences if any of our counterparties should fail to perform their obligations under their respective tolling agreements. The list is not all-inclusive, but represents examples of possible adverse consequences resulting from the nonperformance of our tolling counterparties.

	Our financial condition and results of operations may be adversely affected by their failure to pay amounts due to us and may not be consistent with historical and projected results.
	We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all.
	We would be required to test any long-lived generation asset for impairment if the tolling counterparty defaulted under the related tolling agreement. If we determined that an impairment existed, the asset would be written down to its fair market value, which could materially adversely affect our results of operations and financial condition. For more information on long-lived assets, see " - Critical Accounting Policies."
	Possible acceleration of our project-level debt, in particular:
	1) Under provisions of the PEP five-year loan, lenders holding two-thirds of the loan commitment have the right to demand the entire outstanding principal amount ($145.1 million at December 31, 2002) plus accrued interest immediately due and payable upon a default under the Perryville Tolling Agreement by MAEM. If the lenders were to exercise this right, we might, among other things, renegotiate the loan, refinance the loan, pay off the loan with other borrowings or the proceeds of issuances of additional debt, or cause PEP, as a stand-alone entity, to seek protection under federal bankruptcy laws. In addition, the lenders could foreclose on the mortgage and assume ownership of the plant. Any renegotiated loan or alternative financing would likely be on less favorable terms than the existing terms. For additional information on the loan, see "- Financial Condition - Liquidity and Capital Resources - Debt - Cleco Corporation (Holding C ompany Level)."

	2) Under provisions of the bonds issued by Evangeline LLC, the bondholders have the right to demand the entire outstanding principal amount ($208.8 million at December 31, 2002) 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, we 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 LLC, as a stand-alone entity, 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.

Our counterparties and we currently are in discussions regarding the possibility that one or more of the counterparties might terminate their interests in the respective tolling agreements. We also have been contacted by several entities interested in acquiring power contracts or investing in generation assets. In addition, we have answered a request for proposal relating to the sale of certain of our unregulated generation assets.

Revenue from energy operations and energy trading, net generally is affected by transmission constraints, supply and demand in the market, the financial viability of our marketing and trading counterparties, and volatility of market prices. Energy operations revenue is comprised of two components: energy management services and wholesale natural gas marketed. Cleco Marketing & Trading LLC (Marketing & Trading), a subsidiary of Midstream, primarily provides energy management services to several municipalities and, prior to the fourth quarter of 2002, marketed and traded wholesale natural gas and electricity. During the third quarter of 2002, we began an assessment of our speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and we determined, in light of market conditions and other factors, that Marketing & Trading would discontinue s peculative trading activities. Most of our exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions we entered into to specifically offset those open positions. For information on our obligation to provide credit support in certain instances under power and gas trading agreements entered into by Marketing & Trading, see "- Financial Condition - Liquidity and Capital Resources - General Considerations and Credit-Related Risks." Cleco Energy LLC (Cleco Energy), also a subsidiary of Midstream, primarily markets wholesale natural gas in Louisiana and Texas. It 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 Cleco Generation Services LLC (Cleco Generation) provided to PEP prior to our acquisition of the remaining interest in PEP in the summer of 2002. For additional information regarding our acquisition of PEP, see the Notes to the Consolidated Financial Statements, Note 21 - "Acquisition."

Expenses are primarily affected by the following factors:

Most of Midstream's expenses include purchases for energy operations, depreciation, maintenance, and other operations expenses. Purchases for energy operations are affected primarily by the same factors as energy operations revenue. Depreciation expenses are 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 administration expenses and employee benefits.

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. Factors contributing to the slight increase include:

	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,
	gas transportation charges,
	a deferred tax adjustment, and
	impairment of a long-lived asset.

	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	48,323	(23,006)	(47.6)%
Other operations	27,804	33,984	(6,180)	(18.2)%
Maintenance	8,902	4,828	4,074	84.4 %
Depreciation	15,989	9,379	6,610	70.5 %
Restructuring charge	2,058	-	2,058	*
Impairment of asset	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	*

* 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 "- General Factors Affecting Midstream - Revenue is primarily affected by the following factors," above.

Energy Trading, Net

For 2002 compared to 2001, the increase in power and gas volumes traded was primarily due to expansion of Midstream's power and physical gas trading portfolio, as well as power sales to APP. During the third quarter of 2002, we began an assessment of our speculative trading strategy. This assessment was completed during the fourth quarter of 2002, and we determined, in light of market conditions and other factors, that Midstream would discontinue speculative trading activities. Most of our exposure to the market from positions opened prior to the change in strategy was mitigated in the fourth quarter of 2002 by transactions we entered into specifically to offset those open positions. Volumes and associated net revenue will continue to be affected by those positions during 2003 and 2004. A summary of power and natural gas traded by Midstream and its subsidiaries appears bel ow.

	For the year ended December 31,
	2002	2001	Change
Power (Million kWh)	10,012	3,278	205.4 %
Natural gas (MMBtu)	70,610,889	17,209,354	310.3 %

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

Energy Trading, Net For the year ended December 31,
	2002	2001	Variance	Change
	(Thousands)
Energy trading margins	$ 2,914	$ 5,066	$ (2,152)	(42.5)%
Mark-to-market	(493)	542	(1,035)	*
Energy trading, net	$ 2,421	$ 5,608	$ (3,187)	(56.8)%

* Not meaningful

Energy trading, net for 2002 compared to 2001 decreased $3.2 million. The decrease was primarily due to our efforts in the fourth quarter of 2002 to mitigate most of our exposure to the market following our 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. We adopted EITF No. 02-3 effective July 1, 2002. For additional information on our adoption of EITF No. 02-3, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

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 "marked-to-market." Instead of using EITF No. 98-10, energy contracts now will be evaluated using SFAS No. 133, as amended, in order to determine whether mark-to-market accounting is appropriate. For additional information on the rescission of EITF No. 98-10, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

Energy Operations

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 immediately below presents the components of energy operations revenue.

	For the year ended December 31,
	2002	2001	Variance	Change
	(Thousands)
Energy management services	$ 1,590	$ 763	$ 827	108.4 %
Wholesale natural gas marketed	28,460	57,896	(29,436)	(50.8)%
Energy operations	$ 30,050	$ 58,659	$ (28,609)	(48.8)%

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

	For the year ended December 31,
	2002	2001	Change
Natural gas (MMBtu)	7,622,296	11,398,704	(33.1)%

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

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

Operating Expenses

Purchases for energy operations decreased $23.0 million, or 47.6%, from 2001 to 2002, primarily due to lower per unit costs and lower volumes of natural gas marketed. Other operations expenses decreased $6.2 million, or 18.2%, 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

beginning its full commercial operation in 2002. Maintenance expenses increased a net $4.1 million, or 84.4%, across several Midstream companies. In 2002 compared to 2001, maintenance expenses at Cleco Generation increased $2.6 million, or 98.7%. 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 LLC, 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 PEP 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 LLC primarily due to a reassessment of the useful life of turbin e 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 compared to none in 2001. For additional information on these charges, see the Notes to the Consolidated Financial Statements, Note 20 - "Restructuring Charge" and Note 24 - "Impairment of Long-Lived Asset," 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 APP as a result of Acadia beginning commercial operation in the summer of 2002. For additional information regarding our investment in APP, see the Notes to the Consolidated 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.

Consolidated Results of Operations - Year ended December 31, 2001, Compared to Year ended December 31, 2000

	For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)

Operating revenue	$ 748,759	$ 675,314	$ 73,445	10.9 %
Operating expenses	$ 599,219	$ 527,617	$ 71,602	13.6 %
Net income from continuing operations	$ 72,273	$ 69,335	$ 2,938	4.2 %
Loss from discontinued operations, net	$ (2,035)	$ (6,861)	$ 4,826	(70.3)%
Extraordinary item, net	$ -	$ 2,508	$ (2,508)	*
Net income applicable to common stock	$ 68,362	$ 63,112	$ 5,250	8.3 %

* Not meaningful

Consolidated net income from continuing operations for 2001 totaled $72.3 million, a 4.2% increase compared to 2000. The increase was primarily due to increased energy operations revenue and higher tolling revenue, partially offset by lower margins from energy trading, net, and lower base revenue from customer sales.

Cleco Power's slight decrease in net income from continuing operations of $0.7 million, or 1.2%, was primarily due to lower energy trading, net, lower base revenue from retail customer sales, and higher operating expenses. Partially offsetting the decreases were higher wholesale revenue and higher interest income resulting from a one-time recovery of fuel-related costs in 2001.

Midstream's net income from continuing operations increased $4.6 million, or 46.7%, in 2001 compared to 2000 primarily due to increased energy operations revenue and higher tolling revenue. The increases were partially offset by higher operating expenses and lower energy trading, net.

Consolidated net income applicable to common stock for 2001 compared to 2000 increased $5.3 million, or 8.3%, primarily due to increased energy operations revenue, higher tolling revenue, and a decrease in the loss from discontinued operations at UTS. For additional information on the UTS loss, see the Notes to the Consolidated Financial Statements, Note 17 - "Discontinued Operations." The increases were partially offset by the absence in 2001 of an extraordinary gain at Cleco Energy. For additional information on the extraordinary gain in 2000, see the Notes to the Consolidated Financial Statements, Note 7 - "Extraordinary Gain."

Cleco Power's Results of Operations- Year ended December 31, 2001, Compared to Year ended December 31, 2000

Cleco Power's net income applicable to member's equity for 2001 decreased $0.7 million compared to 2000. Factors contributing to the slight decrease include:

	lower energy trading, net,
	lower base revenue from retail customer sales, and
	higher other operations expenses.

These were partially offset by:

	lower maintenance expenses,
	a one-time adjustment for recovery of fuel-related costs, and
	higher interest income.

	For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)

Operating revenue
Base	$ 287,905	$ 294,486	$ (6,581)	(2.2)%
Fuel cost recovery	304,348	296,812	7,536	2.5 %
Estimated customer credits	(1,800)	(1,233)	(567)	46.0 %
Energy trading, net	1,456	4,495	(3,039)	(67.6)%
Other operations	30,813	28,230	2,583	9.1 %
Intercompany revenue	6,011	9,256	(3,245)	(35.1)%
Total operating revenue	628,733	632,046	(3,313)	(0.5)%

Operating expenses
Fuel used for electric generation	184,479	182,024	2,455	1.3 %
Power purchased for utility customers	139,913	136,176	3,737	2.7 %
Other operations	82,479	74,742	7,737	10.4 %
Maintenance	25,773	30,959	(5,186)	(16.8)%
Depreciation	50,594	49,787	807	1.6 %
Taxes other than income taxes	35,358	36,533	(1,175)	(3.2)%
Total operating expenses	518,596	510,221	8,375	1.6 %

Operating income	$ 110,137	$ 121,825	$ (11,688)	(9.6)%
Interest income	$ 6,498	$ 449	$ 6,049	*
Interest expense	$ 26,819	$ 28,722	$ (1,903)	(6.6)%

* Not meaningful
		For the year ended December 31,
		2001	2000	Change
		(Million kWh)
Electric sales
Residential		3,201	3,296	(2.9)%
Commercial		1,655	1,636	1.2 %
Industrial		2,640	2,883	(8.4)%
Other retail		581	578	0.5 %
Unbilled		34	162	(79.0)%
Total retail		8,111	8,555	(5.2)%
Sales for resale		398	334	19.2 %
Total on-system customer sales		8,509	8,889	(4.3)%
Short-term sales to other utilities		145	77	88.3 %
Sales from trading activities		19	81	(76.5)%
Total electric sales		8,673	9,047	(4.1)%

* Not meaningful

The following chart shows how cooling degree-days and heating degree-days in 2001 and 2000 varied from normal conditions and from the prior year for cooling and heating degree-days for 2001 and 2000. Before 2002, Cleco Power used an internally generated temperature reading to determine cooling and heating degree-days. In the fourth quarter of 2002, Cleco Power began to use temperature data collected by the NOAA for this purpose. Cooling and heating degree-days for 2001 and 2000 have been adjusted to reflect the change in the temperature data source.

	For the year ended December 31,
	2001	2000
Cooling Degree-Days:
Increase (Decrease) from Normal	(5.1)%	7.5 %
Increase (Decrease) from Prior Year	(11.4)%	0.9 %
Heating Degree-Days:
Increase (Decrease) from Normal	1.2 %	6.5 %
Increase (Decrease) from Prior Year	(5.2)%	27.0 %

Base

Base revenue during 2001 decreased $6.6 million, or 2.2%, compared to 2000. The decrease was primarily due to lower kWh sales as a result of decreased cooling-degree days and heating-degree days, as shown in the chart above.

Fuel Cost Recovery

Fuel cost recovery revenue collected from customers increased $7.5 million, or 2.5%, primarily due to an 8.8% increase in the average per unit cost of fuel used for electric operations for 2001 compared to 2000. For additional information on Cleco Power's ability to recover fuel and purchased power costs, see "- General Factors Affecting Cleco Power - Fuel and power purchased are primarily affected by the following factors," above.

Estimated Customer Credits

Revenue for 2001 was decreased by a $1.8 million accrual for estimated customer credits compared to a $1.2 million accrual for 2000. For additional information on the accrual for estimated customer credits, see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

Energy Trading, Net

The decrease in power and natural gas traded was primarily due to a less favorable power and natural gas sales market in 2001 compared to 2000. A summary of power and natural gas traded by Cleco Power for the periods indicated appears below.

	For the year ended December 31,
	2001	2000	Change
Power (Million kWh)	5.0	80.9	(93.8)%
Natural gas (MMBtu)	2,634,766	2,958,615	(10.9)%

In October 2002, the EITF rescinded EITF No. 98-10, which required certain energy contracts to be reported at fair market value or "marked-to-market." The amounts in the chart below and in this discussion of Cleco Power's energy trading, net, in 2001 and 2000 reflect the effects of EITF No. 98-10, since it was the accounting principle used to record trading activities during those time periods. Generally, Cleco Power's energy trading activity was, for the period indicated, considered "trading" under EITF No. 98-10, requiring open positions to be reported at fair market value or "marked-to-market." The chart following presents the components of energy trading, net.

For the year ended December 31,
	2001	20000	Variance	Change
	(Thousands)
Energy trading margins	$ 1,403	$ 3,870	$ (2,467)	(63.7)%
Mark-to-market	53	625	(572)	(91.5)%
Energy trading, net	$ 1,456	$ 4,495	$ (3,039)	(67.6)%

Energy trading, net, for 2001 compared to 2000 decreased $3.0 million, or 67.6%, primarily due to lower gains on gas and power sales and gas futures trading, partially offset by higher gains on gas options trading. For information on the rescission of EITF No. 98-10, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

Intercompany Revenue

Intercompany revenue decreased $3.2 million, or 35.1%, from 2000 to 2001. The decrease was primarily due to the reduction of labor hours billed to an affiliate.

Operating Expenses

Operating expenses increased $8.4 million, or 1.6%, for 2001 compared to 2000. Fuel used for electric generation increased $2.5 million, or 1.3%, primarily due to increased energy prices mainly driven by a 10.5% increase in the average per unit cost of natural gas. The increase was offset by a one-time $6.6 million adjustment for recognition of the recovery of fuel-related costs that had not been previously collected from utility customers. The fuel cost recovery was approved by the LPSC to be collected from customers and was therefore recognized, along with associated interest, in 2001. Power purchased for utility customers increased $3.7 million, or 2.7%, during 2001 compared to 2000 primarily due to a $6.4 million increase in capacity payments, and an 8.8% increase in the average per unit cost of fuel used for electric generation, partially offset by a 16.0% decrease in the averag e per unit cost of purchased power, all of which combined to make the purchase of power more economical than the generation of power. The $7.7 million, or 10.4%, increase in other operations expense was primarily due to a $3.8 million increase in vacation accrual and a $3.3 million increase in employee benefits. The $6.4 million, or 9.4%, decrease in maintenance and in taxes other than income taxes resulted primarily from lower general maintenance, lower right-of-way clearing expenses, and lower franchise taxes.

Interest Income

Interest income increased $6.0 million during 2001 compared to 2000 primarily due to interest related to the recognition of a one-time recovery of fuel-related costs that had not been previously collected from utility customers. Because the recovery of the fuel-related costs was a one-time adjustment, we do not expect the interest income in future periods to be as much as in 2001.

Midstream's Results of Operations - Year ended December 31, 2001, Compared to Year ended December 31, 2000

Midstream's net income for 2001 was $14.5 million, which was higher than the $12.4 million earned in 2000. Factors contributing to the increase include:

	higher energy operations revenue and
	higher tolling revenue.

These were partially offset by:

	higher operations expenses and
	lower energy trading, net.

	For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)

Operating revenue
Tolling operations	$ 60,522	$ 41,354	$ 19,168	46.4%
Energy trading, net	5,608	7,381	(1,773)	(24.0)%
Energy operations	58,659	3,601	55,058	*
Other operations	1,135	118	1,017	*
Intercompany revenue	13,947	37,667	(23,720)	(63.0)%
Total operating revenue	139,871	90,121	49,750	55.2%

Operating expenses
Purchases for energy operations	48,323	1,059	47,264	*
Other operations	33,984	43,644	(9,660)	(22.1)%
Maintenance	4,828	12,256	(7,428)	(60.6)%
Depreciation	9,379	5,952	3,427	57.6%
Taxes other than income taxes	1,402	2,005	(603)	(30.1)%
Total operating expenses	97,916	64,916	33,000	50.8%

Operating income	$ 41,955	$ 25,205	$ 16,750	66.5%

Equity income from investees	$ 175	$ -	$ 175	*

* Not meaningful

Tolling

Tolling operations revenue increased $19.2 million, or 46.4%, in 2001 compared to 2000. The increase was primarily due to the Evangeline facility operating for a full year in 2001. The facility began full commercial operation in July 2000. Partially offsetting the increase was a $5.6 million decrease in revenue caused by replacement power reimbursements from Williams Energy in 2000 that were not required during 2001. ��For additional information on tolling operations, see "- General Factors Affecting Midstream - Revenue is primarily affected by the following factors," above.

Energy Trading, Net

For 2001 compared to 2000, the increase in power and gas volumes was primarily due to expansion of Midstream's physical gas trading portfolio. A summary of power and natural gas traded by Midstream and its subsidiaries for the periods indicated appears below.

	For the year ended December 31,
	2001	2000	Change
Power (Million kWh)	3,278	1,274	157.3 %
Natural gas (MMBtu)	17,209,354	9,685,426	77.7 %

In October 2002, the EITF rescinded EITF No. 98-10, which required certain energy contracts to be reported at fair market value or "marked-to-market." The amounts in the chart below and in this discussion of Midstream's energy trading, net, in 2001 and 2000 reflect the effects of EITF No. 98-10, since it was the accounting principle used to record trading activities during those time periods. Midstream's energy trading activity is considered "trading" under EITF No. 98-10, requiring open positions to be reported at fair market value or "marked-to-market." The chart below presents the components of energy trading, net.

	For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)
Energy trading margins	$ 5,066	$ 7,817	$ (2,751)	(35.2)%
Mark-to-market	542	(436)	978	*
Energy trading, net	$ 5,608	$ 7,381	$ (1,773)	(24.0)%

* Not meaningful

Energy trading, net, for 2001 compared to 2000 decreased $1.8 million primarily due to the volatility in power and gas prices in 2001. For information on the rescission of EITF No. 98-10, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

Energy Operations

The increase of $55.1 million in energy operations revenue during 2001 compared to 2000 was primarily due to a 10.5% increase in the average per unit cost of natural gas and increased volumes of natural gas marketed at Cleco Energy, partially offset by decreased energy management services at Marketing & Trading. Intercompany volume and revenue have been eliminated and therefore are not reflected in the charts below. The chart immediately below presents the components of energy operations revenue.

	For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)
Energy management services	$ 763	$ 961	$ (198)	(20.6)%
Wholesale natural gas marketed	57,896	2,640	55,256	*
Energy operations	$ 58,659	$ 3,601	$ 55,058	*

* Not meaningful

The chart below presents a summary of natural gas marketed for the periods indicated.

	For the year ended December 31,
	2001	2000	Change
Natural gas (MMBtu)	11,398,704	8,926,303	27.7 %

Natural gas sales volume increased due to new long-term supply and spot contracts entered into in 2001.

Intercompany Revenue

Intercompany revenue decreased $23.7 million, or 63.0%, in 2001 compared to 2000. The decrease was primarily due to reduced billings caused by the transfer of employees to other affiliates.

Operating Expenses

Purchases for energy operations increased $47.3 million for 2001 compared to 2000 primarily due to the same factors that affected energy operations revenue. Other operations and maintenance expenses decreased a net $17.1 million, or 30.6%, for 2001 compared to 2000 primarily due to lower administrative expenses due to the transfer of employees to other affiliates. Depreciation expense for 2001 compared to 2000 increased $3.4 million, or 57.6%, because Evangeline operated for a full year compared to only six months in 2000. This increase was partially offset by a decrease in depreciation expense at Evangeline LLC due to a July 2001 change in the estimated life of Evangeline. For additional information regarding the lengthening of the depreciable life of the facility, see the Notes to the Consolidated Financial Statements, Note 15 - "Change in Accounting Estimate."

Equity Income from Investees

Equity income from investees increased $0.2 million in 2001 compared to 2000 primarily due to increased equity earnings from PEP, where Perryville commenced commercial operations of a simple cycle 157-MW combustion turbine in July 2001. For additional information regarding our investment in PEP, see the Notes to the Consolidated Financial Statements, Note 21 - "Acquisition."

Discontinued Operations

In December 2000, management decided to sell substantially all of the UTS assets and to discontinue UTS operations after the sale. On March 31, 2001, management signed an asset purchase agreement to sell UTS to Quanta Services, Inc. (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.

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

At December 31, 2002, UTS had nominal assets since receivables had been either collected or charged against the reserve.

Additional information about UTS follows:

	For the year ended December 31,
	2002	2001	2000
	(Thousands)
Revenue	$ -	$ 5,043	$18,125
Pretax loss from operations of UTS	$ -	$ -	$ 8,801
Income tax benefit associated with loss from operations	$ -	$ -	$ 3,390
Pretax loss from disposal of UTS	$ -	$ 3,310	$ 2,358
Income tax benefit associated with loss on disposal	$ -	$ 1,275	$ 908

For additional information on the UTS loss, see the Notes to the Consolidated Financial Statements, Note 17 - "Discontinued Operations."

Extraordinary Gain

In March 2000 Four Square Gas, a wholly owned subsidiary of Cleco Energy, which is wholly owned by Midstream, paid a third party $2.1 million for a note with a face value of approximately $6.0 million. The note was issued by Four Square Production, another wholly owned subsidiary of Cleco Energy, and relates to the production assets held by Four Square Production. As part of the transaction, the third-party debt-holder sold the note, associated mortgage, deed of trust, and pledge agreement and assigned a 5% overriding royalty interest in the production assets to Four Square Gas. Four Square Gas paid, in addition to the $2.1 million, a total of 4.5% in overriding royalty interest in the production assets. Four Square Gas borrowed the $2.1 million from Cleco Corporation. The gain of approximately $3.9 million was offset against the $1.4 million of income tax relat ed to the gain to arrive at the extraordinary gain, net of income tax, of approximately $2.5 million. For additional information on the extraordinary gain, see the Notes to the Consolidated Financial Statements, Note 7 - "Extraordinary Gain."

CRITICAL ACCOUNTING POLICIES

Our critical accounting policies are those accounting policies that are both important to the portrayal of our financial condition and results of operations and 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 our segments or to us 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 us 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 a change in circumstances or environment. Actual results may differ significantly from these estimates under different assumptions or conditions.

We believe the following are our most significant critical accounting policies.

Transactions between Cleco Power and other subsidiaries of ours are generally governed by rules and regulations issued by the LPSC and FERC. Transactions between Cleco Power and other subsidiaries are recorded assuming they are in accordance with the applicable rules and regulations. During 2002, several instances of possible non-compliance with the LPSC and FERC rules and regulations were discovered, and amounts were recorded on Cleco Power's and other subsidiaries' books in order to reflect the estimated financial impact of the possible violations. For additional information on these transactions, see the Notes to the Consolidated Financial Statements, Note 19 - "Review of Trading Activities," and Note 22 - "Gas Transportation Charges."

We account for pensions and other postretirement benefits under SFAS No. 87, "Employers' Accounting for Pensions." To determine assets, liabilities, income, and expense relating to pension and other postretirement benefits, we must make assumptions about future trends. Assumptions and estimates include, but are not limited to, discount rate, expected return on plan assets, future rate of compensation increases, and medical inflation trend rates. These assumptions are reviewed and updated on an annual basis. Changes in the rates from year to year could have a material effect on our financial condition and results of operations by changing the recorded assets, liabilities, income or expense. For additional information on pensions and other postretirement benefits, see the Notes to the Consolidated Financial Statements, Note 9 - "Pension Plan and Employee Benefits."

Cleco Power

Generally, Cleco Power is affected more by the decisions of the LPSC than by market conditions. The LPSC has authority over several critical areas of Cleco Power. The most important are listed below.

	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, 2002, 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 are impaired.
	The LPSC determines the ability of Cleco Power to recover regulatory assets that are recorded according to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Cleco Power has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At December 31, 2002, Cleco Power has $91.2 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 the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Regulation."
	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. For the years ended December 31, 2002, 2001, and 2000, Cleco Power reported fuel revenue of $262.7 million, $304.3 million, and $296.8 million, respectively. For additional information on the LPSC and the fuel adjustment clause, see "- Financial Condition - Retail Rates of Cleco Power" and "- Results of Operations - General Factors Affecting Cleco Power - Fuel and power purchased are primarily affected by the following factors."
	Cleco Power has recorded a liability of $3.3 million for estimated customer credits it expects to refund to its retail ratepayers pursuant to a settlement agreement with the LPSC limiting Cleco Power's return on equity. The LPSC has the right to audit the filing under the settlement and has done so in the past. If the LPSC's findings concerning estimated customer refunds are different from those expected, Cleco Power could be required to adjust the liability. For additional information on estimated customer credits, see "- Financial Condition - Retail Rates of Cleco Power."

Midstream

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

Midstream accounts for the Evangeline Tolling Agreement as an operating lease. If the tolling agreement were to be modified to the extent that would make lease accounting no longer appropriate, future results could materially differ from those currently reported. Under current lease accounting rules, Evangeline LLC will recognize over the first 10 years of the tolling agreement revenue that will not be billed and collected until the last 10 years of the tolling agreement. If lease accounting were to cease, the revenue would be recognized as billed, causing the revenue recognized in the first 10 years to be lower than what it would have been under lease accounting. As of December 31, 2002, Evangeline LLC had recorded $10.4 million in revenue that will not be billed and collected until the last 10 years of the tolling agreement, beginning in the year 2010. If the tolling agreement is substantially modified, the $10.4 million may not be c ollectible, and Evangeline LLC may be required to incur a loss of some or all of the $10.4 million. Midstream also accounts for the Perryville Tolling Agreement as an operating lease. However, the Perryville Tolling Agreement has different provisions that do not require the acceleration of revenue to early years of the contract. If the Perryville Tolling Agreement was modified to the extent that would make lease accounting no longer appropriate, PEP's revenue would not decrease in the manner described for the Evangeline Tolling Agreement, but would be affected by the modifications to the tolling agreement. If the modifications are significant, PEP's revenue could be materially lower than reported in 2002 or lower than projected revenue. For additional information on the tolling agreements, see the Notes to the Consolidated Financial Statements, Note 14 - "Operating Leases."

Certain triggering events could cause Midstream to determine that its long-lived assets may be impaired according to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Triggering events include, but are not limited to, a significant decrease in the market value of long-lived assets, significant changes in a tolling agreement counterparty's financial condition, a significant change in legal factors, such as adverse changes in environmental laws, or a current operating or cash flow loss combined with a projection of continued losses in the future. At December 31, 2002, Midstream had $546.9 million in long-lived assets. If Midstream determines the carrying value of a long-lived asset cannot be recovered

through cash flows relating to that long-lived asset, the asset would be written down to its fair market value, resulting in an impairment loss. During the fourth quarter of 2002, Midstream recorded an impairment loss of $3.6 million relating to its oil and natural gas production properties. For additional information on the impairment loss, see the Notes to the Consolidated Financial Statements, Note 24 - "Impairment of Long-Lived Asset."

FINANCIAL CONDITION

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, our credit rating, the credit rating of our subsidiaries, the operations of projects funded and the credit ratings of project counterparties. On July 25, 2002, Standard & Poor's placed Cleco Corporation's rating on credit watch with negative implications, and on October 7, 2002, Moody's placed Cleco Corporation's rating on review for potential downgrade and changed Cleco Power's rating outlook to negative. On November 14, 2002, Moody's placed Cleco Power's rating on review for potential downgrade, and on November 15, 2002, Standard & Poor's lowered the credit ratings of the senior unsecured debt of C leco Corporation from BBB to BBB- and Cleco Power from BBB+ to BBB. At December 31, 2002, Moody's credit ratings of the senior unsecured debt of Cleco Corporation and Cleco Power were Baa1 and A3, respectively. Cleco expects Standard & Poor's and Moody's to complete their reviews before the end of the first quarter of 2003. If Cleco Corporation's or Cleco Power's credit rating were to be downgraded, 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 our tolling counterparties are The Williams Companies, Inc., Mirant, Aquila, 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 credit watch for possible further downgrade by one or more rating agencies. The rating of the bonds issued by Evangeline LLC to finance the Evangeline facility was downgraded below investment grade to Ba3 by Moody's on October 2, 2002. In its press release announcing this downgrade, Moody's stated that the deterioration in The Williams Companies, Inc. credit rating had in turn exerted downward pressure on Evangeline LLC's rating. On November 27, 2002, the bonds were further downgraded by Moody 's to B3. For information on possible consequences resulting from failure of our counterparties to perform their obligations under the tolling agreements and recent events relating to the tolling agreements, see "- Results of Operations - General Factors Affecting Midstream - Revenue is primarily affected by the following factors."

Under power and gas trading agreements entered into by Marketing & Trading with various counterparties, the counterparties have the right to request us to provide credit support if the counterparty assesses our creditworthiness as unsatisfactory. Credit support can be provided either by posting a letter of credit, a cash prepayment, posting collateral or security acceptable to the counterparty, a guarantee agreement executed by an entity assessed as creditworthy, or any other mutually acceptable method. Events that may affect a counterparty's assessment of our creditworthiness include defaulting on a contract, exceeding trading limits, debt ratedbelow investment grade by at least one rating agency, substantial changes in power market prices, or any other material adverse change in our financial condition. We may elect to provide the requested credit support or refuse to pro vide the credit support. If we refuse to provide credit support, the requesting counterparty may require us to liquidate all transactions with that counterparty and pay the counterparty any current amounts outstanding plus the net present value of the mark-to-market gains and losses on all open future positions with the counterparty, less any current amounts receivable from the counterparty. If a counterparty were to request us to provide credit support, we would compare the amount of collateral required to the cost of liquidating the transaction and choose the option that minimizes the amount of cash or other assets needed to satisfy the counterparty. As of December 31, 2002, the amount we would have been required to pay if all power and gas trading counterparties requested credit support, and we exercised our option not to provide credit support, was approximately $6.8 million. If we instead elected to provide the requested credit support on all transactions outstanding and did not exercise our right to liquidate the transactions, we would have been required to post approximately $8.6 million in credit support as of December 31, 2002. Our decision, during the fourth quarter of 2002, to no longer engage in speculative trading activities will significantly reduce the amount of required credit support relating to our trading activities. However, the amount we are required to pay at any point in the future remains dependent on changes in the market price of power and gas, the changes

in open power and gas positions and changes in the amount counterparties owe us. Changes in any of these factors could cause the amount of requested credit support to increase or decrease, perhaps significantly.

Debt

At December 31, 2002, and 2001, we had $315.3 million and $179.6 million, respectively, of short-term debt outstanding in the form of commercial paper and bank loans. If we were to default under covenants in our various credit facilities, we would be unable to borrow additional funds from the credit facilities. If our credit rating, as determined by outside rating agencies, were to be downgraded we would be required to pay additional fees and higher interest rates. At December 31, 2002, we were in compliance with the covenants in our credit facilities.

The following table shows short-term debt by subsidiary:

	At December 31,
Subsidiary	2002	2001
	(Thousands)
Cleco Corporation (Holding Company Level)
Commercial paper	$ -	$ 36,933
Bank loans	171,550	77,000
Cleco Power
Commercial paper	-	63,742
Bank loans	107,000	-
Midstream
Bank loans	36,750	-
Cleco Energy
Bank loans	-	1,880

Total	$ 315,300	$ 179,555

Cleco Corporation (Holding Company Level)

Short-term debt increased at Cleco Corporation by $57.6 million at December 31, 2002 compared to December 31, 2001, in order to fund project development at Midstream. A revolving credit facility for Cleco Corporation in the amount of $225.0 million, scheduled to terminate on June 4, 2003, provides for an optional conversion to a one-year term loan. Cleco Corporation entered into the facility in June 2002 in replacement of a $200.0 million facility that expired in June 2002. The facility provides support for the issuance of commercial paper and working capital and other needs. At December 31, 2002, there was $171.5 million drawn on the facility, leaving $53.5 million available. The $53.5 million at December 31, 2002, was further reduced by off-balance sheet commitments of $49.2 million, leaving an actual available balance of $4.3 million. At December 31, 2002, Cl eco Corporation's borrowing rate under this facility was equal to the London Interbank Offered Rate (LIBOR) plus 0.85%, and the weighted average interest rate on the borrowings was 2.62%. In July 2002, the facility was amended to exclude Evangeline LLC from conditions that otherwise would have created an event of default if Evangeline failed to make payments in respect of any of its material obligations. If Cleco Power or Midstream default under their respective facilities, then Cleco Corporation would be considered in default under this facility. When the facility expires, we intend to renew it or enter into a similar agreement with substantially similar terms. However, since many banks have reduced their credit exposure in general, and limited utility credit specifically, we cannot be assured we will be successful in renewing the facility under substantially similar terms. If we cannot renew the facility, we have the option to exercise a conversion to a one-year term loan. Off-balance sheet commitments entered into by us with third parties for certain types of transactions between those parties and our 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. For more information about these commitments see "- Cash Generation and Cash Requirements - Off-Balance Sheet Commitments." In addition, certain indebtedness incurred by Cleco Corporation outside of the facility will reduce the amount of the facility available to it. The amount of such commitments and other indebtedness incurred by Cleco Corporation and reduction of the available amount of the facility was $49.2 million at December 31, 2002, and $70.1 million at December 31, 2001. An uncommitted line of credit with a bank in an amount up to $5.0 million is also available to support Cleco Corporation's workin g capital needs.

On August 23, 2002, a portion of the PEP construction loan was converted to a loan with Mirant in the amount of $100.0 million. On October 1, 2002, the remainder of PEP's $151.9 million construction loan was terminated and replaced with a five-year loan with a group of lenders led by KBC Bank N.V. (KBC) acting as agent (the KBC loan) in the amount of $145.8 million, after savings on construction were applied. The interest rate on both loans resets quarterly. It is based on LIBOR plus a spread, and the rate at December 31, 2002, was 3.28%. The spread is 1.50% for the first two years and 1.65% for the remaining three years. The loans provide for quarterly principal and interest payments. Cleco provides a guarantee to pay interest and principal under the KBC loan should PEP be unable to pay its debt service. At December 31, 2002, the amount guaranteed was $6 .9 million. Also, under the terms of the KBC loan, specified amounts are required to be maintained in restricted cash accounts for debt service payments, major maintenance, and operating needs. At December 31, 2002, there was $7.2 million in these restricted cash accounts. Pursuant to the Construction Management Services Agreement (CMSA) between PEP and KBC, PEP will pay performance damages of approximately $7.3 million by the end of the first quarter of 2003 for failure to achieve performance guarantees within the required timeframe. The payment will be placed in a restricted liquidated damages account and applied towards the loan balance. The CMSA provides that this payment will be the sole and exclusive remedy by PEP for liquidated damages. The KBC loan is collateralized by Cleco Corporation's membership interest in PEP. The Mirant loan also is collateralized by Cleco Corporation's membership interest in

PEP, subordinate to claims under the KBC loan. The KBC loan is scheduled to mature on October 1, 2007, and the Mirant loan is scheduled to mature on December 31, 2007.

Cleco Power

Short-term debt increased at Cleco Power by $43.3 million at December 31, 2002, compared to December 31, 2001, primarily due to the draws under its line of credit that were made in order to manage its liquidity because of uncertainties in the commercial paper market. A revolving credit facility for Cleco Power in the amount of $107.0 million, scheduled to terminate on June 4, 2003, provides for an optional conversion to a one-year term loan. Cleco Power entered into the facility in June 2002 in replacement of a $100.0 million facility that expired in June 2002. The facility provides support for the issuance of commercial paper and working capital needs. At December 31, 2002, Cleco Power's borrowing rate under this facility was equal to LIBOR plus 0.75%, and the weighted average interest rate on the borrowings was 2.30%. When the facility expires, Cleco Power intends to ren ew it or enter into a similar agreement with substantially similar terms. However, since many banks have reduced their credit exposure in general, and limited utility credit specifically, we cannot be assured that Cleco Power will be successful in renewing the facility under substantially similar terms. If Cleco Power cannot renew the facility, it has the option to exercise a conversion to a one-year term loan. An uncommitted line of credit with a bank in an amount up to $5.0 million is also available to support Cleco Power's working capital needs.

On February 8, 2002, Cleco Power issued $25.0 million aggregate principal amount of its 6.125% Insured Quarterly Notes. The notes mature on March 1, 2017, but are redeemable at the option of Cleco Power on or after March 1, 2005. The proceeds of the notes were used to repay short-term debt in the form of commercial paper.

On May 9, 2002, Cleco Power issued $50.0 million aggregate principal amount of its 6.05% Insured Quarterly Notes. The notes mature on June 1, 2012, but are redeemable at the option of Cleco Power on or after June 1, 2004. The proceeds of the notes were used to repay short-term debt in the form of commercial paper.

On June 14, 2002, Cleco Power gave formal notice of its intention to call $15.0 million of 7.55% medium-term notes due July 15, 2004, and $10.0 million of 7.50% medium-term notes due July 15, 2004. Both series of notes became redeemable at Cleco Power's option on July 15, 2002. The notes were repaid on July 15, 2002, with proceeds from commercial paper issuances.

Midstream

Short-term debt increased at Midstream by $34.9 million at December 31, 2002, compared to December 31, 2001, primarily due to additional funding of project development.

Midstream has a $36.8 million revolving credit facility that expires in March 2004. In June 2001, Midstream entered into the facility which was initially scheduled to expire in June 2002. Through amendments in June and August 2002, the facility was extended to its current expiration date. The facility is used to support Midstream's generation activities, and outstanding balances are guaranteed by Cleco Corporation on a subordinated basis. Midstream's borrowing rate under this facility was equal to LIBOR plus 2.50% and was 4.375% at December 31, 2002.

Cleco Energy

On September 30, 2002, Cleco Energy paid off the outstanding balance of $8.0 million on its $10.0 million credit facility with Compass Bank. Cleco Energy had entered into this $10.0 million facility in July 2000. The facility was guaranteed by Cleco Corporation and collateralized by Cleco Energy assets.

Other

Various agreements to which we are subject contain covenants that restrict our 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, 2002, $29.7 million of cash was restricted under the Evangeline LLC senior secured bond indenture, $22.2 million of cash was restricted under an agreement with the lenders for PEP, and $1.8 million of Acadia Power Holding LLC's (APH - the entity through which Midstream owns an interest in APP) cash was restricted under the terms of the Midstream credit facility.

Cash Generation and Cash Requirements

Cash Flows

Cash flows from operating activities during 2002 generated $165.5 million, as shown in the Consolidated Statements of Cash Flows. Net cash provided by operating activities primarily resulted from net income, adjusted for non-cash charges to income, and changes in working capital. The increase of $40.9 million of net cash provided by operating activities for 2002 compared to 2001 is primarily due to an increase in deferred income taxes. This increase is a direct result of book and tax capitalization and depreciation timing differences. The net cash used in investing activities during 2002 of $181.4 million primarily related to additions to property, plant and equipment and changes in nonutility investments. The increase of $6.2 million of net cash used in investing activities for 2002 compared to 2001 is primarily due to increased additions to property, plant and equipment, partially offset by a decrease in equity investment in investees. Net cash provided by financing activities during 2002 of $118.3 million resulted principally from the issuance of common stock, long-term debt and short-term debt. Net cash provided by financing activities was

reduced by the payment of dividends to shareholders and the retirement of medium-term notes at Cleco Power. The increase of $85.1 million of net cash provided by financing activities for 2002 compared to 2001 is primarily due to the issuance of common stock and long-term debt during 2002.

Our 2003 expenditures for construction, investment, and debt maturity are estimated to total $109.0 million, and for the five-year period ending 2007 are expected to total $872.6 million. We believe that our cash and cash equivalents on hand, together with cash generated from our operations, borrowings from credit facilities, and the net proceeds of any issuances under our shelf registration statements, will be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.

Shelf Registrations

At December 31, 2002, Cleco Corporation had $100.0 million remaining on a $200.0 million shelf registration statement that allows for the issuance of its debt securities. In addition, Cleco Corporation had $104.0 million remaining on a $150.0 million shelf registration statement that allows for the issuance of common stock or preferred stock or any combination thereof. On May 8, 2002, Cleco Corporation issued 2.0 million shares of common stock in a public offering pursuant to the $150.0 million registration statement. Net proceeds from the issuance were approximately $44.3 million and were used to acquire Mirant's 50% interest in PEP. For additional information on the acquisition, see "- New Power Plants," below.

At December 31, 2002, Cleco Power had $125.0 million remaining on a $200.0 million shelf registration statement that allows for the issuance of its debt securities. On January 16, 2002, the LPSC approved the issuance of $200.0 million aggregate principal amount of medium-term notes and retail notes pursuant to this registration statement. On February 8, 2002, Cleco Power issued $25.0 million of its 6.125% Insured Quarterly Notes due March 1, 2017, and on May 9, 2002, Cleco Power issued $50.0 million of its 6.05% Insured Quarterly Notes due June 1, 2012, in each case pursuant to this registration statement. The proceeds from the issuances of the notes were used to reduce Cleco Power's commercial paper balance.

Construction and Investment in Subsidiaries Overview

We have divided our construction and investments along our 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, may be passed on to its ratepayers. Those assets earn a rate of return restricted 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 consist of assets whose rate of return is largely determined by the market, not by regulators. Examples of this type of construction are the repowering or construction of generating facilities, additions to gas pipeline transmission systems, and investments in a joint ven ture engaged in constructing and owning power plants.

Cleco Power Construction

Cleco Power's construction expenditures, excluding Allowance for Funds Used During Construction (AFUDC), totaled $87.3 million in 2002, $45.6 million in 2001, and $47.9 million in 2000. The increase in construction expenditures from 2001 to 2002 is primarily due to storm restoration costs. For additional information on storm restoration costs, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Storm Restoration Costs."

Cleco Power's construction expenditures, excluding AFUDC, for 2003 are estimated to be $60.3 million, and for the five-year period ending 2007 are expected to total $311.8 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 will continue to invest in technology to allow it to operate more efficiently.

In 2002, 2001, and 2000, 100% of Cleco Power's construction requirements were funded internally. In 2003, 86.0% of construction requirements are expected to be funded internally. For the five-year period ending 2007, 89.3% of the construction requirements are expected to be funded internally. Cleco Power's remaining construction requirements are expected to be funded through additional borrowings or the issuance of additional debt.

Midstream Construction and Investment in Subsidiaries

Midstream's construction expenditures totaled $3.6 million in 2002, $3.2 million in 2001, and $60.3 million in 2000. Cash investments in subsidiaries, as discussed below, totaled $94.4 million in 2002, $133.1 million in 2001, and $97.2 million in 2000. Total construction and investment in subsidiaries totaled $98.0 million in 2002, $136.3 million in 2001, and $157.5 million in 2000.

Midstream is currently participating in one joint venture, APP, which is 50% owned by Midstream and 50% owned by Calpine. APP 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 APP were $502.7 million. APH capitalized $19.5 million of costs, which consist of interest and other miscellaneous charges related to the construction of APP. As of December 31, 2002, Midstream's equity in APP was $273.0 million. Midstream funded its investment in APP through an intercompany loan from Cleco Corporation, and Cleco Corporation funded the intercompany loan through its credit facility. We currently do not expect to obtain project level financing in 2003 for our equity interest in APP.

PEP, currently a wholly owned subsidiary of Midstream, but originally a joint venture with Mirant, constructed a 725-MW, natural gas-fired power plant in Perryville, Louisiana. Total construction costs of the plant incurred by PEP were approximately $325.5 million, including capitalized interest. A 157-MW combustion turbine commenced simple-cycle operation in the summer of 2001. Full commercial operation of a 568-MW combined-cycle unit began in the summer of 2002. 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 PEP. For additional information regarding this purchase, see the Notes to the Consolidated Financial Sta tements, Note 21 - "Acquisition."

Midstream's 2003 expenditures for construction and investment in subsidiaries are estimated to total $2.3 million and for the five-year period ending 2007 are expected to total $7.3 million. Most of the planned construction and investment in the five-year period will consist of general production assets.

In 2002, 56.4% of Midstream's construction and investment in subsidiaries requirements were funded internally, compared to 19.2% in 2001 and 15.3% in 2000. In 2003, 100.0% of Midstream's construction and investment in subsidiaries requirements are expected to be funded internally. For the five-year period ending 2007, 100.0% of Midstream's construction and investment in subsidiaries requirements are expected to be funded internally.

Other Subsidiary Construction

Other subsidiaries had construction expenditures of $5.0 million during 2002, $3.9 million during 2001, and $5.1 million during 2000. These expenditures related to the installation of new financial software by Cleco Support Group LLC (Support Group) in order to meet the growing needs of Cleco and its subsidiaries. These additions were subsequently allocated to Cleco Power and Midstream and are reflected in their construction expenditure amounts. The amounts allocated to Cleco Power and Midstream were $6.2 million in 2002 and $3.4 million in 2001. No allocations were made in 2000. Other construction expenditures for 2003 are estimated to total $1.0 million and for the five-year period ending 2007 are expected to total $2.0 million. The majority of the planned other construction in the five-year period will go toward the installation and upgrade of computer hardwa re and software for Support Group.

Other Cash Requirements

Scheduled maturities of debt will total $45.4 million for 2003, and $551.5 million for the five-year period ending 2007. In 1991, we began a common stock repurchase program in which up to $30.0 million of common stock may be repurchased. At December 31, 2002, approximately $16.1 million of common stock was available for repurchase under this program. Purchases will be 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. We did not purchase any common stock under the repurchase plan in 2002 or 2000, but did purchase $3.0 million of common stock during 2001.

The following chart summarizes our cash contractual obligations by year:

	Payments Due by Period
Contractual obligations	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Cleco Corporation	$ 202	$ 99,995	$ -	$ -
Cleco Power	25,000	60,000	90,000	186,260
Midstream	20,199	28,242	227,871	177,059
Total long-term debt	$ 45,401	$ 188,237	$ 317,871	$ 363,319

Cleco Power and our three unregulated power plants are our 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, 2002, and 2001, we had internally generated cash of $165.5 million and $124.6 million, respectively, that was available for the repayment of long-term debt and funding of our construction expenditures.

Off-Balance Sheet Commitments

We have 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 our subsidiaries and an equity investee (affiliates). We entered into these off-balance sheet commitments in order to entice desired counterparties to contract with our affiliates by providing some measure of compensation to the counterparty if our affiliate does not fulfill certain contractual obligations. If we had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with our affiliates, or may have contracted with them at terms less favorable to our affiliates.

The off-balance sheet commitments are not recognized on our Consolidated Balance Sheet because we have determined that our affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco Corporation 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 has a schedule of off-balance sheet commitments grouped by the affiliate on whose behalf each commitment was made. The schedule shows the face amount of the commitment, any reductions, the net amount, and reductions in Cleco Corporation's ability to draw on its credit

facility at December 31, 2002. Significant changes occurring subsequent to December 31, 2002, 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 convey the impact of the off-balance sheet commitments on our financial condition.

	At December 31, 2002
Subsidiaries/Affiliates	Faceamount	Reductions	Net amount	Reductions to the amount available to be drawn on Cleco Corporation'scredit facility
	(Thousands)
Acadia Power Holdings LLC
Guarantees issued to:
APP Tolling Agreement counterparty (Aquila Energy)	$ 12,500	$ -	$ 12,500	$ 12,500
APP plant construction contractor	1,352	-	1,352	1,352

Perryville Energy Holdings LLC
Guarantees issued to:
PEP Tolling Agreement counterparty	13,500	-	13,500	13,500
PEP debt service reserve	6,852	-	6,852	6,852

Midstream
Subordinated guarantee issued to bank	36,750	-	36,750	-

Marketing & Trading
Guarantees issued to various trading counterparties	216,250	117,000	99,250	-

Evangeline LLC
Standby letter of credit issued to Tolling Agreement counterparty	15,000	-	15,000	15,000

	$ 302,204	$ 117,000	$ 185,204	$ 49,204

If APP, PEP, or Evangeline LLC fails to perform certain obligations under its respective tolling agreement, Cleco Corporation will be required to make payments to the respective tolling agreement counterparties of APP, PEP or Evangeline LLC under the commitments listed in the above table. Cleco Corporation's obligations under the APP and PEP commitments are in the form of guarantees and are limited to $12.5 million and $13.5 million, respectively. Cleco Corporation's obligation under the Evangeline LLC commitment is in the form of a standby letter of credit from investment grade banks and is limited to $15.0 million. If Cleco Corporation's credit rating should fall below investment grade, as defined by either Moody's or Standard & Poor's, Cleco Corporation would be required to post a $12.5 million letter of credit from an investment grade bank in favor of one of the counterparties to one of APP 's Tolling Agreements in lieu of the $12.5 million guarantee. Ratings triggers do not exist in the PEP and Evangeline Tolling Agreements. Our management expects APP, PEP, and Evangeline LLC to be able to meet their respective obligations under the tolling agreements and does not expect Cleco Corporation to be required to make payments to the counterparties. However, under the covenants associated with Cleco Corporation's credit facility, the entire net amount of the commitments reduces the amount we can borrow under the credit facility. The guarantees for APP and PEP are in force until 2022. The letter of credit for Evangeline LLC is expected to be renewed annually until 2020.

If APP or PEP cannot pay the contractors who built their plants, Cleco Corporation will be required to pay the current amount outstanding. Cleco Corporation's obligation under the PEP arrangement is in the form of a guarantee and is limited to the lesser of the balances of invoices outstanding or $24.0 million. At December 31, 2002, the current contractor's amount outstanding was $0.4 million, and there was $7.2 million in a restricted cash account at KBC available to pay the contractor and other construction expenses, which reduced Cleco Corporation's exposure in respect of this obligation to zero. Perryville began commercial operation on July 1, 2002, and that guarantee will cease upon full payment of the PEP construction contracts. Cleco Corporation's obligation under the APP arrangement is in the form of a guarantee and is limited to 50% of the total for the current contractor's amou nt outstanding. At December 31, 2002, Cleco Corporation's 50% portion of the current contractor's amount outstanding was approximately $1.4 million. Acadia began commercial operation in August 2002, and that guarantee will cease upon full payment of the APP construction contracts. Our management expects both APP and PEP to have the ability to pay their respective contractor as scheduled and does not expect Cleco Corporation to pay on behalf of the subsidiaries. However, under the covenants associated with Cleco Corporation's credit facility, the current monthly amount due to the APP contractor reduces the amount Cleco Corporation can borrow under the credit facility.

Midstream's purchase of Mirant's 50% ownership interest in PEP during the second quarter of 2002 increased Midstream's ownership of PEP to 100%. Cleco Corporation's guarantees to the PEP Tolling Agreement counterparty did not change. The plant construction contractor guarantee increased to include 100% of the outstanding contractor's invoice balance.

On October 1, 2002, Cleco Corporation paid the remaining $15.9 million of its $36.0 million equity subscription in favor of PEP; the remainder of PEP's $151.9 million construction loan was terminated and replaced with a five-year loan in the amount of $145.8 million, after savings on construction were applied; and a $6.9 million guarantee was issued by Cleco Corporation to PEP's lenders. If PEP is unable to pay principal and interest payments, Cleco Corporation will be required to pay up to $6.9 million on behalf of PEP.

When Midstream entered into a $36.8 million revolving 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, 2002, there was $36.8 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.

In the fourth quarter of 2002, Cleco Corporation fully funded the $250.0 million due to APP under APP's Partnership Agreement by paying the $0.4 million remaining in respect of that obligation.

Cleco Corporation has issued guarantees to Marketing & Trading's counterparties in order to facilitate energy trading. 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 balance of net guarantees for Marketing & Trading does not affect the amount Cleco Corporation can borrow under its credit facility. However, the total amount of guaranteed net open positions with all of Marketing & Trading's counterparties over $20.0 million reduces the amounts Cleco Corporation can borrow under its credit facility. At December 31, 2002, the total guaranteed net open positions were $2.8 million, so the borrow ing restriction in our credit facility was not affected. From time to time, Marketing & Trading may trade with new counterparties, and we expect that Cleco Corporation may be required to issue guarantees to these new counterparties. Marketing & Trading may also change the amount of trading with current counterparties and/or stop trading with current counterparties. As counterparties and amounts traded change, corresponding changes will be made in the level of guarantees issued by Cleco Corporation. We anticipate that our decision to cease speculative trading will decrease the level of guarantees required as current positions close and fewer new positions are opened. For information regarding Marketing & Trading's counterparties' right to request Cleco Corporation to provide credit support in certain instances, see "- Liquidity and Capital Resources - General Considerations and Credit-Related Risks."

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

		Amount of Commitment Expiration Per Period
Commercial commitments	Net amount committed	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Guarantees	$ 170,204	$ 137,352	$ -	$ 6,852	$ 26,000
Standby letter of credit	15,000	-	-	-	15,000
Total commercial commitments	$ 185,204	$ 137,352	$ -	$ 6,852	$ 41,000

Inflation

Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged approximately 2.6% during the three years ended December 31, 2002. We believe inflation, at this level, does not materially affect our results of operations or financial position. However, under existing regulatory practice, only the historical cost of 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.

Environmental Matters

We are 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. We have obtained all material environmental permits necessary for our operations and believe we are in substantial compliance with these permits, as well as all applicable environmental laws and regulations. We anticipate that existing environmental rules will not affect operations significantly, but some capital improvements may be required in response to new environmental programs expected in the next few years.

We continue to monitor potential multi-pollutant legislation pending in Congress. While it is unknown at this time what the final outcome of the legislation 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.

Another new regulatory program, Section 316(b) of the Clean Water Act, which deals with water intake structures, may require some capital improvements to several of our generation facilities. The regulations are currently being developed with a projected publication date of February 2004 and, therefore, the capital and operating costs are not known at the present time. We anticipate that any new requirements will be established as the facilities go through the National Pollutant Discharge Elimination System discharge permit renewal process and will be established on a site-specific basis.

Implementation of Phase I of the Clean Air Act did not require us to reduce sulfur emissions at Cleco Power's solid-fuel generation units, which either burn low-sulfur coal or utilize pollution control equipment. Installation of continuous emission monitoring equipment on Cleco Power's generation units was completed in 1996 at a cost of approximately $3.0 million. Although Phase II of the legislation, which became effective in 2000, involves more stringent limits on emissions in 2008, we do not expect these requirements will require substantial capital investments or significantly affect the operation of our generation units.

Some capital investment will be necessary to comply with the various regulatory requirements. The following table lists capital expenditures for environmental matters by subsidiary.

Subsidiary	Capital expenditures for 2002	Projected capital expenditures for 2003
	(Thousands)
Cleco Power	$ 735	$ 1,087
Evangeline LLC	57	-
Perryville	3,120	-
Acadia	1,625	-
Total	$ 5,537	$1,087

In late December 2002, Acadia was issued a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (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. Although the LDEQ may ultimately impose a penalty on APP and/or Evangeline as a result of these exceedances, management does not believe any such penalty will have a material adverse effect on our financial condition or results of operations.

Industry Developments / Customer Choice

Increased competition in the electric utility industry is driven by complex economic, technological, legislative, and regulatory factors. These factors have resulted in the introduction of federal and state legislation and other regulatory initiatives that could produce even greater competition at both the wholesale and retail levels in the future. 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. In 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 organize a series of collaboratives to more fully explore the unresolved issues in the proposed retail c hoice plan. The staff also is to monitor surrounding areas, and if any commence retail access, is to report back the success or failure of those efforts 12 months after the initiatives begin. At the federal level in 2002, several bills, some with conflicting provisions, were introduced and actively debated, although none passed. Conversely, the troubled electric supply situation in California during 2001 and 2000 led many in the industry to reexamine the restructuring process. While a competitive model continues to be espoused in many areas, several states have reduced or eliminated their restructuring efforts or have asked for delays in implementing already passed rules or legislation. Management expects the customer choice debate and other related issues to continue in legislative and regulatory forums. At this time, we 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. Management believes that Cleco Power is a reliable, low-cost provider of electricity, and as such, is currently positioned to compete effectively in a restructured electric marketplace.

Retail Rates of Cleco Power

Retail rates regulated by the LPSC accounted for approximately 79% of our consolidated 2002 revenue. Fuel costs and monthly fuel adjustment billing factors are 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. A base rate decrease of $3.0 million annually became effective November 1, 1996, with a second decrease of an additional $2.0 million annually effective January 1, 1998. The terms of this settlement were to be effective for a five-year period. The settlement period was extended until 2004 under a February 1999 agreement with the LPSC to transfer the existing assets of Coughlin Power Station from Cleco Power's LPSC regulated rate base into Evangeline LLC, which then repowered the generation plant.

During the eight-year period ending September 30, 2004, an LPSC-approved rate stabilization plan is in place. This 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 revenues 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 during the month of September following the evaluation period. Customers received a refund of $0.6 million in September 2002. The determination of any refund relative to the 2002 earnings monitoring period is under review by the LPSC staff. For information concerning amounts accrued by Cleco Power based on the settlement agreement, see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

As noted above, the rate stabilization plan is due to expire on September 30, 2004. A new plan may be ordered by the LPSC upon expiration or the existing plan may be extended with or without modification. We anticipate initiating discussions with the LPSC staff regarding the status of the plan late in 2003.

In November 1997, the LPSC issued an order in a generic docket that promulgated new standards for the monthly fuel adjustment clause rate filings of electric utility companies under its jurisdiction. The order adopted new rules and procedures for the monthly fuel adjustment clause computation and required changes in reporting of fuel and purchased power costs. Although the order narrowed the types of costs that can be included in the fuel adjustment clause, it offset this reduction with an increase in the base rates. New rate schedules that incorporate the shifting of costs from fuel adjustment clause to base rates were calculated, subsequently approved by the LPSC and implemented on January 1, 2000. The changes resulted in an immaterial effect on our financial condition and results of operations for 2002.

The LPSC staff has informed Cleco Power that it is planning to conduct a periodic fuel audit. It is anticipated the audit will commence in the first quarter of 2003. The audit, pursuant to the Fuel Adjustment Clause General Order, issued November 6, 1997, in Docket No. U-21497, is required to be performed no less frequently than every other year; however, this will be the first LPSC fuel adjustment clause audit of Cleco Power. Cleco Power has not been informed which time period will be covered by the audit.

Franchises

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 vary from 10 years to 50 years. 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, will be up for renewal in April 2003. We made an offer to renew the franchise in October 2002.

Regulatory Matters

Wholesale Electric Competition

The Energy Policy Act (Act), enacted by Congress in 1992, significantly changed U.S. energy policy, including regulations governing the electric utility industry. The 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 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 Act, a FERC transmission order requiring a transmitting utility to provide wholesale transmission services must include provisions permitting 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 a ssociated services.

In addition, the Act revised the 1935 Federal Power Act (1935 FPA) to permit utilities, including registered holding companies, and nonutilities 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 establishes 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 is still 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 Corporation and Southern Company announced a combined effort to form a Southeastern RTO, the SeTrans. At the same time, Southwest Power Pool (SPP) and Midwest Independent System Operator (MISO) announced their combined effort to design a Midwestern RTO. On April 1, 2002, MISO filed the necessary documents at the FERC to allow the consolidation of MISO and SP P to proceed. The FERC approved a consolidation of MISO and SPP tariffs, moving the merger closer to completion. On June 27, 2002, the SeTrans sponsors filed a Petition for Declaratory Order, requesting the FERC to approve the governance structure and business model of the SeTrans RTO as consistent with Order No. 2000 and FERC precedent. On October 9, 2002, the FERC responded that SeTrans complies with Order No. 2000 in such critical areas as its governance structure, transmission pricing policy, business model and the Independent System Administrator (ISA) selection process. The FERC also provided guidance on issues critical to forming the RTO. On November 1, 2002, the sponsors of the SeTrans RTO announced the selection of ESB International, Ltd. and Accenture, LLP as the preferred candidates for ISA. Cleco Power continues to be involved in the ongoing RTO development process. Cleco Power cannot anticipate with certainty the final form and configuration that this organizational process will yield nor which specific RTO it will join, although Cleco Power currently is actively participating in the SeTrans process and expects to join that RTO unless circumstances change. Additionally, various parties, including several state commissions, utilities, and other industry participants, are now contesting FERC's jurisdiction in this matter. It is uncertain how or when this debate will be resolved.

In September 2001, the LPSC issued Order No. U-25965 which requires Cleco Power and other transmission-owning entities in Louisiana to show cause why they should not be enjoined from transferring 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 shoul d 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 our 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 July 31, 2002, the FERC issued a notice of proposed rulemaking (RM01-12) that attempts to establish the criteria for a standard market design (SMD). The SMD is intended to establish common operating and market requirements to further foster competitive wholesale electric markets. On October 2, 2002, the FERC extended the comment period and added a reply comment period, moving possible adoption of the rule to the latter part of 2003. The SeTrans sponsors filed comments to the SMD notice of proposed rulemaking on November 15, 2002.

Federal regulators and legislators continue to study the potential effects of restructuring the vertically integrated utility systems and providing retail customers with a choice of supplier. Congress is also evaluating power production and delivery as part of their formation of a national energy policy. At this time, 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. Cleco cannot predict what future legislation may be proposed and/or passed and what impact it may have upon our results of operations or financial condition.

Gas Put Options

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 charged 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 optio n 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. While 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 "Financial Condition - Regulatory Matters - Fuel Audit."

Review of Trading Activities

During a review of trading activities in the second half of 2002, we 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 who in turn would sell the power to its industrial customer or to others. The pricing of these round-trip trades for Cleco Power was $0.2 million, $0.5 million, $0.3 million, and less than $0.1 million for 2002, 2001, 2000, and 1999, respectively. Cleco Power has contacted the FERC and LPSC and discussed these transactions with both agencies. These discussions have led to formal investigatory proceedings with dockets being opened by the FERC and LPSC, with which we are cooperating. Management is unable to predict what positions the FERC and LPSC may take on these transactions, but believes any such action will not have a material adverse effect on our results of operations or financial condition. Marketing & Trading participated in round-trip trades where 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 where 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. The value of all round-trip trades for Marketing & Trading was $1.9 million, $0.4 million, $0.1 million and none for 2002, 2001, 2000, and 1999, respectively. Marketing & Trading has contacted the FERC regarding its round-trip trades. These discussions have led to the same investigatory proceeding with the FERC referenced above, with which we are cooperating. We have received requests for information from the Commodity Futures Trading Commission (CFTC) related to Cleco Power's and Marketing & Trading's round-trip trades and the reporting of trading activities to trade publications. We are providing 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. For additional information regarding the review of trading activities, see the Notes to the Consolidated Financial Statements, Note 19 - "Review of Trading Activities." Management believes these trading activities will be reviewed in Cleco Power's pending LPSC fuel audit. For additional information on the fuel audit, see "- Financial Condit ion - Regulatory Matters - Fuel Audit."

We have implemented Issue 1 of EITF No. 02-3, 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, aggregating revenues and expenses and reporting the number in one line item. Therefore, the effect on our revenues and expenses related to the round-trip trades has been eliminated through the implementation of Issue 1 of EITF No. 02-3. For more information on this issue, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards."

Fuel Audit

The LPSC staff informed Cleco Power that it is planning to conduct a periodic fuel audit beginning in the first quarter of 2003. The audit, pursuant to the Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497, is required to be performed no less frequently than every other year, however, this will be the first LPSC fuel adjustment clause audit of Cleco Power. Cleco Power has not been informed which time period will be covered by the audit, nor is management able to predict the results of the LPSC fuel audit. Recovery fuel adjustment clause costs is subject to refund until final approval is received from the LPSC upon completion of a periodic audit. LPSC-jurisdictional revenue recovered by Cleco Power through its fuel adjustment clause for the three years, five years, and seven years ending December 31, 2002, was $811.5 million, $1,189.4 million, and $1, 531.5 million, respectively.

Gas Transportation Charges

During a review of an affiliate gas transportation contract, we determined that gas transportation charges billed by an unregulated subsidiary of Cleco Energy to Cleco Power may have exceeded the unregulated subsidiary's cost, plus a reasonable rate of return, of providing such services to Cleco Power. As such, these transactions have potentially exceeded the pricing standards of the LPSC for affiliate transactions under the circumstances. Midstream has recorded a charge of approximately $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 is currently in 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 "- Financial Condition - Regulatory Matter - Fuel Audit."

Lignite Deferral

In May 2001, Cleco Power signed a lignite contract with a miner at the Dolet Hills mine. As defined in LPSC Orders No. U-21453, U-20925(SC) and U-22092(SC) (Subdocket G), retail ratepayers are receiving fuel cost savings equal to 2% of the

projected previous mining contract costs through 2011. Costs above 98% of the previous contract's projected costs are deferred. Deferred costs are passed through the fuel adjustment clause to retail ratepayers when the actual costs of the new contract are below 98% of the projected costs of the previous contract. As of December 31, 2002, Cleco Power has deferred $8.3 million in costs and interest relating to the mining contract. If the miner's cumulative costs do not fall below the 98% threshold, Cleco Power may be required to write off some or all of the deferred amount. 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 fall below the 98% threshold and, therefore, expects Cleco Power to recover the amounts deferred.

New Power Plants

APP, a joint venture owned 50% by Midstream and 50% by Calpine, constructed a 1,160-MW, combined-cycle, natural gas-fired power plant near Eunice, Louisiana. Construction on Power Block 1, which is tolled to Aquila Energy, was completed on July 1, 2002, and construction on Power Block 2, which is tolled to CES, was completed on August 2, 2002. Total costs of the plant incurred by APP were $502.7 million. APH capitalized $19.5 million of costs, which consisted of interest, and other miscellaneous charges related to the construction of APP. Midstream funded its investment in APP through an intercompany loan from Cleco Corporation, and Cleco Corporation funded the intercompany loan through its credit facility. We currently do not expect to obtain project level financing in 2003 for our equity interest in APP. The investment in APP is being accounted for using the equity method of accounting. As of December 31, 2002, Midstream had contributed $273.0 million to APP in the form of cash, land, and Midstream's portion of earnings from the joint venture, which amounted to $14.8 million.

APP has entered into the Aquila Tolling Agreement with Aquila Energy for 580 MW of capacity starting on July 1, 2002, and continuing for 20 years and the Calpine Tolling Agreement with CES for 580 MW of capacity starting on July 1, 2002, and continuing for 20 years. Under these tolling agreements, Aquila Energy and CES will supply the natural gas required to generate their respective 580-MW capacity portions and will own the plant's output. The agreements require Aquila Energy and CES to pay APP various capacity reservation and fixed operating and maintenance fees, the amounts of which depend upon the type of capacity and ultimate availability achieved by APP. In addition to the capacity reservation and fixed operations and maintenance payments from Aquila Energy and CES, APP will collect revenues associated with variable operating and maintenance expenses based on actual run hours at Acadia. For additional information on the credit ratings of our counterparties under our tolling agreements, see "- Liquidity and Capital Resources - General Considerations and Credit-Related Risks," above. For information on factors affecting tolling revenues and obligations under our tolling agreements, see "- Results of Operations - General Factors Affecting Midstream."

PEP completed construction of a 725-MW, natural gas-fired power plant in Perryville, Louisiana on June 30, 2002, and full commercial operation of the 568-MW combined-cycle unit began on July 1, 2002. A 157-MW combustion turbine operating in simple cycle became operational in July 2001. As of December 31, 2002, PEP had incurred $325.5 million constructing the plant, including capitalized interest. Nonrecourse financing was obtained 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 complete. For additional information regarding the Perryville financing, see the Notes to the Consolidated Financial Statements, Note 5 - "Debt."

In July 2001, PEP entered into the Perryville Tolling Agreement, a 20-year power purchase agreement with MAEM, Mirant's risk management, trading and marketing organization, for 725 MW of capacity. Under the terms of the contract, MAEM will supply the natural gas needed to fuel the plant and will own the plant's output. The agreement requires MAEM to pay PEP various capacity reservation and fixed operations and maintenance fees, the amount of which depends upon the type of capacity and ultimate availability achieved by Perryville. In addition to the capacity reservation and fixed operating and maintenance payments from MAEM, PEP is entitled to collect revenues associated with variable operating and maintenance expenses based on actual run hours at the Perryville facility. For additional information regarding the credit ratings of our counterparties under our tolling agreements, see "- Liq uidity and Capital Resources - General Considerations and Credit-Related Risks," above. For additional information on factors affecting tolling revenues and obligations under our tolling agreements, see "- Results of Operations - General Factors Affecting Midstream."

PEP in August 2002. The proceeds from the $100.0 million subordinated debt were used to reduce senior project debt. In the event of a payment default under the Perryville Tolling Agreement, Mirant has guaranteed to either pay PEP, on behalf of MAEM, any outstanding amounts under the Perryville Tolling Agreement, or to allow any outstanding amounts to be offset against the subordinated loan principal and interest payments, including accrued and unpaid interest from PEP. The amount of Mirant's guarantee is limited to the principal amount outstanding and accrued and unpaid interest under the subordinated debt. The subordinated debt and associated guarantee mature on October 1, 2007, unless MAEM is in payment default under the Perryville Tolling Agreement. If MAEM is in payment default, then we have the right to extend the maturity of both the subordinated debt and associated guarantee for another five years. Cleco Corporation u sed a combination of newly issued common equity and short-term debt to fund our acquisition of Mirant's interest. The acquisition was accounted for as a purchase in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations." We discontinued the equity method of accounting for PEP effective July 1, 2002, and consolidated PEP's assets and liabilities as of June 30, 2002. PEP's revenue and expenses were reported in the Consolidated Statements of Income beginning July 1, 2002. As of December 31, 2002, PEP's assets and liabilities were $355.0 million and $269.3 million, respectively.

Purchased Power

Cleco Power does not supply all of its customers' electric power requirements from generation facilities owned by the company. We must purchase additional electric power 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 40% of its annual capacity and energy needs under its power purchase 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 power contracts with Williams Energy and Dynegy. Because substantially all of its long-term capacity and energy contracts with Williams Energy and Dynegy expire on December 31, 2004, Cleco Po wer is currently evaluating its long-term capacity and energy needs. For additional information on this process, see "- Results of Operations - General Factors Affecting Cleco Power." 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.

The contracts between Cleco Power and Williams Energy stipulate that Cleco Power must provide additional security in the event of certain ratings triggers. These 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 ratings trigger is $20.0 million under these contracts. The contract between Cleco Power and Dynegy stipulates that Cleco Corporation 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 Corporation could be required to provide to Dynegy is for the full amount of Cleco Power's obligations in respect of the capacity payments for the remainder of the contract. At December 31, 2002, this amount was $12.0 million.

Financial Risk Management

and the instruments and positions are used to satisfy customer requirements. Cleco Power does have some 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 and Marketing & Trading's positio ns do not qualify for the exceptions or hedge accounting under SFAS No. 133 and are therefore marked-to-market.

We are also subject to market risk associated with our tolling agreement counterparties. For additional information concerning our market risk associated with our counterparties, see "- Liquidity and Capital Resources - General Considerations and Credit-Related Risks."

Our 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. Our 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.

Interest

We have entered into various fixed- and variable-rate debt obligations. For details, see the Notes to the Consolidated Financial Statements, Note 5- "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, 2002, the carrying value of our long-term, fixed-rate debt was approximately $670.2 million, with a fair market value of approximately $650.1 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 $35.4 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, 2002, the carrying value of our long-term, variable-rate debt was approximately $244.6 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 $2.4 million in our pretax earnings.

As of December 31, 2002, the carrying value of our short-term, variable-rate debt was approximately $315.3 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 $3.2 million in our pretax earnings.

We monitor our 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 our variable-rate credit facility with fixed-rate debt.

Market Risk

Our management believes we have controls in place to help minimize the 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 which shows Value-at-Risk (VAR) and current market conditions. Cleco Corporation's Board of Directors appoints the members of the Risk Management Committee. VAR limits are set and monitored by the Risk Management Committee.

Marketing & Trading engages in trading of power and natural gas. All of Marketing & Trading's trades are marked-to-market as required by SFAS No. 133. For information regarding rescission of EITF No. 98-10, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Recent Accounting Standards." Due to market price volatility, mark-to-market reporting may introduce volatility to carrying values and hence to our financial statements. The net mark-to-market amount of trading positions of Marketing & Trading for the year ended December 31, 2002, was a loss of $0.5 million.

Cleco Power engages in trading of power and natural gas, provides fuel for generation, and purchases power to meet the power demands of customers. Financial positions that are not used to meet the power demands of customers are marked-to-market as required by SFAS No. 133. For the year ended December 31, 2002, the net mark-to-market amount for these positions was a loss of $0.6 million.

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

Cleco Power has entered into positions to mitigate some of the volatility in fuel costs passed on to customers, as permitted by a 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. At December 31, 2002, the net mark-to-market impact was a loss of $1.4 million.

Cleco Energy provides natural gas to wholesale customers, such as municipalities, and enters into positions in order to provide fixed gas prices to some of its customers. In the fourth quarter of 2001, Cleco Energy discontinued using cash-flow hedges as defined in SFAS No. 133, as amended. 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. For the year ended December 31, 2002, the net mark-to-market impact was a minimal loss.

Marketing & Trading, 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 2002, as well as the VAR at December 31, 2002, and 2001, is summarized below:

Value-at-Risk	For the year ended December 31, 2002			At December 31,
	High	Low	Average	2002		2001
	(Thousands)				(Thousands)
Marketing & Trading	$ 1,154.6	$ 1.7	$ 470.1	$ 5.7		$ 948.8
Cleco Power	$ 269.8	$ -	$ 19.8	$ -		$ 11.2
Cleco Energy	$ 169.6	$ 5.6	$ 27.5	$ 29.3		$ 174.0
Consolidated	$ 1,212.4	$ 27.4	$ 517.3	$ 35.0		$ 1,134.0

The decrease in VAR from December 31, 2002 compared to December 31, 2001, is primarily due to a decrease in trading activity as a result of our decision to no longer engage in speculative trading activities. Under our VAR model, we consider changes in market value of our open positions in excess of $200,000 over our estimated VAR to be material. During 2002, we experienced one day in which there was such an excess, which was $318,000.

The following table summarizes the market value maturities of contracts with prices actively traded at December 31, 2002:

	Fair Value of Contracts at December 31, 2002
Contractual Obligations	Maturity Lessthan one year	Maturity 1-3 years	Maturity over three years	Total Fair Value
	(Thousands)
Assets
Cleco Power	$ 24,457	$ -	$ -	$ 24,457
Midstream	147,820	150	-	147,970
	$ 172,277	$ 150	$ -	$ 172,427
Liabilities
Cleco Power	$ 37,239	$ -	$ -	$ 37,239
Midstream	147,638	150	-	147,788
	$ 184,877	$ 150	$ -	$ 185,027

New Accounting Standards

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

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this report are forward-looking statements. Although we 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 our 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 our actual results to differ materially from those contemplated in a ny of our forward-looking statements:

	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, 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;
	Nonperformance by and creditworthiness of counterparties under tolling and power purchase agreements and trading arrangements, or the renegotiation of those arrangements;
	Increased competition in the power environment, including effects of industry restructuring or deregulation, transmission system operation or administration, retail wheeling, 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, and the formation of RTOs and the implementation of SMD;
	Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (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 LLC;
	Changing market conditions and a variety of other factors associated with physical energy and financial trading activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rate, and warranty risks;
	Acts of terrorism;
	Availability or cost of capital resulting from changes in Cleco Corporation or Cleco Power, interest rates, and securities ratings or market perceptions of the electric utility industry and energy-related industries;
	Employee work force factors, including changes in key executives and work stoppages;
	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.

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

We 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.

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS

				AT DECEMBER 31,
				2002	2001
Assets				(THOUSANDS)
	Current assets
		Cash and cash equivalents		$ 114,331	$ 11,938
		Restricted cash, current portion		7,762	5,466
		Customer accounts receivable (less allowance for doubtful
			accounts of $1,071 in 2002 and $1,561 in 2001)	32,599	25,408
		Other accounts receivable		45,264	47,165
		Taxes receivable		23,607	-
		Unbilled revenues		20,171	17,863
		Fuel inventory, at average cost		13,309	11,990
		Material and supplies inventory, at average cost		14,416	16,107
		Margin deposits		318	580
		Risk management assets		335	1,710
		Accumulated deferred fuel		-	7,979
		Accumulated deferred federal and state income taxes, net		3,829	4,189
		Other current assets		8,940	9,236
			Total current assets	284,881	159,631
	Property, plant and equipment
		Property, plant and equipment		2,200,103	1,844,569
		Accumulated depreciation		(714,178)	(655,737)
		Net property, plant and equipment		1,485,925	1,188,832
		Construction work-in-progress		80,230	35,816
			Total property, plant and equipment, net	1,566,155	1,224,648

	Equity investment in investees			273,688	227,169
	Prepayments			32,865	19,418
	Restricted cash, less current portion			45,907	24,221
	Regulatory assets and liabilities - deferred taxes, net			65,268	58,545
	Long-term receivable			10,370	5,904
	Other deferred charges			65,472	48,354
Total assets				$ 2,344,606	$ 1,767,890

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

(Continued on next page)

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS

					AT DECEMBER 31,
					2002	2001
Liabilities and shareholders' equity					(THOUSANDS)
	Liabilities
		Current liabilities
			Short-term debt		$ 315,300	$ 179,555
			Long-term debt due within one year		45,401	30,843
			Accounts payable		104,046	88,605
			Retainage		6,278	6,439
			Accrued payroll		2,180	1,130
			Customer deposits		21,087	20,692
			Taxes accrued		-	11,052
			Interest accrued		15,546	15,158
			Accumulated deferred fuel		3,559	-
			Risk management liabilities		2,310	743
			Other current liabilities		3,032	2,300
				Total current liabilities	518,739	356,517
		Deferred credits
			Accumulated deferred federal and state income taxes, net		299,019	208,462
			Accumulated deferred investment tax credits		20,744	22,487
			Other deferred credits		57,442	45,693
				Total deferred credits	377,205	276,642
		Long-term debt			868,684	626,777
			Total liabilities		1,764,628	1,259,936

Commitments and contingencies (see Note 16)

Shareholders' equity
	Preferred stock
		Not subject to mandatory redemption			26,578	27,326
		Deferred compensation related to preferred stock held by ESOP			(9,070)	(11,338)
			Total preferred stock not subject to mandatory redemption		17,508	15,988
	Common shareholders' equity
		Common stock, $1 par value, authorized 100,000,000 shares,
			issued 47,065,152 and 45,065,152 shares at December 31, 2002
			and 2001, respectively		47,065	45,065
		Premium on capital stock			152,745	111,714
		Retained earnings			366,073	337,254
		Treasury stock, at cost, 29,959 and 102,242 shares
			at December 31, 2002 and 2001, respectively		(579)	(2,067)
		Accumulated other comprehensive loss			(2,834)	-
			Total common shareholders' equity		562,470	491,966
				Total shareholders' equity	579,978	507,954
Total liabilities and shareholders' equity					$ 2,344,606	$ 1,767,890

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
				FOR THE YEAR ENDED DECEMBER 31,
				2002	2001	2000
				(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Operating revenue
	Electric operations			$ 568,102	$ 592,253	$ 591,298
	Tolling operations			90,260	60,522	41,354
	Energy trading, net			1,675	7,049	11,876
	Energy operations			30,081	58,659	3,601
	Other operations			34,006	32,076	28,418
		Gross operating revenue		724,124	750,559	676,547
			Electric customer credits	(2,900)	(1,800)	(1,233)
		Total operating revenue		721,224	748,759	675,314
Operating expenses
	Fuel used for electric generation			143,733	182,384	180,231
	Power purchased for utility customers			150,400	139,939	135,894
	Purchases for energy operations			25,317	48,314	1,059
	Other operations			87,978	100,724	78,182
	Maintenance			35,080	29,459	37,438
	Depreciation			69,157	60,433	55,840
	Restructuring charge			10,164	-	-
	Impairment of long-lived asset			3,587	-	-
	Taxes other than income taxes			38,812	37,966	38,973
		Total operating expenses		564,228	599,219	527,617
Operating income				156,996	149,540	147,697
Interest income				1,576	7,764	4,665
Allowance for other funds used during construction				2,719	769	507
Equity income from investees				16,204	175	-
Other income (expense), net				(2,768)	74	(1,586)
Income before interest charges				174,727	158,322	151,283
Interest charges
	Interest charges, including amortization of debt expenses,
		premium and discount, net of capitalized interest		61,212	48,871	47,567
	Allowance for borrowed funds used during construction			(603)	(1,178)	(580)
		Total interest charges		60,609	47,693	46,987
Net income from continuing operations before
	income taxes and preferred dividends			114,118	110,629	104,296
Federal and state income taxes				42,243	38,356	34,961
Net income from continuing operations				71,875	72,273	69,335
Discontinued operations
	Loss from operations, net of income taxes			-	-	(5,411)
	Loss on disposal of segment, net of income taxes			-	(2,035)	(1,450)
		Total discontinued operations		-	(2,035)	(6,861)
Net income before extraordinary item				71,875	70,238	62,474
Extraordinary item, net of income taxes				-	-	2,508
Net income before preferred dividends				71,875	70,238	64,982
Preferred dividends requirements, net				1,872	1,876	1,870
Net income applicable to common stock				$ 70,003	$ 68,362	$ 63,112
Average shares of common stock outstanding
	Basic			46,245,104	45,000,955	44,947,718
	Diluted			48,771,864	47,763,713	47,654,954
Basic earnings per share
	From continuing operations			$ 1.51	$ 1.56	$ 1.50
	From discontinued operations			$ -	$ (0.04)	$ (0.15)
	Extraordinary item			$ -	$ -	$ 0.06
	Net income applicable to common stock			$ 1.51	$ 1.52	$ 1.41
Diluted earnings per share
	From continuing operations			$ 1.47	$ 1.51	$ 1.46
	From discontinued operations			$ -	$ (0.04)	$ (0.15)
	Extraordinary item			$ -	$ -	$ 0.05
	Net income applicable to common stock			$ 1.47	$ 1.47	$ 1.36
Cash dividends paid per share of common stock				$ 0.8950	$ 0.8700	$ 0.8450

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
					FOR THE YEAR ENDED DECEMBER 31,
					2002		2001		2000
Operating activities						(THOUSANDS)
	Net income before preferred dividends				$	71,875	$	70,238	$	64,982
	Adjustments to reconcile net income to net cash provided
		by operating activities:
			Loss on disposal of segment, net of tax			-		(2,555)		6,861
			Extraordinary gain, net of tax			-		-		(2,508)
			Depreciation and amortization			71,144		61,775		56,958
			Provision for doubtful accounts			688		2,018		2,195
			Income from equity investments			(16,204)		(175)		-
			Allowance for other funds used during construction			(2,719)		(769)		(507)
			Impairment of long-lived asset			3,587		-		-
			Amortization of investment tax credits			(1,743)		(1,765)		(1,742)
			Net deferred income taxes			79,060		(6,898)		6,098
			Deferred fuel costs			11,538		(4,362)		(6,255)
			Changes in assets and liabilities:
				Accounts receivable, net		(5,119)		19,524		(54,969)
				Unbilled revenues		(2,308)		16,937		(18,503)
				Fuel, materials and supplies inventory		372		(4,953)		1,912
				Prepayments		(14,667)		(326)		-
				Accounts payable		3,931		(21,026)		28,490
				Customer deposits		395		214		110
				Long-term receivable		(4,465)		(5,009)		(895)
				Other deferred accounts		334		2,038		604
				Taxes accrued		(35,204)		(8,639)		14,523
				Interest accrued		(150)		(517)		5,543
				Margin deposits		262		21,077		(21,159)
				Risk management assets and liabilities, net		2,942		(3,866)		1,948
				Other, net		1,966		(8,361)		(1,890)
		Net cash provided by operating activities				165,515		124,600		81,796
Investing activities
	Additions to property, plant and equipment					(89,704)		(49,371)		(113,343)
	Allowance for other funds used during construction					2,719		769		507
	Proceeds from sale of property, plant and equipment					-		1,845		291
	Proceeds from disposal of segment					-		4,590		-
	Equity investment in investees					(39,860)		(133,084)		(97,234)
	Acquisition of partnership, net of cash acquired					(54,561)		-		-
		Net cash used in investing activities				(181,406)		(175,251)		(209,779)
Financing activities
	Cash transferred from (to) restricted accounts, net					(19,359)		25,667		21,908
	Sale of common stock					44,300		-		-
	Change in short-term debt, net					135,745		83,598		69,623
	Retirement of long-term obligations					(63,204)		(32,035)		(29,774)
	Issuance of long-term debt					67,739		-		110,332
	Deferred financing costs					(3,776)		-		-
	Dividends paid on common and preferred stock, net					(43,056)		(41,031)		(39,860)
	Repurchase of common stock					(105)		(3,017)		-
		Net cash provided by financing activities				118,284		33,182		132,229
Net increase (decrease) in cash and cash equivalents						102,393		(17,469)		4,246
Cash and cash equivalents at beginning of year						11,938		29,407		25,161
Cash and cash equivalents at end of year					$	114,331	$	11,938	$	29,407
Supplementary cash flow information
	Interest paid (net of amount capitalized)				$	59,082	$	50,037	$	46,527
	Income taxes paid				$	3,000	$	41,261	$	23,060
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	$	1,860

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

		FOR THE YEAR ENDED DECEMBER 31,
		2002	2001	2000
		(THOUSANDS)
Net income applicable to common stock		$ 70,003	$ 68,362	$ 63,112
Other comprehensive income (loss), before tax:
	Transition adjustment from implementation of SFAS No. 133	-	(4,453)	-
	Net unrealized gains from derivative instruments	-	4,453	-
	Net unrealized loss from limited partnership	(413)	-	-
	Net unrealized gains from available-for-sale securities	55	-	-
	Recognition of additional minimum pension liability	(4,024)	-	-
Other comprehensive income (loss), before tax		(4,382)	-	-
Income tax benefit related to items of other comprehensive income (loss)		1,548	-	-
Comprehensive income, net of tax		$ 67,169	$ 68,362	$ 63,112

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' EQUITY




	COMMON STOCK		PREMIUM ON CAPITAL	LONG-TERM DEBT PAYABLE IN COMPANY COMMON	RETAINED	TREASURY STOCK		ACCUMULATED OTHER COMPREHENSIVE
	SHARES	AMOUNT	STOCK	STOCK	EARNINGS	SHARES	COST	LOSS
	(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
BALANCE, JANUARY 1, 2000	45,065,152	$45,065	$112,722	$1,036	$282,825	180,188	$2,991	$ -
Redemption of preferred stock			(471)
Issuance of treasury stock			22			(79,898)	(1,329)
Director's restricted stock			(14)				(14)
Incentive shares forfeited						4,742	71
Incentive shares purchased			218
Dividend requirements, preferred stock, net					(1,870)
Payment in common stock				(517)		(31,960)	(531)
Cash dividends paid, common stock,
$0.845 per share					(37,890)
Net income from continuing operations					69,335
Loss from discontinued operations					(6,861)
Extraordinary gain					2,508
BALANCE, DECEMBER 31, 2000	45,065,152	45,065	112,477	519	308,047	73,072	1,188	-
Treasury shares purchased						148,432	3,017
Issuance of treasury stock			(750)			(87,304)	(1,606)
Director's restricted stock			(13)				(13)
Dividend requirements, preferred stock, net					(1,876)
Payment in common stock				(519)		(31,958)	(519)
Cash dividends paid, common stock,
$0.870 per share					(39,155)
Net income from continuing operations					72,273
Loss from discontinued operations					(2,035)
Transition adjustment from implementation
of SFAS No. 133								4,453
Net unrealized gains from derivative instruments								(4,453)
BALANCE, DECEMBER 31, 2001	45,065,152	45,065	111,714	-	337,254	102,242	2,067	-
Issuance of common stock	2,000,000	2,000	42,300
Treasury shares purchased						5,784	105
Issuance of treasury stock			(1,260)			(78,067)	(1,584)
Director's restricted stock			(9)				(9)
Dividend requirements, preferred stock, net					(1,872)
Payment in common stock
Cash dividends paid, common stock,
$.895 per share					(41,184)
Net income from continuing operations					71,875
Net unrealized loss from limited partnership								413
Net unrealized gains from available-for sale securites								(55)
Recognition of minimum pension liability								4,024
Income tax benefit related to items of other
comprehensive income								(1,548)
BALANCE, DECEMBER 31, 2002	47,065,152	$47,065	$152,745	-	$366,073	29,959	$ 579	$ 2,834

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' EQUITY




	COMMON STOCK		PREMIUM ON CAPITAL	LONG-TERM DEBT PAYABLE IN COMPANY COMMON	RETAINED	TREASURY STOCK		ACCUMULATED OTHER COMPREHENSIVE
	SHARES	AMOUNT	STOCK	STOCK	EARNINGS	SHARES	COST	LOSS
	(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
BALANCE, JANUARY 1, 2000	45,065,152	$45,065	$112,722	$1,036	$282,825	180,188	$2,991	$ -
Redemption of preferred stock			(471)
Issuance of treasury stock			22			(79,898)	(1,329)
Director's restricted stock			(14)				(14)
Incentive shares forfeited						4,742	71
Incentive shares purchased			218
Dividend requirements, preferred stock, net					(1,870)
Payment in common stock				(517)		(31,960)	(531)
Cash dividends paid, common stock,
$0.845 per share					(37,890)
Net income from continuing operations					69,335
Loss from discontinued operations					(6,861)
Extraordinary gain					2,508
BALANCE, DECEMBER 31, 2000	45,065,152	45,065	112,477	519	308,047	73,072	1,188	-
Treasury shares purchased						148,432	3,017
Issuance of treasury stock			(750)			(87,304)	(1,606)
Director's restricted stock			(13)				(13)
Dividend requirements, preferred stock, net					(1,876)
Payment in common stock				(519)		(31,958)	(519)
Cash dividends paid, common stock,
$0.870 per share					(39,155)
Net income from continuing operations					72,273
Loss from discontinued operations					(2,035)
Transition adjustment from implementation
of SFAS No. 133								4,453
Net unrealized gains from derivative instruments								(4,453)
BALANCE, DECEMBER 31, 2001	45,065,152	45,065	111,714	-	337,254	102,242	2,067	-
Issuance of common stock	2,000,000	2,000	42,300
Treasury shares purchased						5,784	105
Issuance of treasury stock			(1,260)			(78,067)	(1,584)
Director's restricted stock			(9)				(9)
Dividend requirements, preferred stock, net					(1,872)
Payment in common stock
Cash dividends paid, common stock,
$.895 per share					(41,184)
Net income from continuing operations					71,875
Net unrealized loss from limited partnership								413
Net unrealized gains from available-for sale securites								(55)
Recognition of minimum pension liability								4,024
Income tax benefit related to items of other
comprehensive income								(1,548)
BALANCE, DECEMBER 31, 2002	47,065,152	$47,065	$152,745	-	$366,073	29,959	$ 579	$ 2,834

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

NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS

NOTE 1 - THE COMPANY

GENERAL

	Cleco Power LLC (Cleco Power) is an electric utility regulated by the Louisiana Public Service Commission (LPSC) and the Federal Energy Regulatory Commission (FERC), which determine the rates it can charge its customers. Cleco Power serves approximately 261,000 customers in 104 communities in central and southeastern Louisiana.
	Cleco Midstream Resources LLC (Midstream) is an unregulated subsidiary with operations in Louisiana and Texas. Midstream owns and operates wholesale generation stations and wholesale natural gas pipelines, invests in joint ventures that own and operate wholesale generation stations, and engages in energy management activities.
	Our other segment consists of the holding company, a shared services subsidiary, and an investment subsidiary.

The discontinued segment is UTS, LLC (UTS), formerly known as Utility Construction & Technology Solutions LLC (UtiliTech), a utility line construction business. In December 2000, we decided to sell substantially all of the UTS assets. Revenue and expenses associated with UTS are netted and shown on our Consolidated Statements of Income as a loss from discontinued operations. For additional information on selling substantially all of the UTS assets, see Note 17 - "Discontinued Operations."

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

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.

PRINCIPLES OF CONSOLIDATION

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

RECLASSIFICATIONS

REGULATION

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 Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 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. 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 organize a series of collaboratives to more fully explore th e unresolved issues in the plan. The staff also is to monitor surrounding areas and, if any commence retail access, report back the success or failure of that effort 12 months after the initiative began. Any future plan adopted by the LPSC 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.

Pursuant to SFAS No. 71, as of December 31, 2002, 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 and storm restoration costs as a result of rate actions of regulators. 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. At December 31, 2002, Cleco Power had recorded $65.3 million of regulatory assets, net of regulatory liabilities, for deferred taxes because of the regulatory requirement to flow through the tax benefits of accelerated deductions to current customers and an implied regulatory compact that future customers would fund these amounts when Cleco Power pays the additional taxes. These amounts occur o ver the lives of relatively long-lived assets, up to 30 years or more. At December 31, 2002, Cleco Power also has recorded deferred mining costs, storm restoration costs, and interest costs of $8.3 million, $7.0 million, and $10.5 million, respectively. The deferred storm restoration costs, deferred mining costs, and the deferred interest costs are presented in the line item entitled "Other Deferred Charges" on the Consolidated Balance Sheets. For information regarding deferred mining costs, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Lignite Deferral." A discussion of storm restoration costs and deferred interest costs follows in this Note. 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 Pow er'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.

STORM RESTORATION COSTS

During the fourth quarter of 2002, Cleco Power incurred $27.5 million of storm restoration costs, primarily to replace utility poles and conductors damaged by Tropical Storm Isidore and Hurricane Lili. According to an agreement with the LPSC, approximately $7.0 million of these restoration costs were recorded as a regulatory asset, for recovery over the six-year period beginning January 1, 2003.

DEFERRED INTEREST COSTS

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

Other deferred charges at December 31, 2002, also include $1.3 million of interest expenses on fuel cost under collections authorized by the LPSC to be recovered in future periods.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist primarily of regulated generation and energy transmission assets, along with unregulated 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. Unregulated assets are stated at the cost of construction or acquisition.

Our cost of improvements to property, plant and equipment is capitalized. Expenditures for repairs are expensed. 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. Annual depreciation provisions expressed as a percentage of average depreciable property were 3.28% for 2002, 3.27% for 2001, and 3.27% for 2000.

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

	Years
Utility plant	30-49
Oil & gas pipeline	3-50
Other	3-7

Property, plant and equipment consists of:

	At December 31,
	2002	2001
	(Thousands)
Regulated utility plant	$ 1,616,205	$ 1,583,920
Unregulated utility plant	548,478	224,795
Oil and gas pipeline	25,765	28,687
Other	9,655	7,167 ��
Total property, plant and equipment	$ 2,200,103	$ 1,844,569

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 Electric Cooperative, Inc. (Teche). The acquisition adjustment represents the amount paid by Cleco Power for the assets of Teche in excess of their carrying value.

Cleco Power	At December 31,
Cleco Power	2002	2001
	(Thousands)
Plant acquisition adjustment	$ 5,359	$ 5,359
Less accumulated amortization	1,447	1,203
Net plant acquisition adjustment	$ 3,912	$ 4,156

IMPAIRMENT OF ASSETS

We evaluate at each balance sheet date whether events and circumstances have occurred that indicate possible operational impairment. We use 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. We consider continued operating losses, or significant and long-term changes in business conditions, to be primary indicators of potential impairment. In measuring impairment, we look 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, we recorded an impairment charge on certain oi l and gas proved reserves. For additional information on the impairment charge, see the Notes to the Consolidated Financial Statements, Note 24 - "Impairment of Long-Lived Asset."

CASH EQUIVALENTS

We consider 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.

RESTRICTED CASH

Various agreements to which we are subject contain covenants that restrict our use of cash. As certain provisions under those agreements are met, cash is transferred out of related escrow accounts and becomes available for general corporate purposes. At December 31, 2002, $29.7 million of cash was restricted under the Cleco Evangeline LLC (Evangeline LLC) senior secured bond indenture, $22.2 million of cash was restricted under an agreement with the lenders for Perryville Energy Partners LLC (PEP), and $1.8 million of Acadia Power Holdings LLC's (APH) cash was restricted under the terms of the Midstream line of credit.

INCOME TAXES

Deferred income taxes are provided at the current enacted income tax rate on all temporary differences between tax and book bases of assets and liabilities. Cleco Corporation recognizes regulatory assets and liabilities incurred within Cleco Power for the tax effect of temporary differences, which, to the extent past ratemaking practices are continued by regulators, will be realized over the accounting lives of the related properties. Cleco Corporation files a federal consolidated income tax return for all wholly owned subsidiaries.

INVESTMENT TAX CREDITS

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

DEBT EXPENSE, PREMIUM AND DISCOUNT

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

REVENUE AND FUEL COSTS

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 is currently 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.

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

Energy Trading, Net and Other Revenues. Revenue is recognized at the time products or services are provided to and accepted by customers.

Tolling Revenue. Tolling revenue is the amount received by Midstream from its counterparties for the operation of its unregulated generating stations. We consider the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling Agreement) and the Tolling Agreement between PEP and Mirant America's Energy Marketing, LP (MAEM) (Perryville Tolling Agreement) to be operating leases as defined by SFAS No. 13, "Accounting for Leases," and SFAS No. 29, "Determining Contingent Rentals," 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 which provides for a greater portion of annual revenue to be received by us 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 anothe r rational allocation of the revenue is more representative of the pattern in which the leased property is employed. We believe 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. The Perryville Tolling Agreement does not contain a monthly shaping factor for revenue, but instead has a monthly adjustment for penalties which causes a greater risk of losing revenue if capacity is not available during the summer peak months. 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. For more information, see Note 14 - "Operating Leases."

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

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 on a combined basis, was 13.45% on a pretax basis (8.27% net of tax) for 2002, 13.65% on a pretax basis (8.4% net of tax) for 2001, and 13.62% on a pretax basis (8.38% net of tax) for 2000.

CAPITALIZED INTEREST

Cleco Corporation and its subsidiaries, except Cleco Power (see AFUDC above), capitalize interest costs related to longer term construction projects. Cleco Corporation capitalized approximately $6.0 million in 2002, $10.1 million in 2001, and $7.8 million in 2000. In addition, interest costs are capitalized for equity method investments. For more information, see Note 13 - "Equity Investment in Investees."

RISK MANAGEMENT

The market risk inherent in our market risk-sensitive instruments and positions includes the potential change arising from changes in interest rates, the commodity price of power traded on the different power exchanges and the commodity price of natural gas traded. Our 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. Prior to the third quarter of 2002, Cleco Power and Cleco Marketing & Trading LLC (Marketing & Trading) used Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," to determine whether market risk-sensitive instruments and positions are required to be marked-to-market. EITF No. 98-10 was rescinded and Cleco Power and Marketing & Trading currently use SFAS No. 133 in order 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, "Accounting for Derivative Instruments and Hedging Activities," since Cleco Power generally takes physical delivery and the instruments and positions are used to satisfy customer requirements. Cleco Power does have some 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 inco me. 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 LLC's (Cleco Energy) and Marketing & Trading's positions do not qualify for the exceptions nor hedge accounting under SFAS No. 133 and are marked-to-market. Cleco Power and Marketing & Trading have in place with various counterparties agreements that authorize the netting of financial buys and sells and contract payments to mitigate credit risk.

As a result of the implementation of SFAS No. 133, on January 1, 2001, a transition adjustment was recorded Other Comprehensive Income (OCI) that reduced total common shareholders' equity by $4.5 million. During the year ended December 31, 2001, the transition adjustment was reduced to zero primarily due to delivery of underlying natural gas and the assignment of certain contracts to Marketing & Trading.

RECENT ACCOUNTING STANDARDS

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

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the recognition of a liability for an asset's retirement obligation in the period in which the event that triggers the liability occurs. When the liability is initially recorded, the cost of the related asset is increased and subsequently depreciated over the asset's useful life. The liability is adjusted to its present value each period with a corresponding charge to expense. The standard is effective for fiscal years beginning after June 15, 2002. We adopted this statement effective January 1, 2003. The adoption of SFAS No. 143 had an immaterial impact on our financial position and results of operations.

In April 2002, FASB issued SFAS No. 145, "Recission of FASB Statements No, 4, 44 and 64, Amendment of FASB Statement No, 13, and Technical Corrections as of April 2002," which rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt;" SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers;" and SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements;" amends SFAS No. 13, "Accounting for Leases," and contains various technical corrections. The rescission of SFAS Nos. 4 and 64 requires that a gain or loss from the extinguishment of debt meets the criteria in Accounting Principles Board (APB) Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and

Infrequently Occurring Events and Transactions," before the extinguishment is classified as extraordinary. In the year ended December 31, 2000, we reported an extraordinary gain from the extinguishment of debt. The rescission of SFAS Nos. 4 and 64 will not change the reporting of the extinguishment, since it met the criteria stated in APB Opinion No. 30. The rescission of SFAS No. 44, the amendment of SFAS No. 13, and the technical corrections will not have a material impact on our financial statements. The rescission of SFAS Nos. 4 and 64 is effective for fiscal years beginning after June 15, 2002. The amendment of SFAS No. 13 is effective for transactions occurring after May 15, 2002. The rescission of SFAS No. 44 and most technical corrections are effective for financial statements issued on or after May 15, 2002.

In June 2002, the EITF reached a consensus on Issue 1 of EITF No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The consensus reached in Issue 1 requires that all gains and losses from energy trading contracts be reported on the income statement on a net basis effective for periods ending after July 15, 2002. Net reporting consists of aggregating revenue and expense and reporting the net number in one line item on the statements of income. Gross reporting consists of recording revenue and associated expense as separate line items on the statements of income. Before the consensus became effective, we reported unrealized gains and losses, also referred to as "mark-to-market," net and reported realized gains and losses on a gross basis. This issue does not affect the transactions reported under energy operations, which consist of energy management services and natural gas marketed. The consensus on Issue 1 requires that prior periods presented be reclassified in order to be consistent with the current reporting requirements in Issue 1. Net income and shareholders' equity were not affected. Revenue and expenses were reduced by $309.9 million for the year ending December 31, 2001, and by $143.9 million for the year ending December 31, 2000, as a result of adopting 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. Instead of using EITF No. 98-10 to evaluate energy contracts, Cleco will be using SFAS No. 133, as amended, in order to determine whether mark-to-market accounting is appropriate. Any effect of transitioning from the mark-to-market method of accounting under EITF No. 98-10 to another appropriate method will be recorded as a cumulative effect of a change in accou nting principle. The rescission of EITF No. 98-10 will not have a material impact on our financial statements.

In June 2002, FASB issued SFAS No. 146, "Accounting for Exit or Disposal Activities," which defines when a liability is recognized for costs relating to exiting an activity and supercedes EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability be recognized for costs relating to exiting an activity when the liability is incurred, not when an entity commits to an exit plan, as was required under EITF No. 94-3. This statement is effective for exit or disposal activities that are initiated after December 31, 2002. In the fourth quarter of 2002, we committed to a restructuring. The restructuring was accounted for under EITF No. 94-3.

FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," was issued in November 2002. FIN 45 expands on SFAS No. 5, "Accounting for Contingencies;" SFAS No. 57, "Related Party Disclosures;" and SFAS No. 107, "Disclosures About Fair Value of Financial Instruments" by clarifying the accounting for and disclosure of guarantees issued that are included in the scope of SFAS No. 5. Guarantees issued or modified after December 31, 2002, that fall within the scope for initial recognition, must be recognized as a liability at the fair market value of the guarantee on the guarantor's financial statements. Disclosures about guarantees that fall within the scope of FIN 45 are required for financial statements of interim and annual periods ending after December 15, 2002. We have adopted the dis closure requirements of FIN 45 as discussed in Note 23 - "Disclosures About Guarantees."

In December 2002, FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," which amends SFAS No. 123, "Accounting for Stock-Based Compensation," by providing for three methods of transition for expensing stock compensation under SFAS No. 123 and expands disclosure requirements for stock-based compensation. If a company chooses to expense stock options as described in SFAS No. 123, it can choose one of three transition methods: recognize compensation expense for all awards granted, modified or settled after the beginning of the fiscal year of adoption; recognize compensation expense from the beginning of the fiscal year of adoption as if the requirements of SFAS No. 123 had been used since December 15, 1994 or restate all periods presented to conform to the requirements of SFAS No. 123. SFAS No. 148 expands the disclosure requirements of SFAS No. 123 by requiring di sclosures relating to the three transition methods. Those companies that choose not to adopt SFAS No. 123 must present the pro forma effects as if they had adopted SFAS No. 123 in the annual and interim financial statements. This statement is effective for fiscal years ending after December 15, 2002. We have not adopted SFAS No. 123. We have adopted the disclosure requirements of SFAS No. 148 and have included the requirements in Note 6 - "Common Stock."

In January 2003, FASB released FIN 46, "Consolidation of Variable Interest Entities an Interpretation of ARB No. 51." FIN 46 expands the requirements of consolidation by including entities defined as "Variable Interest Entities" which depend on the financial support of a parent in order to maintain viability.

Detailed tests prescribed in FIN 46 can be used to determine the dependence of a Variable Interest Entity on a parent company. Currently, we do not have interest in Variable Interest Entities, but do have equity investments that do not qualify for consolidation under FIN 46. For information about our equity investments, see Note 13 - "Equity Investment in Investees." FIN 46 is effective for all financial statements issued after January 31, 2003.

EARNINGS PER AVERAGE COMMON SHARE

Calculation of Earnings Per Share

	For the year ended December 31, (Thousands, except per share amounts)
	2002			2001			2000
	Income (Numerator)	Shares (Denominator)	Per Share Amount	Income (Numerator)	Shares (Denominator)	Per Share Amount	Income (Numerator)	Shares (Denominator)	Per Share Amount
Net income from continuing operations	$ 71,875			$ 72,273			$ 69,335
Less: preferred dividends requirement, net	1,872			1,876			1,870

Basic EPS
Income from continuing operations available for common shareholders	$ 70,003	46,245	$ 1.51	$ 70,397	45,001	$ 1.56	$ 67,465	44,948	$ 1.50

Effect of Dilutive Securities
Stock option grants		47			213			80
Convertible ESOP preferred stock	1,803	2,480		1,814	2,550		1,830	2,626

Diluted EPS
Income from continuing operations available to common shareholders plus assumed conversions	$ 71,806	48,772	$ 1.47	$ 72,211	47,764	$ 1.51	$ 69,295	47,654	$ 1.46

Earnings per average common share (EPS) is 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 our 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 earnings per share.

Options to purchase 889,136 shares of common stock at prices ranging from $20.375 to $24.25 were outstanding 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, which expire between 2003 and 2012, were still outstanding at the end of fiscal year 2002.

Options to purchase 10,334 shares of common stock at prices ranging from $22.69 to $23.25 were outstanding 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, which expire between 2002 and 2012, were still outstanding at the end of fiscal year 2001.

Options to purchase 108,000 shares of common stock at prices ranging from $20.62 to $21.96 were outstanding but not included in the computation of diluted earnings per share for the fiscal year ended December 31, 2000, because the options' exercise prices were greater than the average market price of the common shares. The options, which expire between 2001 and 2011, were still outstanding at the end of fiscal year 2000.

STOCK OPTIONS

We account for stock options granted to employees under the provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees." We have 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 in Note 6 - "Common Stock."

NOTE 3 - JOINTLY OWNED GENERATION UNITS

Two electric generation units operated by Cleco Power are jointly owned with other utilities. Our proportionate share of operation and maintenance expenses associated with these two units is reflected in the consolidated financial statements.

	At December 31, 2002
	Rodemacher	Dolet Hills
	Unit #2	Unit #1
	(Dollar amounts in thousands)
Ownership	30 %	50 %
Utility plant in service	$85,612	$275,471
Accumulated depreciation	$52,180	$135,470
Unit capacity (megawatts)	523.0	650.0
Share of capacity (megawatts)	156.9	325.0

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The amounts reflected in the Consolidated Balance Sheets at December 31, 2002, and 2001, 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 our long-term debt and 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 us for debt and preferred stock with similar maturities. The fair value of convertible preferred stock is estimated assuming its conversion into common stock at the market price per common share at December 31, 2002, and 2001, with proceeds from the sale of the common stock used to repay the principal balance of Cleco Power's loan to the Employee Stock Ownership Plan (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.

	At December 31,
	2002		2001
Fair Value of Financial Instruments	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
	(Thousands)
Financial instruments not marked-to-market
Long-term debt	$914,828	$894,730	$658,422	$729,684
Preferred stock not subject to mandatory redemption	$ 17,512	$ 24,613	$ 15,988	$ 43,778

	Original Value	Estimated Fair Value	Original Value	Estimated Fair Value
Financial instruments marked-to-market
Energy Market Positions
Assets	$159,774	$172,427	$168,776	$161,668
Liabilities	$171,689	$185,027	$165,337	$158,436

The financial instruments not marked-to-market are reported on our consolidated balance sheets at carrying value. The financial instruments marked-to-market represent off-balance sheet risk because, to the extent we have an open position, we are exposed to the risk that fluctuating market prices may adversely affect our financial condition or results of operations upon settlement. Original value represents the fair value of the positions at the time originated.

NOTE 5 - DEBT

We have revolving credit facilities totaling $368.8 million, consisting of three separate facilities. Compensating balances are required for one of the facilities.

Cleco Corporation has a credit facility totaling $225.0 million. This facility provides for uncollateralized borrowings at interest rates based on either competitive bid, prime rate, or the London Interbank Offered Rate (LIBOR) and is scheduled to expire in June 2003. This facility has an optional conversion to a one-year term loan. The commitment fees for this facility are based upon Cleco Corporation's lowest secured debt ratings and are currently 0.125%. This facility provides support for the issuance of commercial paper and working capital needs. At December 31, 2002, there was $171.5 million drawn on the facility, leaving $53.5 million available. The $53.5 million at December 31, 2002, was further reduced by off-balance sheet commitments of $49.2 million, which left an actual available balance of $4.3 million. Off-balance sheet commitments entered in to by Cleco Corporation with third parties for certain types of transactions between those parties and Cleco Corporation's subsidiaries, other than Cleco Power, reduce the amount of the facility available to Cleco Corporation by an amount equal to the stated or determinable amount of the primary obligation. In addition, certain indebtedness incurred by Cleco Corporation outside of the facility reduces the amount of the facility available to Cleco Corporation. The amount of such commitments provided by Cleco Corporation and other indebtedness reducing the amount of the facility available to be utilized was $49.2 million at December 31, 2002, and $70.1 million at December 31, 2001. On July 31, 2002, this facility was amended to exclude Evangeline LLC from conditions that would have otherwise created an event of default if Evangeline LLC were to fail to make payments with respect to any of its material obligations. On November 7, 2002, this facility was further amende d to exclude Evangeline LLC from conditions that would have otherwise created an event of default if Evangeline LLC were to fail to make payments or declare bankruptcy with respect to any of its material obligations. As of December 31, 2002, Cleco Corporation was in compliance with the covenants in its credit facility. For more information about the commitments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements - Off-Balance Sheet Commitments."

Cleco Power has a revolving credit facility totaling $107.0 million. This facility provides for uncollateralized borrowings at interest rates based on either competitive bid, prime rate, or LIBOR and is scheduled to expire in June 2003. This facility has an optional conversion to a one-year term loan. Commitment fees are based upon Cleco Power's lowest secured debt rating and are currently 0.10%. The facility provides support for the issuance of commercial paper and working capital needs. At December 31, 2002, there was an outstanding draw in the amount of $107.0 million under this credit facility. As of December 31, 2002, Cleco Power was in compliance with the covenants in this credit facility.

On June 25, 2001, Midstream became a party to 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 further amended and restated, including new terms for principal and interest payments through March 2004. The interest rate on this credit facility resets quarterly, is based on LIBOR plus 2.50%, and was 4.375% at December 31, 2002. Under the terms of Midstream's line of credit, $1.8 million of APH's cash is restricted. At December 31, 2002, there was an outstanding draw in the amount of $36.8 million under this credit facility. As of December 31, 2002, Midstream was in compliance with the covenants in this credit facility.

In connection with existing project financing at Perryville, Mirant Corporation (Mirant) issued a $100.0 million subordinated loan to PEP in August 2002. The proceeds from the $100.0 million subordinated debt were used to repay senior project debt. In the event of a payment default under the Perryville Tolling Agreement, Mirant has guaranteed either to pay PEP, on behalf of MAEM, any outstanding amounts under the Perryville Tolling Agreement, or to allow any outstanding amounts to be offset against the subordinated loan principal and interest payments, including accrued and unpaid interest from PEP. The amount of Mirant's guarantee is limited to the principal amount outstanding and accrued and unpaid interest under the subordinated debt. The subordinated debt and associated guarantee mature on October 1, 2007, unless MAEM is in payment default under the Perryville Tolling Agreement. ; If MAEM is in payment default, then Cleco Corporation has the right to extend the maturity of both the subordinated debt and associated guarantee for another five years. For more information regarding PEP guarantees, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements - Off-Balance Sheet Commitments." On October 1, 2002, the remainder of PEP's $151.9 million construction loan was terminated and replaced with a five-year loan with a group of lenders with KBC Bank N.V. (KBC) acting as agent (the KBC loan) in the amount of $145.8 million, after savings on construction were applied. The interest rate on both loans resets quarterly, is based on LIBOR plus a spread, and was 3.28% at December 31, 2002. The spread is 1.50% for the first two years and 1.65% for the remaining three years. The loans provide for quarterly principal and interest payment s.

Cleco Corporation provides a guarantee to pay interest and principal under the KBC loan should PEP be unable to pay its debt service. At December 31, 2002, the amount guaranteed was $6.9 million. Also, under the terms of the KBC loan, specified amounts are required to be maintained in restricted cash accounts for debt service payments, major maintenance, and operating needs. The KBC loan is collateralized by Cleco Corporation's membership interest in PEP. The Mirant loan also is collateralized by Cleco Corporation's membership interest in PEP, subordinate to claims under the KBC loan. The KBC loan is scheduled to mature on October 1, 2007, and the Mirant loan is scheduled to mature on December 31, 2007.

If our counterparties fail to perform their obligations under the Perryville Tolling Agreement or the Evangeline Tolling Agreement, the KBC loan and Evangeline LLC senior secured bonds could be affected. Under provisions of the KBC loan, lenders holding two-thirds of the loan commitment have the right to cause the entire outstanding principal amount ($145.1 million as of December 31, 2002), plus accrued interest, to be immediately due and payable upon a default under the Perryville Tolling Agreement by MAEM. Under provisions of the bonds issued by Evangeline LLC, the bondholders have the right to cause the entire outstanding principal amount ($208.8 million as of December 31, 2002) plus accrued interest to be immediately due and payable upon a default under the Evangeline Tolling Agreement by Williams Energy.

Total indebtedness as of December 31, 2002, and 2001, was as follows:

	At December 31,
	2002	2001
	(Thousands)
Commercial paper, net	$ -	$ 100,675
Short-term bank loans	315,300	78,880
Total short-term debt	$ 315,300	$ 179,555

Senior notes, 8.75%, due 2005	$ 100,000	$ 100,000
First mortgage bonds
Series X, 9.5%, due 2005	60,000	60,000
Pollution control revenue bonds, 5.875%, due 2029, callable after September 1, 2009	61,260	61,260
Medium-term notes
7.55%, due 2004, called at 100%, in 2002	-	15,000
7.50%, due 2004, called at 100%, in 2002	-	10,000
7.00%, due 2003	10,000	10,000
6.55%, due 2003	15,000	15,000
6.33%, due 2002	-	25,000
6.20%, due 2006	15,000	15,000
6.95%, due 2006	10,000	10,000
6.53%, due 2007	10,000	10,000
6.32%, due 2006	15,000	15,000
7.50%, due 2007	15,000	15,000
7.00%, due 2007	25,000	25,000
6.52%, due 2009	50,000	50,000
Total medium-term notes	165,000	215,000
Insured quarterly notes
6.125%, due 2017, callable after March 1, 2005	25,000	-
6.05%, due 2012, callable after June 1, 2004	50,000	-
Total insured quarterly notes	75,000	-

Senior secured bonds, 8.82%, due 2019	208,762	214,228
KBC loan, 3.28%, due 2007	145,059	-
Mirant loan, 3.28%, due 2007	99,550	-
Long-term bank loans	-	7,361
Other long-term debt	197	573
Gross amount of long-term debt	914,828	658,422
Less:
Amount due within one year	(45,401)	(30,843)
Unamortized premium and discount, net	(743)	(802)

Total long-term debt, net	$ 868,684	$ 626,777

The amounts payable under long-term debt agreements for each year through 2007 and thereafter are listed below:

	2003	2004	2005	2006	2007	Thereafter
Amounts payable under long-term debt agreements	$45,401	$13,891	$174,346	$54,971	$262,900	$363,319

The weighted average interest rate on short-term debt at December 31, 2002, was 2.57% compared to 4.20% at December 31, 2001.

The first mortgage bonds are collateralized by the LPSC-jurisdictional property, plant and equipment 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.

The senior secured bonds are collateralized with the Evangeline generation station assets held by Evangeline LLC.

In May 2000, Cleco Corporation sold $100.0 million aggregate principal amount of its five-year senior notes. These notes bear interest at 8.75% per year, mature on June 1, 2005, and are uncollateralized. Approximately $50.0 million of the proceeds from the sale of the notes was used to pay down commercial paper financing, and the remainder was used to invest in joint ventures.

In March 2001, The Bank of New York issued a $15.0 million standby letter of credit on behalf of Evangeline LLC to Williams Energy, pursuant to the Evangeline Tolling Agreement between Williams Energy and Evangeline LLC. The Evangeline Tolling Agreement expires in July 2020. The letter of credit is renewed annually and requires no compensating balances. Letters of credit are issued under Cleco Corporation's revolving credit facility.

On June 14, 2002, Cleco Power gave formal notice of its intention to redeem $15.0 million of 7.55% medium-term notes due July 15, 2004, and $10.0 million of 7.50% medium-term notes due July 15, 2004. Both series of notes became redeemable at Cleco Power's option on July 15, 2002. The notes were repaid on July 15, 2002, with proceeds from commercial paper issuances.

NOTE 6 - COMMON STOCK

In association with incentive compensation plans in effect during the three-year period ended December 31, 2002, certain officers and key employees of Cleco Corporation and its subsidiaries 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 in which the restrictions lapse. As of December 31, 2002, the number of shares of restricted stock previously granted for which restrictions had not lapsed totaled 322,198 shares.

We record 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 Corporation or its subsidiaries. During 2002, Cleco Corporation granted basic nonqualified stock options under the incentive compensation plan. Basic options have an exercise price approximately equal to the fair market value of the stock at grant date. Options granted in 2002 vest one-third each year, beginning on the third anniversary of the grant date, and expire after 10 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, 2002, were as follows:

	Incentive Share
	Option Price per Share		Unexercised Option Shares	Available for Future Grants
Balance, January 1, 2000			1,115,962	165,434

Expiration of 1999 LTIP			-	(165,434)
Approval of 2000 LTIP			-	1,600,000
Options forfeited	$	16.1250	(9,600)	9,600
Options forfeited	$ $	19.205 to 21.580	(30,000)	30,000
Options granted (directors)	$	17.3150	20,000	(20,000)
Options granted - basic (employees)	$	17.3150	8,000	(8,000)
Options granted - premium (employees)	$ $	20.620 to 23.170	54,000	(54,000)
Options granted - basic (employees)	$	18.4400	37,800	(37,800)
Options granted - premium (employees)	$ $	21.960 to 24.675	54,000	(54,000)
Restricted stock granted			-	(142,852)
Restricted stock forfeited			-	2,956

Balance, December 31, 2000			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	$	16.130	(24,000)	-
Options forfeited	$	16.130	(20,000)	20,000
Options forfeited	$	22.250	(26,099)	26,099
Options forfeited	$	17.32	(1,333)	1,333
Options forfeited	$	24.25	(13,333)	13,333
Options forfeited - premium (employees)	$ $	19.21 to 21.58	(100,666)	100,666
Options forfeited - premium (employees)	$ $	20.62 to 23.17	(16,000)	16,000
Options granted (directors)	$	18.125	22,500	(22,500)
Options granted - basic (employees)	$	24.250	82,100	(82,100)
Options granted - (directors)	$	24.000	20,000	(20,000)
Restricted stock granted			-	(147,447)
Restricted stock forfeited			-	10,189

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

At December 31, 2002, we had two stock-based compensation plans. We apply APB Opinion No. 25 and related interpretations in accounting for our plans. Accordingly, no compensation cost has been recognized for our stock options issued pursuant to our long-term incentive compensation plan and stock issued under our Employee Stock Purchase Plan (ESPP). The compensation cost that has been recognized in income for restricted stock issued pursuant to our long-term

incentive plan was $6.6 million, $5.0 million, and $3.5 million for 2002, 2001, and 2000, respectively. Had the compensation expense for Cleco Corporation's stock-based compensation plans been determined consistent with SFAS No. 123, our net income and net income per common share would approximate the pro forma amounts below:

	For the year ended December 31,
	2002		2001		2000
	As Reported	Pro Forma	As Reported	Pro Forma	As Reported	Pro Forma
	(Thousands, except per share amounts)
SFAS No. 123 expense	$ -	$ 654	$ -	$ 589	$ -	$ 311
Estimated reduction in income tax for SFAS No. 123 expense	-	(242)	-	(204)	-	(103)
Net income applicable to common stock	$ 70,003	$ 69,591	$ 68,362	$ 67,977	$63,112	$62,904
Net income per basic common share	$ 1.51	$ 1.50	$ 1.52	$ 1.51	$ 1.41	$ 1.40

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

	For the year ended December 31,
	2002	2001	2000
Expected term (in years)	5.66	5.85	5.26
Volatility	28.0%	15.13%	14.22%
Expected dividend yield	3.95%	4.20%	4.75%
Risk-free interest rate	3.71%	4.87%	6.32%
Weighted average fair value (Black-Scholes value)	$ 4.13	$ 2.82	$ 3.01

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 our stock-based compensation plans.

The following table summarizes information about employee and director stock options outstanding at December 31, 2002:

Options Outstanding
Range of Exercise Price	Number Outstanding	Number Exercisable at 12/31/2002	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life
$15.938	23,338	23,338	$15.938	5.33
$15.938	10,000	10,000	$15.938	6.38
$16.125	245,400	81,800	$16.125	6.56
$19.205 to $21.58	472,134	157,378	$20.380	6.56
$15.938	556	556	$15.938	6.96
$17.315	26,667	20,000	$17.315	7.33
$20.62 to $23.17	38,000	-	$21.883	7.33
$18.44	37,800	-	$18.440	7.58
$21.96 to $24.675	54,000	-	$23.305	7.58
$22.6875	10,000	10,000	$22.688	8.33
$23.25	3,334	3,334	$23.250	8.42
$22.25	213,901	25,000	$22.250	8.58
$20.375	9,000	-	$20.375	8.76
$24.25	68,767	-	$24.250	9.30
$24.00	20,000	20,000	$24.000	9.33
$18.125	22,500	22,500	$18.125	9.56

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 that common shareholders' equity not be less than 35% of total capitalization, including short-term debt and excluding Midstream nonrecourse debt. At December 31, 2002, approximately $69.7 million of retained earnings was not restricted.

SHAREHOLDER RIGHTS PLAN

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.

EMPLOYEE STOCK PURCHASE PLAN

In January 2000, Cleco Corporation's Board of Directors adopted the ESPP. Shareholders approved the plan in April 2000. The ESPP provides the opportunity for employees to purchase shares of Cleco Corporation's common stock at a discounted price. Cleco Corporation implemented the ESPP 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 automatic ally 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, 2002, there were 591,748 shares of common stock left to be purchased under the ESPP.

STOCK SPLIT

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.

COMMON STOCK ISSUANCE

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.

COMMON STOCK REPURCHASE PROGRAM

In 1991, we began a common stock repurchase program, in which up to $30.0 million of common stock may be repurchased. At December 31, 2002, approximately $16.1 million of common stock was available for repurchase under this program. Purchases will be 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. We did not purchase any common stock under the repurchase plan in 2002 or 2000, but did purchase $3.0 million of common stock during 2001.

NOTE 7 - EXTRAORDINARY GAIN

In March 2000, Four Square Gas, a wholly owned subsidiary of Cleco Energy, which is wholly owned by Midstream, paid a third party $2.1 million for a note with a face value of approximately $6.0 million issued by Four Square Production, another wholly owned subsidiary of Cleco Energy. The note relates to the production assets held by Four Square Production. As part of the transaction, the third-party debt-holder sold the note, associated mortgage, deed of trust, and pledge agreement, and assigned a 5% overriding royalty interest in the production assets to Four Square Gas. Four Square Gas paid, in addition to the $2.1 million, a total of 4.5% in overriding royalty interest in the production assets. Four Square Gas borrowed the $2.1 million from Cleco Corporation. The gain of approximately $3.9 million was offset against the $1.4 million of income tax related to the gain to arrive at the extra ordinary gain, net of income tax, of approximately $2.5 million.

NOTE 8 - PREFERRED STOCK

Within the ESOP, each share of Cleco Corporation 8.125% preferred stock is convertible into 9.6 shares of Cleco Corporation common stock. The amount of total capitalization reflected in the 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 the consolidated financial statements for preferred dividend requirements in 2002, 2001, and 2000 have been reduced by approximately $266,000, $326,000, and $391,000, 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)			2000	CHANGE	2000	CHANGE	2001	CHANGE	2002

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	27,851	(790)	27,061	(764)	26,297	(748)	25,549
			$ 28,880	$ (790)	$ 28,090	$ (764)	$ 27,326	$ (748)	$ 26,578

Deferred compensation related to
	convertible preferred stock held by the ESOP		$ (14,991)	$ 1,997	$ (12,994)	$ 1,656	$ (11,338)	$ 2,268	$ (9,070)
					.
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	288,804	(7,904)	280,900	(7,640)	273,260	(7,480)	265,780

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.

	Optional Redemption
	Price per Share
Series
4.50%	$101
Convertible, Series of 1991	$100.8125 to $100

NOTE 9 - PENSION PLAN AND EMPLOYEE BENEFITS

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. No contributions to the pension plan were required during the three-year period ended December 31, 2002. Cleco Power is considered the plan sponsor, and Cleco Support Group LLC (Support Group) is considered the plan administrator.

Cleco Corporation's retirees and their dependents are eligible to receive health, dental 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, 2002, and 2001, are presented in the following table.

	Pension Benefits		Other Benefits
	2002	2001	2002	2001
	(Thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$ 161,111	$129,611	$ 22,288	$ 18,213
Service cost	4,653	3,932	1,309	1,076
Interest cost	11,502	10,697	1,828	1,484
Plan participants' contributions	-	-	432	518
Amendments	166	1,629	-	-
Special termination benefits	1,599	-	150	-
Curtailment loss (gain)	987	-	(918)	-
Actuarial loss	18,631	23,742	8,614	2,081
Expenses paid	(982)	(1,202)	-	-
Benefits paid	(8,283)	(7,298)	(1,874)	(1,084)
Benefit obligation at end of year	189,384	161,111	31,829	22,288

Change in plan assets
Fair value of plan assets at beginning of year	191,950	194,834	-	-
Actual return on plan assets	(14,707)	5,616	-	-
Expenses paid	(982)	(1,202)	-	-
Benefits paid	(8,283)	(7,298)	-	-
Fair value of plan assets at end of year	167,978	191,950	-	-

Funded status	(21,406)	30,839	(31,829)	(22,288)
Unrecognized net actuarial loss (gain)	30,453	(23,194)	7,877	(329)
Unrecognized transition obligation/(asset)	(1,355)	(2,673)	4,597	5,646
Unrecognized prior service cost	10,486	12,368	-	-
Prepaid/(accrued) benefit cost	$ 18,178	$ 17,340	$ (19,355)	$ (16,971)

Employee pension plan assets are invested in Cleco Corporation's common stock, other publicly traded domestic common stocks, U.S. government, federal agency and corporate obligations, an international equity fund, commercial real estate funds, and pooled temporary investments.

The components of net periodic pension and other benefits cost (income) for 2002, 2001, and 2000 are as follows, along with assumptions used:

	Pension Benefits			Other Benefits
	2002	2001	2000	2002	2001	2000
	(Thousands)
Components of periodic benefit costs
Service cost	$ 4,653	$ 3,932	$ 3,825	$ 1,309	$ 1,076	$ 848
Interest cost	11,502	10,697	9,706	1,828	1,484	1,321
Expected return on plan assets	(18,687)	(17,404)	(15,912)	-	-	-
Special termination benefits	1,599	-	-	150	-	-
Curtailment loss	987	-	-	-	-	-
Amortization of transition obligation/(asset)	(1,318)	(1,318)	(1,318)	492	513	513
Prior period service cost amortization	1,062	1,067	969	-	-	-
Net (gain) loss amortization	(635)	(1,650)	(1,194)	47	(2)	5
Net periodic benefit cost/(income)	$ (837)	$ (4,676)	$ (3,924)	$ 3,826	$ 3,071	$ 2,687

	Pension Benefits			Other Benefits
	2002	2001	2000	2002	2001	2000
Weighted-average assumptions as of December 31:
Discount rate	6.50%	7.25%	8.00%	6.50%	7.25%	8.00%
Expected return on plan assets	9.00%	9.50%	9.50%	N/A	N/A	N/A
Rate of compensation increase	5.00%	5.00%	5.00%	N/A	N/A	N/A

At December 31, 2002, and 2001, 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.

In the fourth quarter of 2002, we recognized a restructuring charge of $10.2 million. A portion of the restructuring charge arose from a curtailment loss of $987,000, special termination benefits of $1.6 million related to the pension plan, and special termination benefits of $150,000 related to other benefits. For more information about the restructuring charge, see Note 20 - "Restructuring Charge."

The assumed health care cost trend rates used to measure the expected cost of other benefits were 11.0% in 2002, 9.0% in 2001, and 8.0% in 2000. The rate declines to 4.5% by 2010 and remains at 4.5% thereafter. The initial health care cost trend rate was increased from 9.0% in 2001 to 11.0% in 2002. This 2.0% increase resulted in an unrecognized net actuarial loss of $7.9 million in 2002, compared with a gain of $329,000 in 2001, which is reflected in the Funded Status section of Other Benefits. 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:

	1-percentage point
	Increase	Decrease
	(Thousands)
Effect on total of service and interest cost components	$ 266	$ (276)
Effect on post-retirement benefit obligation	$ 1,916	$ (1,969)

Certain key executives and key managers are covered by a Supplemental Executive Retirement Plan (SERP). The SERP is a noncontributory, 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. No contributions to the SERP were made during the three-year period ended December 31, 2002. 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, 2002, and 2001, are presented in the following table.

	SERP Benefits
	2002	2001
	(Thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$ 11,525	$ 7,861
Service cost	606	394
Interest cost	952	772
Amendments	(197)	-
Actuarial loss	3,677	3,029
Benefits paid	(545)	(531)
Benefit obligation at end of year	16,018	11,525

Funded status	(16,018)	(11,525)
Unrecognized net actuarial loss	7,111	3,748
Unrecognized transition obligation	-	291
Unrecognized prior service cost	(95)	95
Accrued benefit cost	$ (9,002)	$ (7,391)

The components of the net SERP cost for 2002, 2001, and 2000 are as follows, along with assumptions used.

	SERP Benefits
	2002	2001	2000
Components of periodic benefit costs
Service cost	$ 606	$ 394	$ 333
Interest cost	952	772	579
Amortization of transition obligation	291	295	295
Prior period service cost amortization	(7)	16	16
Net loss amortization	314	137	49
Net periodic benefit cost	$ 2,156	$ 1,614	$ 1,272

	SERP Benefits
	2002	2001	2000
Weighted-average assumptions as of December 31:
Discount rate	6.50%	7.25%	8.00%
Expected return on plan assets	N/A	N/A	N/A
Rate of compensation increase	5.00%	5.00%	5.00%

During 2002, we recorded a reduction in other comprehensive income of $4.0 million net of the associated income tax benefit of $1.5 million due to the recognition of an additional minimum pension liability for the SERP, as defined by SFAS No. 87, "Employers' Accounting for Pensions." The accumulated other comprehensive loss associated with the recognition of the minimum pension liability is also $2.5 million.

Most employees are eligible to participate in a savings and investment plan (401(k) 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, 2002, and 2001, the ESOP had allocated to employees 181,329 and 163,487 shares, respectively.

The table below contains information about the 401(k) Plan and the ESOP:

	For the year ended December 31,
	2002	2001	2000
	(Thousands)
401(k) Plan expense	$ 1,142	$ 803	$ 1,061
Dividend requirements to ESOP on convertible preferred stock	$ 2,092	$ 2,155	$ 2,231
Interest incurred by ESOP on its indebtedness	$ 770	$ 914	$ 1,109
Company contributions to ESOP	$ 1,408	$ 520	$ 1,391

NOTE 10 - INCOME TAX EXPENSE

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,
	2002		2001		2000
	(Thousands, except for %)
	Amount	%	Amount	%	Amount	%
Book income before tax	$114,118	100.0	$110,629	100.0	$104,296	100.0
Tax at statutory rate on book income before tax	39,941	35.0	38,720	35.0	36,504	35.0
Increase (decrease):
Tax effect of AFUDC	(1,421)	(1.2)	(2,452)	(2.2)	(2,113)	(2.0)
Amortization of investment tax credits	(1,743)	(1.5)	(1,765)	(1.6)	(1,742)	(1.7)
Tax effect of prior-year tax benefits not deferred	391	0.3	797	0.7	988	0.9
Other, net	971	0.8	(673)	(0.6)	(2,262)	(2.1)
Total federal income tax expense	38,139	33.4	34,627	31.3	31,375	30.1
Current and deferred state income tax expense, net of federal benefit for state income tax expense	4,104	3.6	3,729	3.4	3,586	3.4
Total federal and state income tax expense	$ 42,243	37.0	$ 38,356	34.7	$ 34,961	33.5

Information about current and deferred income tax expense is as follows:

	For the year ended December 31,
	2002	2001	2000
	(Thousands)
Current federal income tax expense	$ (35,026)	$ 40,448	$ 26,381
Deferred federal income tax expense	72,876	(5,903)	4,960
Amortization of accumulated deferred investment tax credits	(1,743)	(1,765)	(1,742)
Total federal income tax expense	36,107	32,780	29,599
Current state income tax expense	(48)	6,571	4,224
Deferred state income tax expense	6,184	(995)	1,138
Total state income tax expense	6,136	5,576	5,362
Total federal and state income tax expense	$ 42,243	$ 38,356	$ 34,961
Discontinued operations
Income tax expense from loss from operations
Federal current	$ -	$ -	$ (2,344)
Federal deferred	-	-	(157)
State current	-	-	(361)
State deferred	-	-	(25)
Total tax expense from loss from discontinued operations	$ -	$ -	$ (2,887)
Income tax expense from loss on disposal of segment
Federal current	$ -	$ (2,624)	$ -
Federal deferred	-	1,522	(1,215)
State current	-	(610)	-
State deferred	-	437	(196)
Total tax expense from loss on disposal of segment	$ -	$ (1,275)	$ (1,411)
Income tax expense from gain on extraordinary item
Federal current	$ -	$ -	$ 1,468
Total federal and state income tax expenses	$ 42,243	$ 37,081	$ 32,131

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2002, and 2001, was comprised of the tax effect of the following:

	At December 31,
	2002		2001
	Current	Noncurrent	Current	Noncurrent
	(Thousands)
Depreciation and property basis differences	$ -	$ (246,816)	$ -	$ (156,382)
State net operating tax losses	-	2,513	-	-
SERP - Other comprehensive income	-	1,548	-	-
Allowance for funds used during construction	-	(30,328)	-	(30,018)
Investment tax credits	-	13,426	-	15,196
SFAS No. 109 adjustments	236	(43,799)	-	(40,621)
Post retirement benefits other than pension	4,365	5,302	3,802	3,661
Other	(772)	(865)	387	(298)
Accumulated deferred federal and state income taxes	$ 3,829	$ (299,019)	$ 4,189	$ (208,462)

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, 2002, and 2001, were $65.3 million and $58.5 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.

NOTE 11 - DISCLOSURES ABOUT SEGMENTS

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

(THOUSANDS)
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	30,050	-	1	30,081
Other operations	29,301	4,655	88	(38)	34,006
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
Interest charges	29,091	31,750	13,533	(13,765)	60,609
Federal and state income taxes	32,172	12,740	(2,495)	(174)	42,243
Segment profit (loss) from continuing operations (1)	$ 59,574	$ 14,660	$ (2,359)	$ -	$ 71,875
Segment assets	$ 1,338,495	$ 978,947	$ 631,389	$ (604,225)	$ 2,344,606

(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


2001

(THOUSANDS)
Revenue
Electric operations	$ 592,253	$ -	$ -	$ -	$ 592,253
Tolling operations	-	60,522	-	-	60,522
Energy trading, net	1,456	5,608	-	(15)	7,049
Energy operations	-	58,659	-	-	58,659
Other operations	30,813	1,135	101	27	32,076
Electric customer credits	(1,800)	-	-	-	(1,800)
Intersegment revenue	6,011	13,947	70,762	(90,720)	-
Total operating revenue	$ 628,733	$ 139,871	$ 70,863	$ (90,708)	$ 748,759

Depreciation expense	$ 50,594	$ 9,379	$ 460	$ -	$ 60,433
Interest charges	26,819	21,010	12,061	(12,197)	47,693
Federal and state income taxes	31,290	8,676	(1,610)	-	38,356
Segment profit (loss) from continuing operations	$ 59,138	$ 14,511	$ 51,415	$ (52,791)	$ 72,273
Loss on disposal of segment, net	-	-	(2,035)	-	(2,035)
Segment profit (loss) (1)	$ 59,138	$ 14,511	$ 49,380	$ (52,791)	$ 70,238
Segment assets	$ 1,185,223	$ 558,985	$ 488,883	$ (465,201)	$ 1,767,890

(1) Reconciliation of segment profit (loss) to consolidated profit:
Segment profit			$ 70,238
Unallocated items
Preferred dividends			(1,876)
Net income applicable to common stock			$ 68,362

2000	Cleco Power	Midstream	Other	Unallocated Items, Reclassifications & Eliminations	Consolidated

(THOUSANDS)
Revenue
Electric operations	$ 591,298	$ -	$ -	$ -	$ 591,298
Tolling operations	-	41,354	-	-	41,354
Energy trading, net	4,495	7,381	-	-	11,876
Energy operations	-	3,601	-	-	3,601
Other operations	28,230	118	73	(3)	28,418
Electric customer credits	(1,233)	-	-	-	(1,233)
Intersegment revenue	9,256	37,667	103,360	(150,283)	-
Total operating revenue	$ 632,046	$ 90,121	$ 103,433	$ (150,286)	$ 675,314

Depreciation expense	$ 49,787	$ 5,952	$ 101	$ -	$ 55,840
Interest charges	28,722	13,471	7,207	(2,413)	46,987
Federal and state income taxes	30,998	5,327	(1,364)	-	34,961
Segment profit (loss) from continuing operations	$ 59,857	$ 9,894	$ 58,994	$ (59,410)	$ 69,335
Loss on disposal of segment, net	-	-	(6,861)	-	(6,861)
Extraordinary gain, net	-	2,508	-	-	2,508
Segment profit (loss) (1)	$ 59,857	$ 12,402	$ 52,133	$ (59,410)	$ 64,982

Segment assets	$ 1,211,191	$ 366,162	$ 443,063	$ (387,416)	$ 1,633,000

(1) Reconciliation of segment profit (loss) to consolidated profit:
Segment profit			$ 64,982
Unallocated items
Preferred dividends			(1,870)
Net income applicable to common stock			$ 63,112

Our reportable segments are determined by our method of internal reporting, which disaggregates our business units by second-tier subsidiary. Our reportable segments are Cleco Power and Midstream. The Other segment consists of the holding company, a shared services subsidiary, an investment subsidiary, and the discontinued operations of UTS. The Other segment subsidiaries operate within Louisiana and Delaware. We have determined that UTS is no longer a reportable segment since it no longer engages in business activities, and management has judged it is not of continuing significance. For additional information about the disposal of UTS, see Note 17 - "Discontinued Operations."

Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco Corporation's Chief Executive Officer (the chief decision-maker) with discrete financial information and, at least quarterly, present discrete financial information to Cleco Corporation's Board of Directors. Each reportable segment prepared budgets for 2002 that were presented to and approved by Cleco Corporation's Board of Directors.

The financial results of Cleco Corporation'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 income taxes and preferred stock dividends. Material intersegment transactions occur on a regular basis.

NOTE 12 - ACCRUAL OF ESTIMATED CUSTOMER CREDITS

Cleco Corporation's reported earnings for December 31, 2002, reflect a $2.9 million accrual within Cleco Power for estimated 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 the year 2004, and also provided for annual base rate tariff reductions of $3.0 million in 1997 and $2.0 million in 1998. 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

12-month-ending results as of September 30 of each year. The settlement provides for such credits to be made on customers' bills the following summer. The LPSC's preliminary report for the 12-month ended September 30, 2001, cycle required a $0.6 million refund, which was credited to customers' bills in September 2002. We anticipate receiving the final report for the September 30, 2001, cycle in the second quarter of 2003.

The $2.9 million accrual relates to the 12-month cycles ending September 30, 2001, 2002, and 2003. 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 our assessment of issues that remain outstanding.

NOTE 13 - EQUITY INVESTMENT IN INVESTEES

Equity investment in investees represents Midstream's approximate $273.0 million investment in Acadia Power Partners LLC (APP) and Cleco Energy's approximate $0.7 million investment in Hudson SVD LLC (Hudson). Midstream's portion of earnings from APP for the year 2002, approximately $14.8 million, is included in the $273.0 million equity investment in APP. Midstream's portion of earnings from PEP for the six months ended June 30, 2002, was approximately $1.4 million. For the year 2002, no material earnings have been recorded for Hudson.

Cleco Corporation accounted for PEP as an equity investment in 2001 and the first six months of 2002. On June 20, 2002, Midstream purchased Mirant's 50% ownership interest in PEP through an intercompany loan from Cleco Corporation. Cleco Corporation discontinued the equity method of accounting for its ownership interest in PEP effective July 1, 2002, and consolidated PEP's assets and liabilities as of June 30, 2002. For additional information regarding this purchase, see Note 21 - "Acquisition."

APP is a joint venture owned 50% by Midstream and 50% by Calpine Corporation (Calpine). APP was formed to construct, own and operate a 1,160-MW combined-cycle, natural gas-fired power plant located near Eunice, Louisiana (Acadia). Total construction costs of the plant incurred by APP were $502.7 million. APH capitalized $19.5 million of costs, which consisted of interest and other miscellaneous charges related to the construction of APP. Cleco Corporation reports its investment in APP on the equity method of accounting as defined in APB Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." As of December 31, 2002, Midstream had invested $273.0 million in APP. This equity investment consists of cash, land, and Midstream's portion of earnings from the joint venture. Midstream's member's equity as reported in the balance she et of APP at December 31, 2002, was $253.5 million. The difference of $19.5 million between the equity investment in investee and the member's equity was primarily the interest capitalized on funds used to contribute to APP. The table below is unaudited summarized financial information for 100% of APP. No income statement information is presented for 2001, during which time Acadia was in the construction phase and all costs were capitalized. Construction on Power Block 1 at APP (PB1), which is tolled to Aquila Energy Marketing Corporation (Aquila Energy), was completed on July 1, 2002, and construction on Power Block 2 at APP (PB2), which is tolled to Calpine, was completed on August 2, 2002.

	Unaudited At December 31,
	2002	2001
	(Thousands)
Current assets	$ 12,719	$ 16,954
Property, plant & equipment, net	496,098	-
Construction work in progress	-	426,666
Other assets	2,469	-
Total assets	$ 511,286	$ 443,620
Current liabilities	$ 4,207	$ 22,870
Partners' capital	507,079	420,750
Total liabilities and partners' capital	$ 511,286	$ 443,620

	Unaudited Year Ended December 31,
	2002	2001
	(Thousands)
Total revenue	$ 49,102	$ -
Total operating expenses	19,405	-
Net income	$ 29,697	$ -

For information about guarantees issued by Cleco Corporation on behalf of APP, see Note 23 - "Disclosures About Guarantees."

Cleco Energy owns 50% of Hudson, which indirectly owns and operates natural gas pipelines in Texas and Louisiana. Hudson also owns a controlling interest in an entity that owns and operates a pipeline system in Texas. The member's equity as reported in the balance sheet was approximately $0.7 million, which equals the investment at Cleco Energy.

NOTE 14 - OPERATING LEASES

Under the terms of the Evangeline and Perryville Tolling Agreements, the two tolling counterparties have the right to own, dispatch, and market all of the electric generation capacity produced by our tolled facilities and are responsible for providing the required natural gas to the facilities. We collect a fee from the tolling counterparties for operating and maintaining the tolled facilities. Both tolling agreements have terms that extend until at least 2020. The tolling agreements are accounted for as operating leases and their revenues are recognized as described in Note 2 - "Summary of Significant Accounting Policies - Revenue and Fuel Costs."

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

	At December 31,
	2002	2001
	(Thousands)
Tolled power plants	$ 548,478	$ 224,795
Construction work in progress	793	519
Less: accumulated depreciation	23,764	11,406
Net plant	$ 525,507	$ 213,908

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

Year ending December 31,	(Thousands)
2003	$ 102,942
2004	103,475
2005	104,013
2006	104,557
2007	105,109
Thereafter	1,456,068
Total future rental payments	$ 1,976,164

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 counterparties under the tolling agreements. For the year ended December 31, 2002, tolling rental revenue of $90.3 million was recognized, including contingent rents of approximately $9.4 million. For the years ended December 31, 2001, and 2000, contingent rents were approximately $4.2 million and $1.0 million, respectively.

For information relating to the acquisition of additional ownership interest during 2002 related to Perryville tolling agreement, see Note 21 - "Acquisition."

NOTE 15 - CHANGE IN ACCOUNTING ESTIMATE

Evangeline LLC and PEP 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 LLC's plant assets were extended from 27 to 46 years and the estimated service lives for PEP'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 PEP's asset lives being extended during 2002, component depreciation escalated depreciation expense for the year, offsetting what would otherwise be 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.

NOTE 16 - SECURITIES LITIGATION AND OTHER
COMMITMENTS AND CONTINGENCIES

On November 22, 2002, a lawsuit (Securities Litigation) was filed in the Ninth Judicial District Court, Rapides Parish, State of Louisiana, purportedly on behalf of a class of persons or entities who purchased Cleco Corporation's common stock during a specified period of time (Class Period). 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, where it currently is pending. The Securities Litigation is still in its formative stages. Based on information currently available to management, we do not

believe the Securities Litigation will have a material adverse effect on our financial condition or results of operations.

We are 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, we have been named as a defendant by individuals who claim injury due to exposure to asbestos while working at sites in central Louisiana. Most of these 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 us. Our management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Our management believes that the disposition of these matters will not have a material adverse effect on our financial condition, result s of operations, or cash flows.

For information regarding off-balance sheet commitments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements - Off-Balance Sheet Commitments." 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.

NOTE 17 - DISCONTINUED OPERATIONS

In December 2000, management decided to sell substantially all of the UTS assets and discontinue UTS' operations after the sale. On March 31, 2001, management signed an asset purchase agreement to sell UTS to Quanta Services, Inc. (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, 2002, UTS had only nominal assets since receivables have been either collected or written off.

As of December 31, 2002, several contingent liabilities relating to UTS existed. Under the asset purchase agreement, UTS and its sole member have agreed to indemnify Quanta for losses resulting from certain breaches or failures by UTS and its sole member to fulfill their obligations under the asset purchase agreement, for taxes and other losses arising from events occurring prior to the sale. The indemnification amount is limited to approximately $5.0 million and terminates on April 1, 2003. The limitation does not apply to fraudulent misrepresentations. At December 31, 2002, no amounts have been recorded for the indemnifications because no claim has been asserted by Quanta, and management has determined the possibility of a claim is not probable.

Additional information about UTS is as follows:

	For the year ended December 31,
	2002		2001		2000
	(Thousands)
Revenue	$	-	$	5,043	$	18,125
Loss from operations, net	$	-	$	-	$	(5,411)
Income tax benefit associated with
Loss from operations	$	172	$	-	$	3,390
Loss on disposal of segment, net	$	-	$	2,035	$	1,450
Income tax benefit associated with
Loss on disposal of segment	$	-	$	1,275	$	908

NOTE 18 - RISKS AND UNCERTAINTIES

Our tolling counterparties are Williams Energy, MAEM, Aquila Energy, and Calpine Energy Services, L.P. (CES). The following list discusses possible adverse consequences if any of our counterparties fail to perform their obligations under their respective tolling agreements. The list is not all-inclusive, but represents examples of possible adverse consequences resulting from the nonperformance of our tolling counterparties.

	Our financial condition and results of operations may be adversely affected by their failure to pay amounts due to us and may not be consistent with historical and projected results.
	We may not be able to enter into agreements in replacement of our existing tolling agreements on terms as favorable as our existing agreements or at all.
	We would be required to test any long-lived generation asset for impairment if the tolling counterparty defaulted under the related tolling agreement. If we determined that an impairment existed, the asset would be written down to its fair market value, which could materially adversely affect our results of operations and financial condition. For more information on long-lived assets, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -Critical Accounting Policies."
	Possible acceleration of our project-level debt, in particular:
	1) Under provisions of the PEP five-year loan, lenders holding two-thirds of the loan commitment have the right to cause the entire outstanding principal amount ($145.1 million at December 31, 2002) plus accrued interest to be immediately due and payable upon a default under the Perryville Tolling Agreement by MAEM. If the lenders were to exercise this right, we might, among other things, renegotiate the loan, refinance the loan, pay off the loan with other borrowings or the proceeds of issuances of additional debt, or cause PEP, as a stand-alone entity, to seek protection under federal bankruptcy laws. In addition, the lenders could foreclose on the mortgage and assume ownership of the plant. Any renegotiated loan or alternative financing would likely be on less favorable terms than the existing terms. For additional information on the loan, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - F inancial Condition- Liquidity and Capital Resources - Debt - Cleco Corporation (Holding Company Level)."

	2) Under provisions of the bonds issued by Evangeline LLC, the bondholders have the right to demand the entire outstanding principal amount ($208.8 million at December 31, 2002) 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, we 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 LLC, as a stand-alone entity, 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.

For information about the credit ratings of the parent companies of our counterparties, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - General Considerations and Credit-Related Risks."

NOTE 19 - REVIEW OF TRADING ACTIVITIES

Over the past few months, we have been reviewing certain energy trading activities, including transactions between Cleco Power and certain Midstream companies. We have determined that certain trading transactions may have violated the Public Utility Holding Company Act of 1935 as well as various statutes and regulations administered by the FERC and the LPSC.

We have contacted the appropriate regulatory authorities, including the staffs of the FERC and the LPSC, and have held discussions with them concerning indirect sales of test power by Evangeline LLC to Cleco Power, a regulated affiliate utility, other indirect acquisitions of purchased power by Cleco Power from Marketing & Trading, and Cleco Power's indirect sales of power to Marketing & Trading. These discussions have led to formal investigatory proceedings by the FERC and LPSC, with which we are cooperating. These proceedings entail discovery measures by the agencies of the referenced energy trading transactions and energy trading transactions in general between our power marketer subsidiaries. At the same time, we are continuing our own internal investigations of our subsidiaries' energy trading activities for regulatory compliance. These continuing governmental and internal investigations may result in determinations of violations in addition to those described in this Note.

The indirect sales of test power by Evangeline LLC occurred just prior to the commercial operation date of that plant in 2000. More specifically, Evangeline LLC sold test power directly to a third party to be resold to Cleco Power. In addition, Marketing & Trading purchased test power in 2002 from APP 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 LLC or Marketing & Trading and as Marketing & Trading's purchases from APP. The pricing to Cleco Power of these purchases of test power was $1.0 million in 2002 and $1.3 million in 2000. It appears some of these transactions have potentially exceeded the pricing standards of the FERC and the LPSC. In addition, these transactions may have violated the FERC's rules governing affiliate relations and the Exempt Wholesale Generator provisions of the Public Utility Holding Company Act of 1935. Management is unable to predict the remedial actions that may be taken with respect to these transactions by the governmental agencies involved.

Cleco Power's other indirect acquisitions of purchased power from Marketing & Trading occurred in 2002, 2001, and 2000. In these transactions, Marketing & Trading would purchase power and then sell some of this power to a third party, which then immediately would sell the same volume to Cleco Power. The pricing of these purchase transactions to Cleco Power was $0.8 million, $11.7 million, and $2.1 million for 2002, 2001, and 2000, respectively. It appears some of these transactions have potentially exceeded the pricing standards of the FERC and the LPSC. In addition, these transactions may have violated the FERC's rules governing affiliate relations.

During each of the years 2002, 2001, and 2000, Marketing & Trading also indirectly acquired purchased power from Cleco Power. In these transactions, Cleco Power would acquire wholesale power and sell it to a third party, which then immediately would sell the same volume to Marketing & Trading. The pricing of Marketing & Trading's purchase transactions from Cleco Power was approximately $1.7 million, $0.9 million, and $0.7 million for 2002, 2001, and 2000, respectively. These transactions may have violated the FERC's and LPSC's rules governing affiliate relations. Management is unable to predict what action the LPSC and the FERC will take with regard to these transactions and cannot reasonably estimate its minimum probable contingency for this exposure.

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 of the transactions described in this Note will be reviewed in Cleco Power's pending LPSC fuel audit. For additional information on the fuel audit, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Fuel Audit."

As a result of the transactions described in this Note (with the exception of those transactions described in the fifth paragraph of this Note), Cleco Power, Marketing & Trading, and Evangeline LLC have recorded reserves equal to the probable amounts management believes likely to be required by the LPSC and the FERC to be refunded to customers and/orassessed as a penalty. If the established reserves are less than the amount the companies are ultimately ordered to refund or pay as penalties by the LPSC or the FERC relating to these transactions, management believes any such additional amounts will not have a material adverse effect on our results of operations or financial condition. Additionally, as a result of the activities described in the four immediately preceding paragraphs, the FERC could elect to suspend the power market authorizations and related authorities of Cleco Power, Marketing & Trading and Evangeline LLC. Suspension of these authorizations and related authorities of one or more of these entities could have a material adverse effect on our results of operations and financial condition. Management is unable to predict the remedial actions, if any, that the FERC may take with respect to the power market authorizations and related authorities.

NOTE 20 - RESTRUCTURING CHARGE

On September 24, 2002, we announced a companywide organizational restructuring. During the fourth quarter of 2002, 123 employees accepted severance and 37 employees accepted an early retirement package. The majority of these employees left during the fourth quarter, resulting in 160 fewer employees. No particular group of employees was targeted. Employees who left due to the restructuring ranged from linemen to vice presidents of operating subsidiaries. The following table shows the type of charges incurred and the remaining balance in the associated liability accounts, where appropriate, that is still to be paid as of December 31, 2002.

Category of cost	Expensed	Paid	Liability remaining
	(Thousands)
Cash items
Severance and other employee payouts, including associated payroll taxes	$ 6,503	$ 1,236	$ 5,267
Lease termination payments	592	-	592
Other	49	49	-
Total cash items	7,144	1,285	5,859
Noncash items
Special termination benefits	2,736	-	-
Write-off of leasehold improvements	284	-	-
Total noncash items	3,020	-	-
Total	$ 10,164	$ 1,285	$ 5,859

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

NOTE 21 - ACQUISITION

On June 20, 2002, Midstream purchased Mirant's 50% ownership interest in PEP through an intercompany loan from Cleco Corporation. Midstream used the proceeds from the intercompany loan to pay 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. Mirant retains certain obligations as a project sponsor, some of which are subject to indemnification by Cleco Corporation. The obligations indemnified by Cleco Corporation relate to the construction of the plant. For information about potential amounts owed to the PEP plant construction contractor, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condit ion - Cash Generation and Cash Requirements - Off-Balance Sheet Commitments." Cleco Corporation used a combination of newly issued common equity and short-term debt to fund its acquisition of Mirant's interest in PEP. Cleco Corporation discontinued the equity method of accounting effective July 1, 2002, and consolidated PEP's assets and liabilities as of June 30, 2002. PEP's revenue and expenses were reported in the Statement of Income beginning July 1, 2002. As of December 31, 2002, PEP's assets and liabilities were $355.0 million and $269.3 million, respectively.

PEP, formerly a joint venture between Midstream and Mirant, completed constructing a 725-MW, natural gas-fired power plant in Perryville, Louisiana (Perryville) on June 30, 2002. A 157-MW combustion turbine operating in simple cycle became operational on July 1, 2001. Commercial operation of the 568-MW combined-cycle unit began on July 1, 2002. As of December 31, 2002, PEP had incurred $325.5 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 5 - "Debt."

Cleco Corporation's consolidated pro forma results, as if the acquisition had occurred on January 1, 2001, as shown below.

	For the year ended December 31,
	2002	2001
	(Thousands)
Revenue	$ 722,383	$ 752,036
Net income	$ 70,690	$ 68,814
Earnings per share (basic)	$ 1.53	$ 1.53
Earnings per share (diluted)	$ 1.49	$ 1.48

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

	At June 30, 2002
	(Thousands)
Current assets	$ 880
Property, plant and equipment	64,661
Construction work-in-progress	257,320
Other assets	5,075
Total assets	$ 327,936

Current liabilities	$ 11,892
Long-term debt	251,930
Member's equity	64,114
Total liabilities and member's equity	$ 327,936

NOTE 22 - GAS TRANSPORTATION CHARGES

During a review of an affiliate gas transportation contract, we determined that gas transportation charges billed by a subsidiary of Cleco Energy to Cleco Power may have exceeded the unregulated affiliate'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 under the circumstances.

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 is currently in discussions with the staff of the LPSC regarding these transactions. It is anticipated an audit will commence in the first quarter of 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 will be the first LPSC fuel adjustment clause audit of Cleco Power. Cleco Power has not been informed which time period will be covered by the audit, nor is management able to predict the results of the LPSC fuel audit. For additional information about Cleco Power's pending LPSC fuel audit, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Fuel Audit."

NOTE 23 - DISCLOSURES ABOUT GUARANTEES

Cleco Corporation and Cleco Power have agreed to contractual terms that require them to pay amounts to third parties upon the occurrence of certain triggering events on behalf of nonaffiliated entities. These contractual terms are generally defined as guarantees in FIN 45. Guarantees issued or modified after December 31, 2002, 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, 2002. The following paragraphs contain the disclosure requirements.

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 based on acts conducted in the discharge of their official capacity. Cleco Corporation has purchased various insurance policies to reduce the risks associated with the indemnification.

As a part of the sale of UTS, Cleco has agreed to indemnify the purchaser for losses resulting from certain breaches. For information regarding the sale of UTS and the related indemnities, see Note 17 - "Discontinued Operations."

Cleco Corporation has issued several guarantees on behalf of APP, which is accounted for on the equity method of accounting. One guarantee was issued to Aquila Energy, one of APP's tolling counterparties. Cleco Corporation will be required to make payments to the counterparty if APP fails to perform certain obligations under the Aquila Tolling Agreement. Cleco Corporation's obligation under this guarantee is limited to $12.5 million. This guarantee is in force until 2022. The other guarantee was issued to APP's construction contractor. If APP cannot pay the contractor who built its plant, Cleco Corporation will be required to pay the current amount outstanding. Cleco Corporation's obligation to the construction contractor is limited to 50% of the current total for the current contractor's amount outstanding. At December 31, 2002, Cleco Corporation's 50% portion of the current contractor's amount outstanding was approximately $1.4 million. Acadia began commercial operation in August 2002, and that guarantee will cease upon full payment of the APP construction contract.

Cleco Corporation has issued guarantees and letters of credit to support the activities of certain affiliates. These commitments are not within the scope of FIN 45. For information regarding these commitments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements - Off-Balance Sheet Commitments."

As part of the Lignite Mining Agreement entered into in 2001, Cleco Power and Southwestern Electric Power Company 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, 2002, Cleco Power's 50% exposure was approximately $30.0 million. The lignite mining contract is in place until 2011.

NOTE 24 - IMPAIRMENT OF LONG-LIVED ASSET

Cleco Energy, a wholly owned subsidiary of Midstream, 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 an 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 market value of the proved reserves was determined by using the discounted estimated net future cash flows at an appropriate discount rate of 10%. The difference between the carrying value and the fair market value resulted in an impairment charge of approximately $3.6 million, which is presented as a separate line item in "Operating Expenses" on the Consolidated Statements of Income.

NOTE 25 - MISCELLANEOUS FINANCIAL INFORMATION (UNAUDITED)

Quarterly information for Cleco for 2002 and 2001 is shown in the following table. All share and per share amounts have been adjusted to reflect the May 7, 2001, two-for-one stock split. 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 Income, due to the weighted-average dilutive effect of 2.0 million common shares issued on May 8, 2002.

	2002
	(Thousands, except per share amounts)
	1^st Quarter	2^nd Quarter	3^rd Quarter	4^th Quarter
Operating revenue as reported in 10-Q	$220,264	$370,624	$224,589	$173,715
Adjustments:
Reclassifications 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	$ 0.2200	$ 0.2250	$ 0.2250	$ 0.2250
Closing market price per share High	$ 22.94	$ 23.78	$ 21.43	$ 15.87
Low	$ 19.90	$ 20.58	$ 11.67	$ 9.58


	2001
	(Thousands, except per share amounts)
	1^st Quarter	2^nd Quarter	3^rd Quarter	4^th Quarter
Operating revenue as reported in 10-Q	$253,111	$303,700	$306,969	$194,839
Adjustments:
Reclassifications due to EITF 02-3	(51,492)	(109,832)	(85,955)	(62,581)
Operating revenue adjusted	$201,619	$193,868	$221,014	$132,258
Operating income	$ 32,483	$ 36,105	$ 62,372	$ 18,580
Net income applicable to common stock	$ 10,221	$ 12,601	$ 30,595	$ 14,945
Basic net income per average common share	$ 0.23	$ 0.28	$ 0.68	$ 0.33
Diluted net income per average common share	$ 0.22	$ 0.27	$ 0.65	$ 0.33
Dividends paid per common share	$ 0.2125	$ 0.2175	$ 0.22	$ 0.22
Closing market price per share High	$ 25.03	$ 23.59	$ 22.92	$ 22.08
Low	$ 20.36	$ 21.25	$ 19.48	$ 19.60

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, 2002, Cleco had 8,990 common and 107 preferred shareholders, as determined from the records of the transfer agent.

On January 24, 2003, Cleco Corporation's Board of Directors declared a quarterly dividend of $0.225 per share payable February 15, 2003, to common shareholders of record on February 3, 2003. Preferred dividends were also declared payable March 1, 2003, to preferred shareholders of record on February 15, 2003.

Report of Independent Accountants

To the Shareholders and
Board of Directors of Cleco Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Cleco Corporation and its subsidiaries at December 31, 2002, and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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 the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

PricewaterhouseCoopers LLP
New Orleans, Louisiana
January 28, 2003

CLECO CORPORATION
FIVE-YEAR SELECTED FINANCIAL DATA (UNAUDITED)

			2002		2001		2000		1999		1998
(THOUSANDS, EXCEPT PER SHARE, PERCENTAGES AND RATIOS)
Operating revenue (excluding intersegment revenue)
	Cleco Power	$	593,781	$	622,722	$	622,790	$	744,096	$	515,175
	Midstream		127,386		125,924		52,454		20,339		-
	Other		57		113		70		-		-
	Total	$	721,224	$	748,759	$	675,314	$	764,435	$	515,175
Net income before income taxes, discontinued operations, extraordinary item, and preferred dividends		$	114,118	$	110,629	$	104,296	$	85,836	$	80,741
Net income applicable to common stock		$	70,003	$	68,362	$	63,112	$	54,756	$	51,664
Basic EPS from continuing operations		$	1.51	$	1.56	$	1.50	$	1.25	$	1.16
Basic EPS applicable to common stock		$	1.51	$	1.52	$	1.41	$	1.22	$	1.15
Diluted EPS from continuing operations		$	1.47	$	1.51	$	1.46	$	1.21	$	1.12
Diluted EPS applicable to common stock		$	1.47	$	1.47	$	1.36	$	1.18	$	1.12
Return on average common equity			13.3%		14.3%		14.0%		12.7%		12.4%
Effective tax rate			37.0%		34.7%		33.5%		32.3%		33.2%

Capital expenditures
	Cleco Power	$	87,321	$	45,642	$	47,900	$	51,700	$	94,030
	Midstream		97,974		136,284		157,534		127,300		-
	Other (after allocation to Cleco Power and Midstream)		(1,170)		529		5,143		226		-
	Total	$	184,125	$	182,455	$	210,577	$	179,226	$	94,030
Internal cash generation (% of capital expenditures)
	Cleco Power		100.0%		100.0%		100.0%		100.0%		63.3%
	Midstream		56.4%		18.5%		15.3%		1.6%		0.0%
	Other		100.0%		100.0%		100.0%		100.0%		0.0%
Property, plant and equipment, net - Cleco Power
	Production	$	209,765	$	218,802	$	231,108	$	246,810	$	264,891
	Transmission	$	243,986	$	236,009	$	240,256	$	231,953	$	226,493
	Distribution	$	460,636	$	428,477	$	419,737	$	411,520	$	406,063
	Other	$	98,693	$	93,661	$	90,162	$	92,756	$	92,832

Total capitalization
Common shareholders' equity			38.83%		43.36%		40.81%		42.50%		54.02%
Preferred stock			1.21%		1.41%		1.33%		1.35%		2.35%
Long-term debt			59.96%		55.23%		57.86%		56.15%		43.63%

Total assets		$	2,344,606	$	1,767,890	$	1,750,356	$	1,704,650	$	1,429,000

Embedded cost of debt			6.67 %		8.08%		8.02%		7.89%		6.75%
Ratio of earnings to fixed charges (pre-tax)			2.60x		2.68x		2.66x		3.26x		3.75x	x

Total return to shareholders			(32.2)%		(16.6)%		76.0%		(2.5)%		11.0%
Average shares outstanding for year, basic			46,245,104		45,000,955		44,947,718		45,002,648		44,960,326
Average shares outstanding for year, diluted			48,771,864		47,763,713		47,654,954		47,697,030		47,734,916
Market price per share at year end		$	14.00	$	21.97		27.38	$	16.03	$	17.16
Market capitalization at year-end		$	658,493	$	987,804	$	1,231,620	$	719,551	$	771,556
Price-earnings ratio at year-end			9.3x		14.5x		19.4x		13.1x		14.9x	x
Market-to-book ratio at year-end			1.17x		2.01x		2.65x		1.64x		1.82x	x
Book value per share at year-end		$	11.96	$	10.92	$	10.33	$	9.75	$	9.45
Dividends paid per common share		$	0.895	$	0.870	$	0.845	$	0.825	$	0.805
Dividend payout ratio			59.3 %		57.3 %		60.2%		67.8%		70.1%
Dividend yield at year-end			6.4 %		4.0 %		3.1%		5.1%		4.7%

CLECO CORPORATION
FIVE-YEAR SELECTED OPERATING DATA (UNAUDITED)


			2002		2001		2000		1999		1998
(THOUSANDS, EXCEPT PERCENTAGES AND RATIOS)
Non-fuel recovery revenue by customer class - Cleco Power
	Residential	$	148,544	$	140,547	$	144,999	$	139,660	$	142,484
	Commercial		66,212		64,127		63,475		60,486		58,494
	Industrial		55,033		52,578		54,733		51,772		49,344
	Other		34,400		29,641		27,692		24,427		23,698
	Unbilled		1,194		1,012		3,588		3,795		(136)
	Total	$	305,383	$	287,905	$	294,487	$	280,140	$	273,884
Sales of Electricity (millions of kilowatt-hours) - Cleco Power
	Residential		3,400		3,201		3,296		3,147		3,215
	Commercial		1,722		1,655		1,636		1,573		1,534
	Industrial		2,756		2,640		2,884		2,717		2,529
	Other		1,308		979		912		924		959
	Unbilled		30		34		162		105		(7)
	Total		9,216		8,509		8,890		8,466		8,230
Average retail customers by class - Cleco Power
	Residential		222,766		219,809		217,538		213,860		209,605
	Commercial		31,406		30,634		30,136		29,513		28,902
	Industrial		747		750		767		786		790
	Other		6,211		6,178		6,121		5,976		5,876
	Total		261,130		257,371		254,562		250,135		245,173
Average revenue per kWh sold - Cleco Power
	Residential	$	0.0729	$	0.0814	$	0.0778	$	0.0682	$	0.0679
	Commercial	$	0.0675	$	0.0764	$	0.0722	$	0.0621	$	0.0615
	Industrial	$	0.0466	$	0.0553	$	0.0502	$	0.0421	$	0.0416
	Other, including unbilled	$	0.0566	$	0.0583	$	0.0672	$	0.0546	$	0.0489
	Total composite	$	0.0616	$	0.0696	$	0.0665	$	0.0570	$	0.0564
Average annual kWh use per residential customer - Cleco Power			15,263		14,563		15,151		14,715		15,338
Average annual revenue per residential customer - Cleco Power		$	1,113	$	1,186	$	1,178	$	1,003	$	1,041
Degree days -% of normal
	Heating		3.8%		(15.4)%		(6.6)%		(31.3)%		(28.0)%
	Cooling		2.6%		6.1%		15.3%		15.5%		20.9%
Capacity (MW)
	Cleco Power:
	Coal and lignite		482		482		482		482		482
	Natural gas and oil		877		880		885		1,211		1,211
	Firm capacity purchases		857		772		625		20		20
	Midstream:
	Natural gas		2,061		848		775		-		-
	Total		4,277		2,982		2,767		1,713		1,713
Peak demand (MW) - Cleco Power			1,833		1,751		1,839		1,767		1,627
Generation (MWH) - Cleco Power
	Net generation - system plants		5,405		5,536		6,254		6,376		6,764
	Purchased power		4,482		3,739		3,255		2,359		2,117
	Total energy supply		9,887		9,275		9,509		8,735		8,881
Cost of fuel per kWh		$	0.0285	$	0.0358	$	0.0328	$	0.0236	$	0.0228
Fuel Mix - Cleco Power
	Coal & lignite		32.6%		33.0%		35.4%		33.3%		37.3%
	Natural gas & oil		22.0%		26.7%		30.4%		39.7%		39.0%
	Purchased power		45.4%		40.3%		34.2%		27.0%		23.8%
System annual load factor			59.5%		57.2%		55.4%		54.3%		56.2%
System Average Interruption Duration Index (SAIDI) - Cleco Power			2.82		2.40		1.82		1.78		1.75
	(Average amount of hours a customer's service is interrupted)
System Average Interruption Frequency Index (SAIFI) - Cleco Power			2.09		1.82		1.41		1.39		1.25
	(Average number of times a customer's service is interrupted)
Customer Satisfaction Percentage - Cleco Power			93%		92%		94%		97%		95%
Number of employees			1,214		1,392		1,622		1,383		1,210

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Readability	7th grade Avg

Cleco Corporate 10-K2002 FY Annual report

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