2001 CLECO CORPORATION FORM 10K EXHIBIT 13

EX-13 6 cleco2001exhibit13_10k.htm EXHIBIT 13 2001 CLECO CORPORATION FORM 10K EXHIBIT 13
EXHIBIT 13

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

In this report Cleco (which includes Cleco Corporation and all of its regulated and nonregulated subsidiaries) is, at times, 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) with respect to the rates Cleco Power can charge its customers. Cleco Power serves approximately 250,000 customers mainly in central Louisiana.
*	The primary business of Cleco Midstream Resources LLC (Midstream) is to own and operate wholesale generation stations, invest in joint ventures that own and operate wholesale generation stations, own and operate wholesale natural gas pipelines, and engage in energy marketing 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. In December 2000 we decided to sell substantially all of the assets of UTS. Revenues and expenses associated with UTS are netted and shown on our Consolidated Statements of Income as loss from discontinued operations. For additional information on the sale of the assets, see the Notes to the Consolidated Financial Statements, Note 18 - "Discontinued Operations."

Reorganization

On December 31, 2000 Cleco Utility Group Inc. (Utility Group) merged into Cleco Power. Prior to the merger, Cleco Power had nominal assets and liabilities. As a result of the merger, Cleco Power acquired all of the assets and assumed all of the liabilities and obligations of Utility Group.

Cleco Corporation

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 revenues	$	1,058,619	$	820,015	$	238,604	29.1 %
Operating expenses	$	909,079	$	672,820	$	236,259	35.1 %
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 of income taxes	$	-	$	2,508	$	(2,508)	(100.0)%
Net income applicable to common stock	$	68,362	$	63,112	$	5,250	8.3 %

Net income from continuing operations for the year ended December 31, 2001, totaled $72.3 million, a $2.9 million increase over the year ended December 31, 2000. The improvement largely was due to an increase in net income from continuing operations at Midstream, which was partially offset by a decrease at Cleco Power.

Midstream's net income from continuing operations increased largely because a wholesale power plant owned and operated by a Midstream subsidiary was in commercial operation for all of 2001. The plant did not begin commercial operation until mid-2000. Partially offsetting the increase was a decrease in net income from continuing operations from Midstream's energy marketing and trading operations.

The slight decrease in net income from continuing operations at Cleco Power primarily was caused by lower base revenues and margins from energy marketing operations. This decrease was partially offset by a decrease in fuel expenses and an increase in interest income due mainly to a one- time recognition of the recoverability of previously uncollected fuel costs.

Losses from the discontinued operations of UTS reduced net income $2.0 million in 2001, compared to a decrease in net income of $6.9 million in 2000. The loss from discontinued operations in 2000 consisted of operating losses for 12 months of $5.4 million and the estimated loss on disposal of $1.5 million. The loss from discontinued operations in 2001 consisted of the difference between the estimated loss on disposal recorded in 2000 and the actual loss incurred after all assets were disposed of and all liabilities were paid. There was no extraordinary gain in 2001 compared to a $2.5 million extraordinary gain in 2000. Net income applicable to common stock was $68.4 million in 2001 compared to $63.1 million in 2000.

Earnings for past years are not necessarily indicative of future earnings and results. Future earnings will be affected by, among other things, weather conditions, our business development programs, the overall economy of Cleco Power's service area, the operating performance of the facilities of Cleco Power and Midstream, legislative and other regulatory changes, the ability of our marketing and trading counterparties to perform their obligations, and increased competition.

Cleco Power

Revenues are 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 rates fluctuate while allowing recovery of, with no profit, the majority of costs of purchased power and fuel used to generate electricity. Rates for transmission service and wholesale power sales are regulated by the FERC. Energy marketing revenues are based on the electric and natural gas markets, which are affected by supply and demand of those commodities and marketing strategies.

Residential customers' demand for electricity is 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 of a consumer utilizing air conditioning, while a heating degree-day is an indication of the likelihood of a consumer utilizing 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 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 approximately 30 years.

Commercial and industrial customers' demand for electricity is less affected by the weather and is primarily dependent upon the strength of the economy in the service territory and the nation. Cleco Power's two largest customers manufacture wood products, so its sales to industrial customers are affected by the worldwide demand for those products.

Sales growth to retail electric customers has averaged 3.1% over the last five years, and we expect it to range from 2% to 3% per year during the next five years. The levels of future sales will depend upon factors such as weather conditions, customer conservation efforts, retail marketing and business development programs, and the economy of the service area. Some of the issues facing the electric utility industry that could affect sales include:

*	deregulation,
*	retail wheeling,
*	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.

Energy marketing sales primarily are affected by demand and supply of energy, market prices, and transmission constraints.

Fuel and power purchased are affected by the following factors:

Changes in fuel and purchased power expenses reflect fluctuations in fuel used for generation, fuel costs, availability of economic power, and deferral of expenses for recovery from customers through fuel adjustment clauses in subsequent months.

Historically, changes in the cost of generating fuel and purchased power have not affected net income because substantially all such costs are passed on to customers through fuel adjustment clauses. These adjustments are audited monthly and are regulated by the LPSC (representing about 93% of the total fuel cost adjustment) and the FERC. Until approval is received, the adjustments are subject to refund.

Coal and lignite are obtained both under long-term contracts and through the spot market. Natural gas is purchased under short-term contracts. Cleco Power has several power contracts with two power marketing companies for 705 megawatts (MW) of capacity in 2002 and 2003, increasing to 760 MW of capacity in 2004. Power is purchased from other utilities and other marketers to supplement Cleco Power's generation at times of relatively high demand when the purchase price of the power is less than Cleco Power's cost of production. However, transmission capacity must be available to transport the purchased power to Cleco Power's system in order for Cleco Power to be able to utilize the power. During 2001, 40% of Cleco Power's energy requirements were met with purchased power, up from 34% in 2000 and 27% in 1999.

In future years, Cleco Power's power plants may not 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 are not expected to be affected by such constraints.

An affiliate of Cleco owns and operates natural gas pipelines at two of Cleco Power's power plants where natural gas is used as a primary fuel. These pipelines increase access to natural gas markets and lower the cost of gas supplies.

Other expenses

Other operations expenses are affected, among other things, by the cost of employee benefits, such as health care, the number of employees, changes in actuarial assumptions, and capacity charges. Maintenance expense generally is driven by the physical characteristics of the plant as well as planned preventive maintenance.

Results of Operations - Continuing Operations

Year ended December 31, 2001, compared to Year ended December 31, 2000

Cleco Power's net income for the year ended December 31, 2001, was $59.1 million compared $59.9 million in 2000. The decrease largely was due to lower margins from marketing and trading operations as well as lower base revenues from retail customer sales, which were partially offset by higher transmission and wholesale revenues. There was a $22.1 million increase in operating expenses in 2001 compared to 2000 primarily because of higher operations expense and purchases for energy marketing.

	For the year ended December 31,
	2001	2000	Variance	Change
Operating revenues:	(Thousands)
Base	$ 318,715	$ 322,716	$ (4,001)	(1.2)%
Fuel cost recovery	304,347	296,812	7,535	2.5 %
Affiliate revenue	3,530	9,256	(5,726)	(61.9)%
Estimated customer credits	(1,800)	(1,233)	(567)	(46.0)%
Energy marketing	31,212	18,078	13,134	72.7 %
Total operating revenues	656,004	645,629	10,375	1.6 %
Operating expenses:
Purchases for energy marketing operations	29,756	13,583	16,173	119.1 %
Operations and maintenance	124,694	112,043	12,651	11.3 %
Fuel and purchased power	302,482	303,987	(1,505)	(0.5)%
Depreciation	50,594	49,787	807	1.6 %
Taxes other than income	35,358	36,533	(1,175)	(3.2)%
Intercompany	2,987	7,871	(4,884)	(62.1)%
Total operating expenses	545,871	523,804	22,067	4.2 %
Operating Income	$ 110,133	$ 121,825	$ (11,692)	(9.6)%
	=======	========	========

	For the year ended December 31,
	2001	2000	Change
	(Million kilowatt hours )
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 %
Total retail, billed	8,077	8,393	(3.8)%
Unbilled	34	162	(79.0)%
Sales for resale	398	334	19.2 %
Total on-system customer sales	8,509	8,889	(4.3)%
Short-term sales to other utilities	129	77	67.5 %
Sales from marketing activities	5	81	(93.8)%
Total electric sales	8,643	9,047	(4.5)%
	======	======

Base revenues from energy sales during 2001 decreased $6.6 million compared to 2000 due to lower kWh sales. Offsetting this decrease was an increase of $1.8 million in transmission-related base revenues and a $0.8 million increase in miscellaneous base revenues, resulting in a net $4.0 million decrease in base revenues compared to 2000.

The following chart indicates the percentage variance from normal conditions and from the prior year for cooling/heating degree-days.

Cooling/Heating degree-days For the year ended December 31,
	2001	2000
Cooling Degree-Days:
Increase/(Decrease) from Normal	6.1 %	15.3 %
Increase/(Decrease) from Prior Year	(7.7)%	0.3 %
Heating Degree-Days:
Increase/(Decrease) from Normal	(15.4)%	(6.6)%
Increase/(Decrease) from Prior Year	(9.7)%	34.7 %

Short-term electric sales to other utilities increased significantly during 2001. The increase primarily was due to sales to the city of Lafayette under a one-year replacement energy contract that began in December 2000, and sales to the city of Ruston under a three-year contract to supply all of its power beginning June 1, 2001.

Fuel cost recovery revenues collected from customers increased primarily because the average per unit cost of fuel was $2.92 per million British thermal units (MMBtu) in 2001 versus $2.72 per MMBtu in 2000. The increase in the average per unit cost of fuel was primarily a result of a 7.3% increase in the per unit cost of natural gas for 2001 compared to 2000.

An earnings review settlement was reached with the LPSC in 1996 under which accruals for estimated customer credits are sometimes required. Cleco Power accrued $1.8 million during 2001 compared to $1.2 million in 2000. The amount of credit due customers, if any, is determined by the LPSC annually, based on results for the 12-month period ending September 30 of each year. For additional information, see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

Energy marketing revenues for 2001 increased $13.1 million compared to 2000. The increase in energy marketing revenues primarily is due to excess natural gas marketed and an increase in the price of natural gas in 2001 compared to 2000. Cleco Power's energy trading activity is considered "trading" under Emerging Issues Task Force (EITF) No. 98-10, requiring open positions to be reported at fair market value or "marked-to-market." The mark-to-market related to these open positions was a gain of less than $0.1 million for 2001 versus a gain of $0.6 million in 2000.

Energy Marketing Operations For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 31,159	$ 17,453	$ 13,706	78.5 %
Mark-to-market	53	625	(572)	(91.5)%
Total	31,212	18,078	13,134	72.7 %
Energy trading expenses	29,756	13,583	16,173	119.1 %
Net margins	$ 1,456	$ 4,495	$ (3,039)	(67.6)%
	=======	=======	=======

Operating expenses increased $22.1 million, or 4.2%, during 2001 compared to 2000. Energy marketing expenses increased $16.2 million for 2001 compared to 2000 largely because of the same factors that caused increases in energy marketing revenues. Fuel expense increased $2.5 million because of increased energy prices mainly driven by increases in the price of natural gas. This increase was offset by a one-time $6.6 million adjustment reflecting the 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 the fourth quarter of 2001. Purchased power expense decreased $4.0 million during 2001 compared to 2000 principally as a result of a decrease in the price of power purchased. The increase in other operations expense for 2001 compared to 2000 primarily was due to a $6.3 million increase in capacity payments, a $3.8 million increase in vacation accrual, and an increase of $3.3 million in employee benefits.

Interest income increased $6.5 million for 2001 compared to 2000 largely because of the interest related to the recognition of the recovery of fuel-related costs that had not been previously collected from utility customers. Because the recovery of the fuel-related costs is a one-time adjustment, we do not expect the amount of interest income in future periods to be as much as experienced in 2001.

Interest expense decreased $1.9 million in 2001 compared to 2000 primarily due to a decrease in medium-term notes and a decrease in the interest rates paid on commercial paper.

Allowance for funds used during construction (AFUDC) increased to $1.2 million in 2001 from $0.6 million because of an increase in average construction. Allowance for funds used during construction represents Cleco Power's estimated cost of financing LPSC and FERC rate-regulated construction and is not a current source of cash. Regulatory bodies allow for a return on and recovery of AFUDC when setting rates for utility services.

Midstream

General factors affecting Midstream

The majority of Midstream's revenues are derived from its power plant operations and energy marketing and trading operations.

Revenues from power plant operations primarily are derived from the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling Agreement) with Williams Energy and Trading Company (Williams). The Evangeline Tolling Agreement gives Williams the right to own, dispatch and market all of the electric generation capacity of the Cleco Evangeline LLC (Evangeline) facility until July 2020. Therefore, Evangeline does not have the right to dispatch or sell electricity from the facility. Williams is responsible for providing its own natural gas to the facility and pays Evangeline a fee for operating and maintaining the facility. When the facility is unable to operate, Evangeline has the option to purchase replacement power for Williams. By providing replacement power, Evangeline can maintain certain capacity requirements under the Evangeline Tolling Agreement and be reimbursed by Williams for replacement power based upon the heat rate of the plant, the price of natural gas, and the amount of megawatt hours (MWh) of replacement power provided to Williams. Evangeline Tolling Agreement revenues are not recognized evenly throughout the year. Evangeline's 2001 revenues were recognized in the following manner:

*	16% in the first quarter,
*	23% in the second quarter,
*	42% in the third quarter, and
*	19% in the fourth quarter.

Revenues for 2002 are anticipated to be recognized in a similar manner. Tolling revenues generally are affected by the availability of the Evangeline facility to operate, the amount of replacement power provided to Williams, and other characteristics of the plant. See the Notes to the Consolidated Financial Statements, Note 14 - "Operating Lease" for more information about the Evangeline Tolling Agreement.

Nonperformance by and the credit risk of the counterparties to the Evangeline Tolling Agreement, as well as the tolling agreements at Acadia Power Partners LLC (APP) and Perryville Energy Partners LLC (PEP), may adversely affect our financial condition and results of operations. If the counterparties are unable to perform under the respective tolling agreement, Cleco's financial condition and results of operations may be impacted by a failure to collect outstanding receivables and could incur an impairment loss on Midstream's investments in the Evangeline generating station and the investments in APP and PEP.

Revenues from energy marketing and trading operations generally are affected by transmission constraints, demand versus supply, financial viability of our marketing and trading counterparties, and market prices. Midstream has two subsidiaries that market and trade energy: Cleco Marketing & Trading LLC (Marketing & Trading) and Cleco Energy LLC (Cleco Energy). Marketing & Trading began operations in July 1999 and markets wholesale natural gas and electricity. Cleco Energy markets wholesale natural gas in Louisiana and Texas. Although our energy marketing and trading operations have been profitable, their primary purpose is to provide market intelligence and to optimize existing assets and contracts. Unless market conditions and company strategy shift, we do not expect significant future profits from our trading operations.

The majority of Midstream's expenses are purchases for energy marketing and trading, depreciation, maintenance, and other operating expenses. Purchases for energy marketing and trading generally are influenced by the same factors affecting the energy marketing and trading revenues and the amount of replacement power purchased by Evangeline.

Depreciation expense is affected by the amount of plant in service, the time the plant was placed in service, and the estimated useful life of the plant. Maintenance expense generally is driven by the physical characteristics of the plant as well as planned preventive maintenance. Other operating expenses relate mainly to administration expenses, employee benefits, and various other items.

Results of Operations - Continuing 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 revenues:
Energy marketing revenue	$ 344,062	$ 141,812	$ 202,250	142.6 %
Tolling revenue	60,522	41,354	19,168	46.4 %
Other operations	1,461	403	1,058	262.5 %
Intercompany	14,030	37,667	(23,637)	(62.8)%
Total operating revenues	420,075	221,236	198,839	89.9 %
Operating expenses:
Purchases for energy marketing and tolling operations	329,677	134,659	195,018	144.8 %
Operations and maintenance	26,567	19,878	6,689	33.7 %
Depreciation	9,188	5,952	3,236	54.4 %
Taxes other than income	1,255	828	427	51.6 %
Intercompany	11,465	34,716	(23,251)	(66.9) %
Total operating expenses	378,152	196,033	182,119	92.9 %
Operating income	$ 41,923	$ 25,203	$ 16,720	66.3 %
	=======	=======	=======

Energy Marketing and Trading Operations

The chart below presents a summary of electricity and natural gas marketed during 2001 compared to 2000.

	For the year ended December 31
	2001	2000	Change
Electricity (Million kWh)	3,278	1,274	157.3%
Natural gas (MMBtu)	28,608,058	18,611,729	53.7%

Energy marketing revenues increased to $344.1 million in 2001 from $141.8 million in 2000 mainly because of an increase in electricity marketed and an increase in the per unit price of natural gas. Purchases for energy marketing increased to $329.7 million from $134.7 million in 2000 mainly because of the same factors affecting energy marketing revenues. Our average per unit cost of natural gas in 2001 decreased 10.3% compared to 2000, and the average per unit cost of electricity increased 28.4% for 2001 compared to 2000.

See "Financial Risk Management" for more information about energy marketing and trading operations.

Power Plant Operations

Tolling revenues were $60.5 million in 2001 compared to $41.3 million in 2000. Most of the difference was attributable to the Evangeline facility operating for a full year in 2001. The facility began full commercial operations in July 2000. Partially offsetting that increase was a $5.6 million decrease in revenue caused by replacement power reimbursements from Williams in 2000 that were not required during 2001.

There were less than $0.1 million in purchases for energy marketing operations in 2001 compared to $6.9 million in 2000 for Evangeline. During the fourth quarter of 2000, the Evangeline facility was unable to operate, mainly because of facility modifications required by the turbine vendor after the facility was declared in commercial operation. While the facility was unable to operate, replacement power was purchased and provided to Williams in order to maintain availability and ensure capacity payments. The modifications were completed during the fourth quarter of 2000.

Other operations expense increased $0.5 million, depreciation expense increased $2.8 million, and maintenance expense increased $1.9 million from 2000 to 2001 principally because Evangeline operated for a full year compared to only six months in 2000. During the second quarter of 2001, the increase in depreciation was partially offset by the lengthening of the depreciable life of the plant, as described in the Notes to the Consolidated Financial Statements, Note 15 - "Change in Accounting Estimate."

Interest expense increased $8.1 million to $19.2 million in 2001 compared to $11.1 million in 2000. Interest expense increased in 2001 because interest was capitalized during the first six months in 2000 when the Evangeline facility was still under construction, whereas a full year of interest was expensed in 2001. See the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Capitalized Interest" for more information.

Other revenues of Midstream were $1.1 million in 2001 compared to $0.4 million in 2000 largely because of billings for power plant construction and maintenance as a result of an increase in power plant construction in Louisiana.

Other

Net income from continuing operations from our Other segment decreased $1.4 million in 2001 principally because of an increase in financing expenses compared to 2000.

Cleco Corporation

Consolidated Results of Operations

Year ended December 31, 2000 compared to Year ended December 31, 1999

	For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Operating revenues	$ 820,015	$ 764,435	$ 55,580	7.3 %
Operating expenses	$ 672,820	$ 650,019	$ 22,801	3.5 %
Net income from continuing operations	$ 69,335	$ 58,070	$ 11,265	19.4 %
Loss from discontinued operations, net	$ (6,861)	$ (1,304)	$ (5,557)	426.2 %
Extraordinary item, net of income taxes	$ 2,508	$ -	$ 2,508	100.0 %
Net income applicable to common stock	$ 63,112	$ 54,756	$ 8,356	15.3 %

Net income applicable to common stock for 2000 was $63.1 million compared to $54.8 million in 1999. Net income from continuing operations for 2000 totaled $69.3 million, an $11.3 million increase compared to 1999. The increase in net income from continuing operations primarily was due to an increase of net income from continuing operations at Cleco Power and Midstream. Losses from the discontinued operations of UTS reduced net income $6.9 million in 2000 compared to a $1.3 million loss in 1999. Increasing earnings in 2000 was an extraordinary gain of $2.5 million from the repurchase of debt within Midstream.

Higher net income from continuing operations at Cleco Power in 2000 compared to 1999 was largely the result of higher MWh sales to on-system customers in 2000.

Midstream's net income from continuing operations increased in 2001 compared to 2000 because Evangeline began operating in 2000, and Marketing & Trading had a full year of energy marketing in 2000 versus only six months in 1999.

Cleco Power

Results of Operations - Continuing Operations

Year ended December 31, 2000, compared to Year ended December 31, 1999

Cleco Power's net income for the year ended December 31, 2000, was $59.9 million compared to $55.6 million in 1999. The increase largely was because of higher base revenues in 2000 compared to 1999. There was a $115.2 million decrease in operating expenses primarily resulting from a decrease in energy marketing expenses, partially offset by increased capacity charges and higher fuel cost.

	For the year ended December 31,
	2000	1999	Variance	Change
Operating revenues:	(Thousands)
Base	$ 322,716	$ 306,225	$ 16,491	5.4 %
Fuel cost recovery	296,812	202,565	94,247	46.5 %
Affiliate revenue	9,256	7,816	1,440	18.4 %
Estimated customer credits	(1,233)	(2,776)	1,543	55.6 %
Energy marketing	18,078	238,082	(220,004)	(92.4)%
Total operating revenues	645,629	751,912	(106,283)	(14.1)%
Operating expenses:
Purchases for energy marketing operations	13,583	230,084	(216,501)	(94.1)%
Operations and maintenance	112,043	105,225	6,818	6.5 %
Fuel and purchased power	303,987	212,128	91,859	43.3 %
Depreciation	49,787	49,285	502	1.0 %
Taxes other than income	36,533	35,870	663	1.8 %
Intercompany	7,871	6,397	1,474	23.0 %
Total operating expenses	523,804	638,989	(115,185)	(18.0)%
Operating income	$ 121,825	$ 112,923	$ 8,902	7.9 %
	=======	=======	========

	For the year ended December 31,
	2000	1999	Change
	(Million kWh)
Electric sales:
Residential	3,296	3,147	4.7 %
Commercial	1,636	1,573	4.0 %
Industrial	2,883	2,717	6.1 %
Other retail	578	562	2.8 %
Total retail, billed	8,393	7,999	4.9 %
Unbilled	162	105	54.3 %
Sales for resale	334	362	(7.7)%
Total on-system customer sales	8,889	8,466	5.0 %
Short-term sales to other utilities	77	126	(38.9)%
Sales from marketing activities	81	5,815	(98.6)%
Total electric sales	9,047	14,407	(37.2)%
	=====	======

Revenues were reduced $1.2 million and $2.8 million in 2000 and 1999, respectively, for customer rate refunds pursuant to an earnings review settlement reached with the LPSC in 1996. Under the terms of the settlement, accruals for estimated customer credits are sometimes required with the amount of credit due customers determined annually by the LPSC based on results for the 12-month period ending September 30 of each year. For additional information see the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits."

Most of the $16.5 million increase in base revenues in 2000 compared to 1999 was caused by a 4.9% increase in kWh sales to on-system customers, which was driven by warmer than normal summer weather and colder than normal winter weather. Weather patterns also caused the increase in sales to residential customers. The rest of the increase in base revenues largely was due to higher transmission and miscellaneous revenues.

Sales to commercial and industrial customers during 2000 were higher compared to 1999 primarily because of increased economic growth in the nation and the region served by Cleco Power.

The following chart indicates the percentage variance from normal conditions and from the prior year for cooling/heating degree-days for the years ended December 31, 2000 and 1999.

Cooling/Heating degree-days For the year ended December 31,
	2000	1999
Cooling Degree-Days:
Increase/(Decrease) from Normal	15.3 %	15.5 %
Increase/(Decrease) from Prior Year	0.3 %	(3.8)%
Heating Degree-Days:
Increase/(Decrease) from Normal	(6.6)%	(31.3)%
Increase/(Decrease) from Prior Year	34.7 %	(5.3)%

Fuel cost recovery revenues collected in 2000 increased $94.2 million over 1999 mainly because of higher natural gas prices in 2000 compared to 1999. The higher gas prices increased both Cleco Power's cost of generating power and the cost of purchased power in the region.

Energy marketing revenues decreased $220.0 million in 2000 compared to 1999 because of a reduced level of energy trading activities resulting from a refinement of trading practices within Cleco Power and from the transfer of the Coughlin Power Station (CPS) to Evangeline.

Energy Marketing Operations For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Energy trading revenue	$ 17,453	$ 238,652	$(221,199)	(92.7)%
Marked-to-market	625	(570)	1,195	- %
Total	18,078	238,082	(220,004)	(92.4)%
Energy trading expenses	13,583	230,084	(216,501)	(94.1)%
Net margins	$ 4,495	$ 7,998	$ (3,503)	(43.8)%
	=======	=======	=======

Operating expenses decreased $115.2 million or 18.0% during 2000 compared to 1999. Energy marketing expenses decreased $216.5 million during 2000 compared to 1999 largely due to a reduced level of energy trading activities resulting from a refinement of trading practices within Cleco Power and from the transfer of CPS to Evangeline. Fuel and purchased power for utility operations increased $91.8 million in 2000 compared to 1999 mainly because of increased energy prices, which were primarily driven by increases in natural gas prices and demand from native load customers. The 6.9% increase in other operations expense for 2000 compared to 1999 was due primarily to a $10.2 million increase in energy capacity payments, partially offset by decreased expenses in transmission, distribution, and customer accounting operations.

Midstream

Results of Operations - Continuing Operations

Year ended December 31, 2000, compared to Year ended December 31, 1999

	For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Operating revenues:
Energy marketing revenue	$ 141,812	$ 18,698	$ 123,114	658.4 %
Tolling revenue	41,354	-	41,354	100.0 %
Other operations	403	1,641	(1,238)	(75.4)%
Intercompany	37,667	6,493	31,174	480.1 %
Total operating revenues	221,236	26,832	194,404	724.5 %
Operating expenses:
Purchases for energy marketing and tolling operations	134,659	14,856	119,803	806.4 %
Operations and maintenance	19,878	4,545	15,333	337.3 %
Depreciation	5,952	668	5,284	791.0 %
Taxes other than income	828	175	653	373.1 %
Intercompany	34,716	4,860	29,856	614.3 %
Total operating expenses	196,033	25,104	170,929	680.9 %
Operating income	$ 25,203	$ 1,728	$ 23,475	- %
	=======	=======	=======

Energy Marketing and Trading Operations

The chart below presents a summary of electricity and natural gas marketed during 2000 as compared to 1999.

	For the year ended December 31,
	2000	1999	Change
Electricity (Million kWh)	1,274	135	843.7%
Natural gas (MMBtu)	18,611,729	8,817,944	111.1%

Energy marketing revenues increased to $141.8 million in 2000 from $18.7 million in 1999 as a result of a full year of energy marketing and trading operations in 2000 compared to only six months in 1999. Purchases for energy marketing increased to $127.8 million from $14.9 million in 1999 because of the same factor noted above.

See "Financial Risk Management" for more information about energy marketing and trading operations.

Power Plant Operations

Tolling revenues were $41.3 million in 2000 compared to none in 1999. The change was caused by the Evangeline facility beginning full commercial operation in July 2000.

Purchases for energy marketing operations in 2000 were $6.9 million. During the fourth quarter of 2000, the Evangeline facility was unable to operate mainly because of facility modifications required by the turbine vendor after the facility was declared in commercial operation. While the facility was unable to operate, replacement power was purchased and provided to Williams in order to maintain availability and ensure capacity payments. The modifications were completed during the fourth quarter of 2000.

Other operations expense increased by $4.3 million, depreciation expense increased $4.2 million, and maintenance expense increased $1.6 million in 2000 compared to 1999 because of the commencement of operations at Evangeline in 2000.

Interest expense increased $11.2 million to $11.4 million in 2000 compared to $0.2 million in 1999 because interest was capitalized during most of 1999 as compared to the capitalization of interest during only the first six months in 2000 when the Evangeline facility was still under construction. See the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Capitalized Interest" for more information.

Discontinued Operations

In December 2000 management decided to sell substantially all of 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.

The $2.0 million loss on disposal of a segment, net, for 2001 primarily resulted from actual operating losses in 2001 exceeding estimated operating losses for 2001 that were included in the loss on disposal of a segment for the year ended December 31, 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 with Quanta signed in November 2001.

At December 31, 2001, UTS had nominal assets since receivables have been either collected or charged against the reserve.

Additional information about UTS follows:

	For the year ended December 31,
	2001	2000	1999
	(Thousands)
Revenues	$ 5,043	$18,125	$ 6,866
Pretax loss from operations of UTS	$ -	$ 8,801	$ 1,966
Income tax benefit associated with loss from operations	$ -	$ 3,390	$ 662
Pretax loss from disposal of UTS	$ 3,310	$ 2,358	$ -
Income tax benefit associated with loss on disposal	$ 1,275	$ 908	$ -

Extraordinary Gain

In March 2000 Four Square Gas, a wholly owned subsidiary of Cleco Energy, 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. 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. The gain of approximately $3.9 million was reduced by $1.4 million of related income tax to arrive at the extraordinary gain, net of income tax, of approximately $2.5 million.

Critical Accounting Policies

We are disclosing the significant risk and uncertainties inherent in the application of our critical accounting policies. These accounting policies are those considered by management to be most critical, which means they typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

While we have identified these specific critical accounting policies among the reportable segments and discuss them below, other accounting policies may exist which have assumptions that could cause actual results to be different than expected results.

Cleco Power

Cleco Power has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. However, 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. See the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies - Regulation" for more information about the LPSC and regulatory assets.

Cleco Power has recorded a liability for estimated customer credits expected to be refunded 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 is different than expected, Cleco Power could be required to adjust the liability. See "Retail Rates of Cleco Power" for more information.

Cleco Power has concluded none of its current property, plant and equipment is impaired due to the ability to recover prudent costs through the ratemaking of the LPSC. If the LPSC were to rule that the cost of current or future property, plant and equipment was imprudent and not recoverable, Cleco Power could be required to write down the imprudent cost and incur a corresponding loss.

Cleco Power has concluded it is in compliance with current environmental laws and regulations. If a currently unknown liability is discovered, or an event occurs to put Cleco Power in noncompliance, or the laws or regulations change, Cleco Power's financial condition may be adversely impacted by fines and actions required to return Cleco Power to compliance.

Cleco Power has entered into various contracts for the purchase or sale of electricity and the purchase of fuel used at its generating stations in order to meet customer demand. These contracts meet the normal purchase/sale exception in Statement of Financial Accounting Standards (SFAS) No. 133 based on the current interpretation by the Derivatives Implementation Group (DIG). If the DIG's interpretations were to change and contracts no longer met the normal purchase/sale exception, then the fair market value may have to be recorded. If the fair market value were recorded, it could have a material impact on our financial condition and results of operations.

Midstream

*	Evangeline accounts for the Evangeline Tolling Agreement as an operating lease. If the Evangeline Tolling Agreement were modified to the extent that would make lease accounting improper, then future results could materially differ from those currently reported. In the event the Evangeline Tolling Agreement were to be discharged through judicial proceedings (such as bankruptcy court), future results could be materially different than current results. Currently, Evangeline has in place guaranties that it expects would mitigate some of the effects of bankruptcy or other judicial proceedings. See the Notes to the Consolidated Financial Statements, Note 14 - "Operating Lease," for more information about the Evangeline Tolling Agreement.
*	Midstream companies currently engage in energy marketing and trading activities. Contracts (for example, options, futures, calls and swaps) are entered into with counterparties based on assumptions of future movements of energy prices, ability of counterparties to perform contractual obligations, corporate risk strategies and internal controls. These derivative instruments are recorded on Cleco's financial statements at their fair market value. If the market moves in an unexpected manner, if risk is not timely and adequately balanced, if counterparties fail to perform contractual obligations, or if internal controls are circumvented, actual results could differ materially from expected results. See "Financial Risk Management" for more information about Midstream's energy trading.
*	Midstream accounts for its investments in APP and PEP under the equity method of accounting due to the lack of a certain level of control over the entities. If circumstances occur which would require APP and PEP to be consolidated, our financial condition and results of operations could be significantly impacted.
*	Midstream has concluded it is in compliance with current environmental laws and regulations. If a currently unknown liability is discovered, or an event occurs to put Midstream in noncompliance, or the laws or regulations change, Midstream's financial condition may be adversely impacted by fines and actions required to return Midstream to compliance.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Financing for construction requirements and operational needs is dependent upon the cost and availability of external funds from capital markets and financial institutions at both company and project levels. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, Cleco's credit rating, the credit rating of its subsidiaries, the operations of projects funded, the credit ratings of project counterparties, and the pro-forma economics of projects to be funded.

At December 31, 2001, and 2000, there were $179.6 million and $96.0 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, 2001, we were in compliance with the covenants in our credit facilities, and our credit ratings have not been downgraded since May 8, 2000.

The following table shows short-term debt by subsidiary.

Subsidiary	At December 31,
	2001	2000
	(Thousands)
Cleco Corporation (Holding Company Level)
Commercial paper	$ 36,933	$ 54,220
Bank loans	77,000	-
Cleco Power
Commercial paper	63,742	41,397
Midstream
Bank loans	1,880	340
Total	$ 179,555	$ 95,957
	=======	======

Cleco Corporation (Holding Company Level)

Short-term debt increased at the Holding Company level in order to fund project development at Midstream. Two credit facilities for Cleco totaling $200 million are structured such that $120 million is scheduled to terminate in June 2002, and $80 million is scheduled to terminate in August 2002. The facilities provide for working capital and other needs of Cleco and its subsidiaries. When the $120 million facility expires, we intend to renew it or enter into a similar agreement with similar terms. Off-balance sheet commitments entered into by Cleco with third parties for certain types of transactions between those parties and Cleco's affiliates, other than Cleco Power, will reduce the amount of the facilities available to Cleco by an amount equal to the stated or determinable amount of the primary obligation. For more information about the commitments see "-Cash Generation and Cash Requirements - Off-balance Sheet Commitments". In addition, certain indebtedness incurred by Cleco outside of the facilities will reduce the amount of the facilities available to Cleco. The amount of such commitments and other indebtedness at December 31, 2001, and 2000, totaled $70.1 million and $60.9 million, respectively. An uncommitted line of credit with a bank in the amount of $2.5 million is also available to support working capital needs.

Cleco Power

Commercial paper increased at Cleco Power by $22.3 million at December 31, 2001, compared to the same date in 2000 largely due to the repayment at maturity of $25 million in medium-term notes classified as long-term debt with the proceeds of commercial paper issuances. An existing $100 million revolving credit facility at Cleco Power is scheduled to terminate in June 2002. This facility provides support for the issuance of commercial paper and working capital needs. When the facility expires, Cleco Power intends to renew it or enter into a similar agreement with similar terms. An uncommitted line of credit with a bank in the amount of $2.5 million is also available to support working capital needs.

Midstream

On June 25, 2001, Midstream entered into a $36.8 million line of credit. This line of credit may be used to support Midstream's generation activities. Midstream may borrow at a rate of interest equal to the higher of the Federal Funds Rate plus applicable spread or the bank's prime rate in effect on such date. Outstanding balances under this line of credit are guaranteed by Cleco. The 364-day facility is scheduled to terminate in June 2002. At December 31, 2001, there were no balances outstanding under this line of credit.

Other

At December 31, 2001, CLE Resources, Inc. (Resources), a wholly owned subsidiary of Cleco, held $0.4 million of cash and marketable securities compared to $18.8 million at December 31, 2000. The cash and marketable securities are committed to supporting activities of affiliates.

Restricted cash represents cash to be used for specific purposes. The $29.7 million of restricted cash at December 31, 2001, consists of reserve accounts required by the Evangeline senior secured bond indenture, which remain restricted under the bond indenture until certain of its provisions are met. As the provisions are met, cash is transferred out of the escrow account and is available for general corporate purposes.

CASH GENERATION AND CASH REQUIREMENTS

Cash Flows

Cash flows from operating activities during 2001 generated $124.8 million, as shown in the Consolidated Statements of Cash Flows. Net cash provided by operating activities resulted from net income, adjusted for noncash charges to income, and changes in working capital. The net cash used in investing activities of $175.4 million primarily related to additions to property, plant and equipment and changes in nonutility investments. Net cash provided by financing activities of $33.1 million resulted principally from cash transferred from Evangeline's restricted escrow account and the issuance of short-term debt. Net cash provided by financing activities was reduced by payment of dividends to shareholders and the maturity of medium-term notes at Cleco Power.

Shelf Registrations

At December 31, 2001, Cleco had a shelf registration statement providing for the issuance of $100 million aggregate principal amount of its debt securities. In February 2001 Cleco filed a shelf registration statement providing for the issuance of up to $150 million of common stock, preferred stock or trust preferred securities, or any combination thereof. There were no issuances, at December 31, 2001, under the shelf registration. At December 31, 2001, Cleco Power had a shelf registration statement providing for the issuance of $200 million aggregate principal amount of its debt securities. In January 2002 the LPSC approved the issuance of medium-term notes and retail notes pursuant to the registration statement. On February 8, 2002, Cleco Power issued $25 million of its 6.125% Insured Quarterly Notes due 2017. The proceeds from the issuance of the notes of $23.6 million were used to reduce Cleco Power's commercial paper balance.

Construction and Investment in Subsidiaries Overview

Cleco has divided its construction and investments along its major first-tier subsidiaries -Cleco Power and Midstream. Cleco Power construction consists of assets that may be included in Cleco Power's rate base and the cost of which, if considered prudent by the LPSC, may be passed on to jurisdictional customers. 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." Such assets consist of additions to Cleco Power's distribution system and improvements to its transmission system and generation stations. Midstream construction and investment consist of assets whose rate of return is largely determined by the market, not the LPSC. Examples of this type of construction are the repowering of the Evangeline facility, additions to gas pipeline transmission systems, and investments engaged in constructing and owning power plants.

Other subsidiaries had construction expenditures of $3.9 million during 2001, $5.0 million during 2000, and $0.2 million during 1999. These expenditures relate 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. Other construction expenditures for 2002 are estimated to total $5.0 million and for the five-year period ending 2006 are expected to be $7.1 million. The majority of the planned other construction in the five-year period will go toward the installation of new financial hardware and software by Support Group.

Cleco Power Construction

Cleco Power's construction expenditures, excluding AFUDC, totaled $45.6 million in 2001, $47.9 million in 2000, and $51.7 million in 1999.

Cleco Power's construction expenditures, excluding AFUDC, for 2002 are estimated to be $66.2 million and for the five-year period ending 2006 are expected to total $368.8 million. About one-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. Also, Cleco Power will continue to invest in technology to allow it to operate more efficiently.

In 2001, 2000 and 1999, 100% of Cleco Power's construction requirements were funded internally. In 2002, 94.2% of construction requirements are expected to be funded internally. For the five-year period ending 2006, 90.7% of the construction requirements are expected to be funded internally.

Midstream Construction and Investment in Subsidiaries

Additions to property, plant and equipment totaled $3.2 million in 2001, $60.3 million in 2000, and $127.3 million in 1999. Cash investments in subsidiaries, as discussed below, totaled $133.3 million in 2001, $97.2 million in 2000, and zero in 1999. Total construction and investment in subsidiaries totaled $136.5 million in 2001, $157.5 million in 2000, and $127.3 million in 1999.

Midstream is currently participating in two joint ventures, both of which are 50% owned by Midstream.

APP is a joint venture with Calpine Corporation that is in the process of constructing a 1,160- MW, combined-cycle, natural gas-fired power plant near Eunice, Louisiana. Total construction costs of the plant to be incurred by APP are estimated at $564.0 million, with an estimated completion date of mid-2002. As of December 31, 2001, Midstream's equity in APP was $223.0 million. Long-term, non recourse financing at APP is expected to be received by the third quarter of 2002. The total equity contribution to APP, net of reimbursement from permanent and interim project financing, is expected to be approximately $70.0 million. See the Notes to the Consolidated Financial Statements, Note 19 - "Commitments and Contingencies" for information concerning a proceeding relating to APP's water and air permits.

PEP is a joint venture with Mirant Corporation that is in the process of constructing a 725-MW, natural gas-fired power plant in Perryville, Louisiana. Total construction costs of the plant to be incurred by PEP are estimated at $336.0 million. A 157-MW combustion turbine commenced simple-cycle operation in July 2001. Full commercial operation of a 568-MW combined-cycle unit is expected for the summer of 2002. As of December 31, 2001, Midstream's equity in PEP was $3.4 million. An eight-year mini-perm, non recourse financing of $300 million at PEP was received in the second quarter of 2001. Total equity contribution in PEP, net of reimbursement from project financing, is expected to be approximately $18.0 million.

Midstream's 2002 expenditures for construction and investment in subsidiaries are estimated to total $81.2 million and for the five-year period ending 2006 are expected to total $285.7 million. Most of the planned construction and investment in the five-year period will consist of construction and/or acquisition of energy-related assets.

In 2001, 19.2% of Midstream's construction and investment in subsidiaries requirements were funded internally, compared to 15.3% in 2000 and 1.6% in 1999. In 2002, 28.8% of Midstream's construction and investment in subsidiaries requirements are expected to be funded internally. For the five-year period ending 2006, 64.4% of Midstream's construction and investment in subsidiaries requirements are expected to be funded internally.

Other Cash Requirements

Scheduled maturities of debt will total $30.8 million for 2002 and $312.4 million for the five-year period ending 2006. In 1991 Cleco began a common stock repurchase program, in which up to $30.0 million of common stock may be repurchased. At December 31, 2001, approximately $16.1 million of common stock was available for repurchase. 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. Cleco purchased the following amounts of stock under the repurchase plan:

	2001 - $3.0 million
	2000 - None
	1999 - $3.8 million

The following chart summarizes the cash contractual obligations by year and category:

	Payments Due by Period
Contractual obligations	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Long-term debt	$ 30,843	$ 64,460	$ 217,144	$ 345,975
Equity investments in investees	18,023	-	-	-
Total contractual cash obligations	$ 48,866	$ 64,460	$ 217,144	$ 345,975
	======	======	=======	======

Off-Balance Sheet Commitments

We have entered into various off-balance sheet commitments in the form of guaranties and a standby letter of credit in order to facilitate the activities of our affiliates. These off-balance sheet commitments require us to make payments to various counterparties if our affiliates do not fulfill certain contractual obligations. The off-balance sheet commitments are not recognized on our Consolidated Balance Sheet because we have determined that it is not probable that payments will be required since we have determined that our affiliates are able to perform these obligations under their contracts. Certain amounts of these commitments reduce the amount of the credit facilities available to Cleco by an amount defined by the credit agreement. The following table has a schedule of off-balance sheet commitments grouped by the affiliate on whose behalf each commitment was entered into. The schedule shows the face amount of the commitment, any reductions, the net amount and reductions in our ability to draw on our credit facilities. Following the table is a discussion of the off-balance sheet commitments. The discussion should be read in conjunction with the table in order to understand the impact of the off-balance sheet commitments on our financial condition.

Affiliate	Face amount	Reductions	Net amount	Reductions to the amount available to be drawn on Cleco's credit facilities
	(Thousands)
Acadia Power Holding LLC
Guaranties issued to:
APP Tolling Agreement counterparty	$ 12,500		$ 12,500	$ 12,500
APP plant construction contractor	3,885		3,885	3,885
APP (under APP's partnership agreement)	250,000	$ 214,260	35,740	-

Perryville Energy Holdings LLC
Guaranties issued to:
PEP Tolling Agreement counterparty	13,500	-	13,500	13,500
PEP plant construction contractor	7,144	-	7,144	7,144
PEP (equity subscription)	18,023	-	18,023	18,023

Midstream
Subordinated guaranty issued to bank	-	-	-	-

Marketing & Trading
Guaranties issued to various trading counterparties	122,250	74,000	48,250	-

Evangeline
Standby letter of credit issued to tolling agreement counterparty	15,000	-	15,000	15,000

	$ 442,302	$ 288,260	$ 154,042	$ 70,052
	======	======	======	======

If APP, PEP or Evangeline fail to perform certain obligations under their respective tolling agreements, we will be required to make payments to the respective tolling agreement counterparties of APP, PEP or Evangeline under the commitments listed in the above schedule. Our obligations under the APP and PEP commitments are in the form of guaranties and are limited to $12.5 million and $13.5 million, respectively. Our obligation under the Evangeline commitments is in the form of a standby letter of credit and is limited to $15 million. Management expects APP, PEP and Evangeline to be able to meet their respective obligations under the tolling agreements and does not expect Cleco to be required to make payments to the counterparties. However, under the covenants associated with our credit facilities, the entire net amount of the commitments reduces the amount we can borrow from our credit facilities. The guaranties for APP and PEP are in force until 2022. The letter of credit for Evangeline is in force until the year 2020.

If APP or PEP cannot pay their contractors building their plants, we will be required to pay the current amount outstanding. Our obligation under the PEP arrangement is in the form of a guaranty and is limited to $12 million. Our obligation under the APP arrangement is in the form of a guaranty and is limited to 50% of the current total current contractor amount outstanding. Management expects both affiliates to have the ability to pay their respective contractor as scheduled and does not expect to pay the bill on behalf of the affiliates. However, under the covenants associated with our credit facilities, the current monthly amount due to the contractors reduces the amount we can borrow from our credit facilities. These guaranties issued to APP and PEP's construction contractors are in force until the contractors are finished constructing the plants and final payments are made by APP and PEP, respectively.

Cleco has issued a guaranty to APP to contribute up to $250 million to APP. The $250 million is reduced by the $3.9 million guaranty issued to the APP construction contractor and the $210.3 million in cash previously contributed to APP by Cleco. The $250 million guaranty will be replaced with an equity contribution when project-level financing is obtained. We currently expect project-level financing to occur in the third quarter of 2002.

We have an obligation to make a $18.0 million equity subscription to PEP. As construction is completed on the plant, the equity subscription will be satisfied by equity contributions. We currently expect to have contributed the entire amount by the time the plant is declared in commercial operation, which is expected to be in July 2002. Under the covenants associated with our credit facilities, the entire equity subscription reduces the amount we can borrow from our credit facilities.

In conjunction with Midstream entering into a $36.8 million line of credit, Cleco entered into a subordinated guaranty with the bank issuing the line of credit. Under the terms of the guaranty, Cleco will pay principal and interest if Midstream is unable to pay. At December 31, 2001, there were no principal and interest payable under the line of credit, therefore Cleco was not exposed to pay under the guaranty.

Cleco has issued guaranties to Marketing & Trading's counterparties in order to facilitate energy marketing and trading. In conjunction with the guaranties issued, Marketing & Trading has received guaranties from certain counterparties and has entered into

netting agreements whereby Marketing & Trading is only exposed to the net open position with each counterparty. The guaranties issued and received expire at various times. The balance of net Marketing & Trading guaranties does not affect the amount we can borrow from our credit facilities. However, the total amount of guarantied net open positions with all of Marketing & Trading's counterparties over $20 million reduces the amounts we can borrow under our credit facilities. At December 31, 2001, the total guarantied net open positions was $3.3 million, so our credit facilities were not impacted. From time to time Marketing & Trading will trade with new counterparties, and it is expected that Cleco may be required to issue guaranties to these new counterparties. Marketing & Trading may also change the amount of trading with current counterparties and stop trading with current counterparties. As counterparties and amounts traded change, corresponding changes will be made in the level of guaranties issued.

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

		Amount of Commitment Expiration Per Period
Commercial commitment	Net amount committed	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Guaranties	$ 139,042	$ 113,042	-	-	$ 26,000
Standby letter of credit	15,000	-	-	-	15,000
Total commercial commitments	$ 154,042	$ 113,042			$ 41,000

Inflation

Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged approximately 2.8% during the three years ended December 31, 2001. We believe inflation, at this level, does not materially affect Cleco's 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 plant in future years.

INDUSTRY DEVELOPMENTS / CUSTOMER CHOICE

Forces driving increased competition in the electric utility industry involve 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 potentially 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 plan. The staff is to also monitor surrounding areas, and if any commence retail access, are to report back the success or failure of those efforts 12 months after the initiatives begin. At the federal level, several bills, some with conflicting provisions, have been introduced and actively debated this past year to promote a competitive environment in the electric utility industry, although none passed. Conversely, the troubled electric supply situation in California over the past two years has led many in the industry to reexamine the restructuring process. While a competitive environment 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 debate relating to customer choice and other related issues to continue in legislative and regulatory bodies in 2002. At this time, Cleco Power cannot predict whether any legislation or regulation affecting it will be enacted or adopted during 2002 and, if enacted, what form such legislation or regulation might take.

A potentially competitive environment presents both the opportunity to supply electricity to new customers and the risk of losing existing customers. The LPSC is currently soliciting comments for expanded generation supply options for utility 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 account for approximately 59% of Cleco's consolidated 2001 revenues. 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 plant facility 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, providing customers with lower electricity rates. A base rate decrease of $3 million annually became effective November 1, 1996, with a second decrease of an additional $2 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 CPS from Cleco Power's LPSC regulated rate base into Evangeline, which then repowered the generating 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 of 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 $2.4 million in September 2001. Of that amount, approximately $1.8 million was reflective of the earnings level achieved in the previous earnings period, $0.1 million represented an under-refunded amount from the previous refund, and $0.5 million from LPSC Case No. U-24064. The determination of any refund relative to the 2001 earnings monitoring period is under review by LPSC Staff. See the Notes to the Consolidated Financial Statements, Note 12 - "Accrual of Estimated Customer Credits" for information concerning amounts accrued by Cleco Power based on the settlement agreement.

In November 1997 the LPSC issued an order in a generic docket that promulgated new standards for the monthly Fuel Adjustment Clause (FAC) rate filings of electric utility companies under its jurisdiction. The order adopted new rules and procedures for the monthly FAC 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 FAC, it offset this reduction with an increase in the base rates. New rate schedules that incorporate the shifting of costs from FAC to base rates were calculated, subsequently approved by the LPSC and implemented on January 1, 2000. The changes resulted in an immaterial effect upon Cleco's financial condition and results of operations for 2001.

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 and expired. Cleco Power successfully negotiated the following franchises during 2001:

*	In February 2001 Cleco Power successfully negotiated a franchise renewal with the city of Jeanerette for a 20-year franchise applicable to its approximately 3,000 customers. The city of Jeanerette franchise had expired in 1997, and Cleco Power continued to serve the city while negotiating for a new franchise.
*	In October 2001 the franchise with the city of Washington for its approximately 1,900 customers was successfully renewed for a term of 25 years.

Cleco Power's franchise with the city of Franklinton, and its approximately 2,500 customers, will be up for renewal in 2003.

ENVIRONMENTAL MATTERS

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

In December 2001 the Evangeline facility received a Compliance Order from the Louisiana Department of Environmental Quality for past exceedances of the facility's water discharge permit. The first group of exceedances occurred during the conclusion of significant construction activities at the facility while the second group of exceedances was associated with a new wastewater neutralization system. The facility now performs batch testing prior to discharge to prevent future violations. The operational problems have been resolved, and we do not expect any significant penalty associated with the Compliance Order.

Cleco continues 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.

Implementation of Phase I of the Clean Air Act did not require Cleco to reduce sulfur emissions at Cleco Power's solid-fuel generating units, which either burn low-sulfur coal or utilize pollution control equipment. Installation of continuous emission monitoring equipment on Cleco Power's generating 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, these requirements have not significantly affected the operation of Cleco's generating units. However, some capital investment may continue to be necessary to comply with Phase II requirements. The following table lists capital expenditures for environmental matters by subsidiary.

Subsidiary	Capital expenditures for 2001	Projected capital expenditures for 2002
	(Thousands)
Cleco Power	$ 470	$ 550
Evangeline	-	-
Total	$ 470	$ 550
	=====	=====

See the Notes to the Consolidated Financial Statements, Note 19 - "Commitments and Contingencies."

REGULATORY MATTERS

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 associated services.

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

In 1996 the FERC issued Orders No. 888 and 889 requiring open access to utilities' transmission systems. The open access provisions require FERC-regulated electric utilities to offer third parties access to transmission under terms and conditions comparable to the utilities' use of their own systems. In addition, Order No. 888, as amended, provides for the full recovery of wholesale stranded costs if the costs were prudently incurred to serve wholesale customers and would go unrecovered if those customers used open access transmission service and moved to another electricity supplier. The stranded costs would be recovered from the departing customers. Order No. 888, as amended, also allows customers under existing wholesale sales contracts to seek FERC approval to modify their contracts on a case-by-case basis. Because of the "grandfather" provisions of Orders No. 888 and 889, most of Cleco Power's existing transmission contracts are not affected. To date, the orders have not had a material effect on Cleco's financial condition or results of operation.

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 Regional Transmission Organization (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. On July 11, 2001, FERC issued orders stating its intention to form four regional RTOs covering the Northeast, Southeast, Midwest and West. Since this date the FERC has relaxed its mandate for the four RTOs, but is still insisting upon the large regional RTO model. Many transmission owning utilities and system operators have been trying to interpret and implement the FERC directives by trying to organize acceptable RTOs. In November, Entergy and Southern Companies 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. For Cleco Power, this provides an opportunity to participate in both markets due to its proximity to both proposed RTOs. Cleco Power is continuing to participate in the ongoing RTO development process. Cleco Power cannot anticipate the final form and configuration that this organizational process will yield nor which specific RTO it will join. 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 requiring 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. RT01-100-000 conflict with the public interest. The order does not limit Cleco Power's ability to participate in RTO development.

The transfer of control of Cleco Power's transmission facilities to an RTO has the potential to materially affect Cleco's financial condition and results of operations. Additionally, 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.

Wholesale energy markets, including the market for wholesale electric power, are becoming even more competitive than in the past, as the number of market participants in these markets increases with the enactment of the Energy Policy Act and the regulatory activities of the FERC. Federal and state regulators and legislators are studying potential effects of restructuring the vertically integrated utility systems and providing retail customers a choice of supplier. At this time it is not possible to predict when or if retail customers will be able to choose their electric suppliers. No federal legislation was passed in the most recent legislative session, although several bills were proposed that addressed both restructuring of the industry and transmission reliability issues. Cleco cannot predict what future legislation may be proposed and/or passed and what impact it may have upon its results of operations or financial condition.

FINANCIAL RISK MANAGEMENT

The market risk inherent in Cleco's market risk-sensitive instruments and positions is the potential change arising from changes in the short-, medium- and long-term interest rates; the commodity price of electricity and the commodity price of natural gas. Generally, Cleco Power's market risk-sensitive instruments and positions are characterized as "other than trading;" however, Cleco Power does have positions that are considered "trading" as defined by EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." All of Marketing & Trading's and Cleco Energy's positions are characterized as "trading" under EITF No. 98-10. Cleco's exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and the commodity price of electricity and natural gas. Management's views on market risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains or losses. The views do represent, within the parameters disclosed, what management estimates may happen.

Interest

Cleco has entered into various fixed- and variable-rate debt obligations. See the Notes to the Consolidated Financial Statements, Note 5 - "Debt" for details. 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, 2001, the carrying value of Cleco's long-term, fixed-rate debt was approximately $651.0 million, with a fair market value of approximately $722.3 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 $43.0 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, 2001, the carrying value of Cleco's long-term, variable-rate debt was approximately $7.4 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 $74,000 in Cleco's pretax earnings.

As of December 31, 2001, the carrying value of Cleco's short-term, variable-rate debt was approximately $179.5 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 $1.8 million in Cleco's pretax earnings.

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

Market Risk

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

Marketing & Trading engages in marketing and trading of electricity and natural gas. All of Marketing & Trading's trades are considered "trading" under EITF No. 98-10 and are marked-to-market. Due to market price volatility, marked-to-market reporting may introduce volatility to carrying values and hence to Cleco's financial statements. The net marked-to-market impact of trading positions of Marketing & Trading at December 31, 2001, was a gain of $0.1 million.

Cleco Power engages in marketing and trading of electricity and natural gas and provides fuel for generation and purchased power to meet the electricity demands of customers. Financial positions that are not used to meet the electricity demands of customers are considered as "trading." At December 31, 2001, the net marked-to-market impact for those positions was a gain of less than $0.1 million.

Cleco Energy engages in providing 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, and changes in market values of the positions are reflected on the Consolidated Statements of Income. At December 31, 2001, the net marked-to-market impact was a loss of $0.1 million.

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 positions and a 99.7% confidence level for electricity 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 the year ended December 31, 2001, as well as the VAR at December 31, 2001, and 2000, is summarized below:

Value-at-Risk	For the year ended December 31, 2001			At December 31,
	High	Low	Average	2001	2000
	(Thousands)
Marketing & Trading	$ 4,056.8	$ 166.7	$ 1,386.2	$ 948.8	$ 1,570.6
Cleco Power	$ 1,422.3	$ 7.1	$ 387.4	$ 11.2	$ 322.4
Cleco Energy	$ 352.0	$ 2.3	$ 157.0	$ 174.0	$ -
Consolidated	$ 4,567.6	$ 546.7	$ 1,891.3	$ 1,134.0	$ 1,893.0

The following table summarizes the market value maturities of contracts with prices actively traded at December 31, 2001:

	Fair Value of Contracts at Period-End
Contractual Obligations	Maturity less than one year	Maturity 1-3 years	Maturity over three years	Total Fair Value
	(Thousands)
Assets
Cleco Power	$ 798	$ -	$ -	$ 798
Midstream	160,522	348	-	160,870
	$ 161,320	$ 348	$ -	$ 161,668
	=======	=====	=====	=======
Liabilities
Cleco Power	$ 4,091	$ -	$ -	$ 4,091
Midstream	153,997	348	-	154,345
	$ 158,088	$ 348	$ -	$ 158,436
	=======	=====	=====	=======

New Accounting Standards

For discussion of new accounting standards, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies," which is incorporated herein by reference.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

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

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

*	Factors affecting operations, such as:

	(1)	unusual weather conditions;
	(2)	catastrophic weather-related damage;
	(3)	unscheduled generation outages;
	(4)	unusual maintenance or repairs;
	(5)	unanticipated changes in fossil fuel costs, gas supply costs, or availability constraints;
	(6)	environmental incidents;
	(7)	acts of terrorism; and
	(8)	electric transmission or gas pipeline system constraints.

*	Legislative and regulatory initiatives regarding deregulation of the industry, including potential deregulation legislation in Louisiana, and potential national deregulation legislation.
*	The timing and extent of the entry of additional competition in electric or gas markets and the effects of continued industry consolidation through the pursuit of mergers, acquisitions, and strategic alliances.
*	Regulatory factors such as changes in the policies or procedures that set rates; changes in our ability to recover capital expenditures for environmental compliance, purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases.
*	Financial or regulatory accounting principles or policies imposed by governing bodies.
*	Political, legal, and economic conditions and developments in the United States. This would include inflation rates and monetary fluctuations.
*	Changing market conditions and other factors related to physical energy and financial trading activities. These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.
*	The performance of projects undertaken by our nonregulated businesses and the success of efforts to invest in and develop new opportunities.
*	Availability of, or cost of, capital.
*	Employee work force factors, including changes in key executives, and work stoppages.
*	Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
*	Changes in federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.

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

EXHIBIT 99.1

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

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

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) with respect to the rates Cleco Power can charge its customers. Cleco Power serves approximately 250,000 customers mainly in central Louisiana.
*	The primary business of Cleco Midstream Resources LLC (Midstream) is to own and operate wholesale generation stations, invest in joint ventures that own and operate wholesale generation stations, own and operate wholesale natural gas pipelines, and engage in energy marketing activities.
*	Our other segment consists of the holding company, a shared services subsidiary, and an investment subsidiary.

Reorganization

Cleco Corporation

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 revenues	$	1,058,619	$	820,015	$	238,604	29.1 %
Operating expenses	$	909,079	$	672,820	$	236,259	35.1 %
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 of income taxes	$	-	$	2,508	$	(2,508)	(100.0)%
Net income applicable to common stock	$	68,362	$	63,112	$	5,250	8.3 %

Cleco Power

Revenues are affected by the following factors:

*	deregulation,
*	retail wheeling,
*	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.

Energy marketing sales primarily are affected by demand and supply of energy, market prices, and transmission constraints.

Fuel and power purchased are affected by the following factors:

Other expenses

Results of Operations - Continuing Operations

Year ended December 31, 2001, compared to Year ended December 31, 2000

	For the year ended December 31,
	2001	2000	Variance	Change
Operating revenues:	(Thousands)
Base	$ 318,715	$ 322,716	$ (4,001)	(1.2)%
Fuel cost recovery	304,347	296,812	7,535	2.5 %
Affiliate revenue	3,530	9,256	(5,726)	(61.9)%
Estimated customer credits	(1,800)	(1,233)	(567)	(46.0)%
Energy marketing	31,212	18,078	13,134	72.7 %
Total operating revenues	656,004	645,629	10,375	1.6 %
Operating expenses:
Purchases for energy marketing operations	29,756	13,583	16,173	119.1 %
Operations and maintenance	124,694	112,043	12,651	11.3 %
Fuel and purchased power	302,482	303,987	(1,505)	(0.5)%
Depreciation	50,594	49,787	807	1.6 %
Taxes other than income	35,358	36,533	(1,175)	(3.2)%
Intercompany	2,987	7,871	(4,884)	(62.1)%
Total operating expenses	545,871	523,804	22,067	4.2 %
Operating Income	$ 110,133	$ 121,825	$ (11,692)	(9.6)%
	=======	========	========

	For the year ended December 31,
	2001	2000	Change
	(Million kilowatt hours )
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 %
Total retail, billed	8,077	8,393	(3.8)%
Unbilled	34	162	(79.0)%
Sales for resale	398	334	19.2 %
Total on-system customer sales	8,509	8,889	(4.3)%
Short-term sales to other utilities	129	77	67.5 %
Sales from marketing activities	5	81	(93.8)%
Total electric sales	8,643	9,047	(4.5)%
	======	======

The following chart indicates the percentage variance from normal conditions and from the prior year for cooling/heating degree-days.

Cooling/Heating degree-days For the year ended December 31,
	2001	2000
Cooling Degree-Days:
Increase/(Decrease) from Normal	6.1 %	15.3 %
Increase/(Decrease) from Prior Year	(7.7)%	0.3 %
Heating Degree-Days:
Increase/(Decrease) from Normal	(15.4)%	(6.6)%
Increase/(Decrease) from Prior Year	(9.7)%	34.7 %

Energy Marketing Operations For the year ended December 31,
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 31,159	$ 17,453	$ 13,706	78.5 %
Mark-to-market	53	625	(572)	(91.5)%
Total	31,212	18,078	13,134	72.7 %
Energy trading expenses	29,756	13,583	16,173	119.1 %
Net margins	$ 1,456	$ 4,495	$ (3,039)	(67.6)%
	=======	=======	=======

Interest expense decreased $1.9 million in 2001 compared to 2000 primarily due to a decrease in medium-term notes and a decrease in the interest rates paid on commercial paper.

Midstream

General factors affecting Midstream

The majority of Midstream's revenues are derived from its power plant operations and energy marketing and trading operations.

*	16% in the first quarter,
*	23% in the second quarter,
*	42% in the third quarter, and
*	19% in the fourth quarter.

Results of Operations - Continuing 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 revenues:
Energy marketing revenue	$ 344,062	$ 141,812	$ 202,250	142.6 %
Tolling revenue	60,522	41,354	19,168	46.4 %
Other operations	1,461	403	1,058	262.5 %
Intercompany	14,030	37,667	(23,637)	(62.8)%
Total operating revenues	420,075	221,236	198,839	89.9 %
Operating expenses:
Purchases for energy marketing and tolling operations	329,677	134,659	195,018	144.8 %
Operations and maintenance	26,567	19,878	6,689	33.7 %
Depreciation	9,188	5,952	3,236	54.4 %
Taxes other than income	1,255	828	427	51.6 %
Intercompany	11,465	34,716	(23,251)	(66.9) %
Total operating expenses	378,152	196,033	182,119	92.9 %
Operating income	$ 41,923	$ 25,203	$ 16,720	66.3 %
	=======	=======	=======

Energy Marketing and Trading Operations

The chart below presents a summary of electricity and natural gas marketed during 2001 compared to 2000.

	For the year ended December 31
	2001	2000	Change
Electricity (Million kWh)	3,278	1,274	157.3%
Natural gas (MMBtu)	28,608,058	18,611,729	53.7%

See "Financial Risk Management" for more information about energy marketing and trading operations.

Power Plant Operations

Other

Net income from continuing operations from our Other segment decreased $1.4 million in 2001 principally because of an increase in financing expenses compared to 2000.

Cleco Corporation

Consolidated Results of Operations

Year ended December 31, 2000 compared to Year ended December 31, 1999

	For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Operating revenues	$ 820,015	$ 764,435	$ 55,580	7.3 %
Operating expenses	$ 672,820	$ 650,019	$ 22,801	3.5 %
Net income from continuing operations	$ 69,335	$ 58,070	$ 11,265	19.4 %
Loss from discontinued operations, net	$ (6,861)	$ (1,304)	$ (5,557)	426.2 %
Extraordinary item, net of income taxes	$ 2,508	$ -	$ 2,508	100.0 %
Net income applicable to common stock	$ 63,112	$ 54,756	$ 8,356	15.3 %

Higher net income from continuing operations at Cleco Power in 2000 compared to 1999 was largely the result of higher MWh sales to on-system customers in 2000.

Cleco Power

Results of Operations - Continuing Operations

Year ended December 31, 2000, compared to Year ended December 31, 1999

	For the year ended December 31,
	2000	1999	Variance	Change
Operating revenues:	(Thousands)
Base	$ 322,716	$ 306,225	$ 16,491	5.4 %
Fuel cost recovery	296,812	202,565	94,247	46.5 %
Affiliate revenue	9,256	7,816	1,440	18.4 %
Estimated customer credits	(1,233)	(2,776)	1,543	55.6 %
Energy marketing	18,078	238,082	(220,004)	(92.4)%
Total operating revenues	645,629	751,912	(106,283)	(14.1)%
Operating expenses:
Purchases for energy marketing operations	13,583	230,084	(216,501)	(94.1)%
Operations and maintenance	112,043	105,225	6,818	6.5 %
Fuel and purchased power	303,987	212,128	91,859	43.3 %
Depreciation	49,787	49,285	502	1.0 %
Taxes other than income	36,533	35,870	663	1.8 %
Intercompany	7,871	6,397	1,474	23.0 %
Total operating expenses	523,804	638,989	(115,185)	(18.0)%
Operating income	$ 121,825	$ 112,923	$ 8,902	7.9 %
	=======	=======	========

	For the year ended December 31,
	2000	1999	Change
	(Million kWh)
Electric sales:
Residential	3,296	3,147	4.7 %
Commercial	1,636	1,573	4.0 %
Industrial	2,883	2,717	6.1 %
Other retail	578	562	2.8 %
Total retail, billed	8,393	7,999	4.9 %
Unbilled	162	105	54.3 %
Sales for resale	334	362	(7.7)%
Total on-system customer sales	8,889	8,466	5.0 %
Short-term sales to other utilities	77	126	(38.9)%
Sales from marketing activities	81	5,815	(98.6)%
Total electric sales	9,047	14,407	(37.2)%
	=====	======

Sales to commercial and industrial customers during 2000 were higher compared to 1999 primarily because of increased economic growth in the nation and the region served by Cleco Power.

The following chart indicates the percentage variance from normal conditions and from the prior year for cooling/heating degree-days for the years ended December 31, 2000 and 1999.

Cooling/Heating degree-days For the year ended December 31,
	2000	1999
Cooling Degree-Days:
Increase/(Decrease) from Normal	15.3 %	15.5 %
Increase/(Decrease) from Prior Year	0.3 %	(3.8)%
Heating Degree-Days:
Increase/(Decrease) from Normal	(6.6)%	(31.3)%
Increase/(Decrease) from Prior Year	34.7 %	(5.3)%

Energy Marketing Operations For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Energy trading revenue	$ 17,453	$ 238,652	$(221,199)	(92.7)%
Marked-to-market	625	(570)	1,195	- %
Total	18,078	238,082	(220,004)	(92.4)%
Energy trading expenses	13,583	230,084	(216,501)	(94.1)%
Net margins	$ 4,495	$ 7,998	$ (3,503)	(43.8)%
	=======	=======	=======

Midstream

Results of Operations - Continuing Operations

Year ended December 31, 2000, compared to Year ended December 31, 1999

	For the year ended December 31,
	2000	1999	Variance	Change
	(Thousands)
Operating revenues:
Energy marketing revenue	$ 141,812	$ 18,698	$ 123,114	658.4 %
Tolling revenue	41,354	-	41,354	100.0 %
Other operations	403	1,641	(1,238)	(75.4)%
Intercompany	37,667	6,493	31,174	480.1 %
Total operating revenues	221,236	26,832	194,404	724.5 %
Operating expenses:
Purchases for energy marketing and tolling operations	134,659	14,856	119,803	806.4 %
Operations and maintenance	19,878	4,545	15,333	337.3 %
Depreciation	5,952	668	5,284	791.0 %
Taxes other than income	828	175	653	373.1 %
Intercompany	34,716	4,860	29,856	614.3 %
Total operating expenses	196,033	25,104	170,929	680.9 %
Operating income	$ 25,203	$ 1,728	$ 23,475	- %
	=======	=======	=======

Energy Marketing and Trading Operations

The chart below presents a summary of electricity and natural gas marketed during 2000 as compared to 1999.

	For the year ended December 31,
	2000	1999	Change
Electricity (Million kWh)	1,274	135	843.7%
Natural gas (MMBtu)	18,611,729	8,817,944	111.1%

See "Financial Risk Management" for more information about energy marketing and trading operations.

Power Plant Operations

Tolling revenues were $41.3 million in 2000 compared to none in 1999. The change was caused by the Evangeline facility beginning full commercial operation in July 2000.

Discontinued Operations

At December 31, 2001, UTS had nominal assets since receivables have been either collected or charged against the reserve.

Additional information about UTS follows:

	For the year ended December 31,
	2001	2000	1999
	(Thousands)
Revenues	$ 5,043	$18,125	$ 6,866
Pretax loss from operations of UTS	$ -	$ 8,801	$ 1,966
Income tax benefit associated with loss from operations	$ -	$ 3,390	$ 662
Pretax loss from disposal of UTS	$ 3,310	$ 2,358	$ -
Income tax benefit associated with loss on disposal	$ 1,275	$ 908	$ -

Extraordinary Gain

Critical Accounting Policies

Cleco Power

Midstream

*	Evangeline accounts for the Evangeline Tolling Agreement as an operating lease. If the Evangeline Tolling Agreement were modified to the extent that would make lease accounting improper, then future results could materially differ from those currently reported. In the event the Evangeline Tolling Agreement were to be discharged through judicial proceedings (such as bankruptcy court), future results could be materially different than current results. Currently, Evangeline has in place guaranties that it expects would mitigate some of the effects of bankruptcy or other judicial proceedings. See the Notes to the Consolidated Financial Statements, Note 14 - "Operating Lease," for more information about the Evangeline Tolling Agreement.
*	Midstream companies currently engage in energy marketing and trading activities. Contracts (for example, options, futures, calls and swaps) are entered into with counterparties based on assumptions of future movements of energy prices, ability of counterparties to perform contractual obligations, corporate risk strategies and internal controls. These derivative instruments are recorded on Cleco's financial statements at their fair market value. If the market moves in an unexpected manner, if risk is not timely and adequately balanced, if counterparties fail to perform contractual obligations, or if internal controls are circumvented, actual results could differ materially from expected results. See "Financial Risk Management" for more information about Midstream's energy trading.
*	Midstream accounts for its investments in APP and PEP under the equity method of accounting due to the lack of a certain level of control over the entities. If circumstances occur which would require APP and PEP to be consolidated, our financial condition and results of operations could be significantly impacted.
*	Midstream has concluded it is in compliance with current environmental laws and regulations. If a currently unknown liability is discovered, or an event occurs to put Midstream in noncompliance, or the laws or regulations change, Midstream's financial condition may be adversely impacted by fines and actions required to return Midstream to compliance.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

The following table shows short-term debt by subsidiary.

Subsidiary	At December 31,
	2001	2000
	(Thousands)
Cleco Corporation (Holding Company Level)
Commercial paper	$ 36,933	$ 54,220
Bank loans	77,000	-
Cleco Power
Commercial paper	63,742	41,397
Midstream
Bank loans	1,880	340
Total	$ 179,555	$ 95,957
	=======	======

Cleco Corporation (Holding Company Level)

Cleco Power

Midstream

Other

CASH GENERATION AND CASH REQUIREMENTS

Cash Flows

Shelf Registrations

Construction and Investment in Subsidiaries Overview

Cleco Power Construction

Cleco Power's construction expenditures, excluding AFUDC, totaled $45.6 million in 2001, $47.9 million in 2000, and $51.7 million in 1999.

Midstream Construction and Investment in Subsidiaries

Midstream is currently participating in two joint ventures, both of which are 50% owned by Midstream.

Other Cash Requirements

	2001 - $3.0 million
	2000 - None
	1999 - $3.8 million

The following chart summarizes the cash contractual obligations by year and category:

	Payments Due by Period
Contractual obligations	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Long-term debt	$ 30,843	$ 64,460	$ 217,144	$ 345,975
Equity investments in investees	18,023	-	-	-
Total contractual cash obligations	$ 48,866	$ 64,460	$ 217,144	$ 345,975
	======	======	=======	======

Off-Balance Sheet Commitments

Affiliate	Face amount	Reductions	Net amount	Reductions to the amount available to be drawn on Cleco's credit facilities
	(Thousands)
Acadia Power Holding LLC
Guaranties issued to:
APP Tolling Agreement counterparty	$ 12,500		$ 12,500	$ 12,500
APP plant construction contractor	3,885		3,885	3,885
APP (under APP's partnership agreement)	250,000	$ 214,260	35,740	-

Perryville Energy Holdings LLC
Guaranties issued to:
PEP Tolling Agreement counterparty	13,500	-	13,500	13,500
PEP plant construction contractor	7,144	-	7,144	7,144
PEP (equity subscription)	18,023	-	18,023	18,023

Midstream
Subordinated guaranty issued to bank	-	-	-	-

Marketing & Trading
Guaranties issued to various trading counterparties	122,250	74,000	48,250	-

Evangeline
Standby letter of credit issued to tolling agreement counterparty	15,000	-	15,000	15,000

	$ 442,302	$ 288,260	$ 154,042	$ 70,052
	======	======	======	======

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

		Amount of Commitment Expiration Per Period
Commercial commitment	Net amount committed	Less than one year	1-3 years	4-5 years	Over 5 years
	(Thousands)
Guaranties	$ 139,042	$ 113,042	-	-	$ 26,000
Standby letter of credit	15,000	-	-	-	15,000
Total commercial commitments	$ 154,042	$ 113,042			$ 41,000

Inflation

INDUSTRY DEVELOPMENTS / CUSTOMER CHOICE

RETAIL RATES OF CLECO POWER

Franchises

*	In February 2001 Cleco Power successfully negotiated a franchise renewal with the city of Jeanerette for a 20-year franchise applicable to its approximately 3,000 customers. The city of Jeanerette franchise had expired in 1997, and Cleco Power continued to serve the city while negotiating for a new franchise.
*	In October 2001 the franchise with the city of Washington for its approximately 1,900 customers was successfully renewed for a term of 25 years.

Cleco Power's franchise with the city of Franklinton, and its approximately 2,500 customers, will be up for renewal in 2003.

ENVIRONMENTAL MATTERS

Subsidiary	Capital expenditures for 2001	Projected capital expenditures for 2002
	(Thousands)
Cleco Power	$ 470	$ 550
Evangeline	-	-
Total	$ 470	$ 550
	=====	=====

See the Notes to the Consolidated Financial Statements, Note 19 - "Commitments and Contingencies."

REGULATORY MATTERS

FINANCIAL RISK MANAGEMENT

Interest

Market Risk

Based on these assumptions, the high, low and average VAR for the year ended December 31, 2001, as well as the VAR at December 31, 2001, and 2000, is summarized below:

Value-at-Risk	For the year ended December 31, 2001			At December 31,
	High	Low	Average	2001	2000
	(Thousands)
Marketing & Trading	$ 4,056.8	$ 166.7	$ 1,386.2	$ 948.8	$ 1,570.6
Cleco Power	$ 1,422.3	$ 7.1	$ 387.4	$ 11.2	$ 322.4
Cleco Energy	$ 352.0	$ 2.3	$ 157.0	$ 174.0	$ -
Consolidated	$ 4,567.6	$ 546.7	$ 1,891.3	$ 1,134.0	$ 1,893.0

The following table summarizes the market value maturities of contracts with prices actively traded at December 31, 2001:

	Fair Value of Contracts at Period-End
Contractual Obligations	Maturity less than one year	Maturity 1-3 years	Maturity over three years	Total Fair Value
	(Thousands)
Assets
Cleco Power	$ 798	$ -	$ -	$ 798
Midstream	160,522	348	-	160,870
	$ 161,320	$ 348	$ -	$ 161,668
	=======	=====	=====	=======
Liabilities
Cleco Power	$ 4,091	$ -	$ -	$ 4,091
Midstream	153,997	348	-	154,345
	$ 158,088	$ 348	$ -	$ 158,436
	=======	=====	=====	=======

New Accounting Standards

For discussion of new accounting standards, see the Notes to the Consolidated Financial Statements, Note 2 - "Summary of Significant Accounting Policies," which is incorporated herein by reference.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

*	Factors affecting operations, such as:

	(1)	unusual weather conditions;
	(2)	catastrophic weather-related damage;
	(3)	unscheduled generation outages;
	(4)	unusual maintenance or repairs;
	(5)	unanticipated changes in fossil fuel costs, gas supply costs, or availability constraints;
	(6)	environmental incidents;
	(7)	acts of terrorism; and
	(8)	electric transmission or gas pipeline system constraints.

*	Legislative and regulatory initiatives regarding deregulation of the industry, including potential deregulation legislation in Louisiana, and potential national deregulation legislation.
*	The timing and extent of the entry of additional competition in electric or gas markets and the effects of continued industry consolidation through the pursuit of mergers, acquisitions, and strategic alliances.
*	Regulatory factors such as changes in the policies or procedures that set rates; changes in our ability to recover capital expenditures for environmental compliance, purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases.
*	Financial or regulatory accounting principles or policies imposed by governing bodies.
*	Political, legal, and economic conditions and developments in the United States. This would include inflation rates and monetary fluctuations.
*	Changing market conditions and other factors related to physical energy and financial trading activities. These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.
*	The performance of projects undertaken by our nonregulated businesses and the success of efforts to invest in and develop new opportunities.
*	Availability of, or cost of, capital.
*	Employee work force factors, including changes in key executives, and work stoppages.
*	Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
*	Changes in federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.

CLECO CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	For the Year Ended December 31,
	2001		2000		1999
	(Thousands, except share and per share amounts)
Operating revenue
Retail electric operations	$ 623,062		$ 619,528		$ 508,790
Energy marketing and tolling operations	435,796		201,244		256,780
Other operations	1,561		476		1,641
Gross operating revenue	1,060,419		821,248		767,211
Less retail electric customer credits	1,800		1,233		2,776

Total operating revenue	1,058,619		820,015		764,435

Operating expenses
Fuel used for electric generation	184,516		182,151		145,229
Power purchased for utility customers	117,966		121,963		65,303
Purchases for energy marketing operations	359,433		148,242		244,384
Other operations	118,412		91,924		79,240
Maintenance	30,746		35,271		29,852
Depreciation	60,246		55,840		49,966
Taxes other than income taxes	37,760		37,429		36,045

Total operating expenses	909,079		672,820		650,019

Operating income	149,540		147,195		114,416
Interest income	8,202		6,628		1,697
Allowance for other funds used during construction	769		507		654
Other income (expense), net	322		(729)		(1,328)

Income before interest charges	158,833		153,601		115,439

Interest charges
Interest on debt and other, net of amount capitalized	47,852		48,721		28,412
Allowance for borrowed funds used during construction	(1,178)		(580)		(91)
Amortization of debt discount, premium and expense, net	1,530		1,164		1,282
Total interest charges	48,204		49,305		29,603
Net income from continuing operations before income taxes and preferred dividends	110,629		104,296		85,836
Federal and state income taxes	38,356		34,961		27,766
Net income from continuing operations	72,273		69,335		58,070

Discontinued operations
Loss from operations, net of income taxes	-		(5,411)		(1,304)
Loss on disposal of segment, net of income taxes	(2,035)		(1,450)		-
Total discontinued operations	(2,035)		(6,861)		(1,304)

Net income before extraordinary item	70,238		62,474		56,766

Extraordinary item, net of income taxes	-		2,508		-

Net income before preferred dividends	70,238		64,982		56,766

Preferred dividend requirements, net	1,876		1,870		2,010

Net income applicable to common stock	$ 68,362		$ 63,112		$ 54,756
	=======		========		=======

Average shares of common stock outstanding
Basic	45,000,955		44,947,718		45,002,648
Diluted	47,763,713		47,654,954		47,697,030
Basic earnings per share
From continuing operations	$	1.56	$	1.50	$	1.25
From discontinued operations	$	(0.04)	$	(0.15)	$	(0.03)
Extraordinary item	$	-	$	0.06	$	-
Net income applicable to common stock	$	1.52	$	1.41	$	1.22

Diluted earnings per share
From continuing operations	$	1.51	$	1.46	$	1.21
From discontinued operations	$	(0.04)	$	(0.15)	$	(0.03)
Extraordinary item	$	-	$	0.05	$	-
Net income applicable to common stock	$	1.47	$	1.36	$	1.18

Cash dividends paid per share of common stock	$	0.870	$	0.845	$	0.825

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

CLECO CORPORATION

CONSOLIDATED BALANCE SHEETS

	At December 31,
	2001	2000
	(Thousands)
Assets
Current assets
Cash and cash equivalents	$ 11,938	$ 29,407
Restricted cash	5,466	14,478
Customer accounts receivable (less allowance for doubtful accounts of $1,561 in 2001 and $1,983 in 2000)	47,543	74,620
Other accounts receivable	25,720	24,200
Unbilled revenues	17,863	37,547
Fuel inventory, at average cost	11,938	7,275
Material and supplies inventory, at average cost	16,160	15,956
Margin deposits	580	21,657
Risk management assets	1,818	19,070
Accumulated deferred fuel	7,979	3,617
Accumulated deferred federal and state income taxes, net	4,249	2,964
Other current assets	6,798	4,857
Total current assets	158,052	255,648
Property, plant and equipment
Property, plant and equipment	1,844,569	1,799,161
Accumulated depreciation	(655,767)	(604,145)
Net property, plant and equipment	1,188,802	1,195,016
Construction work-in-progress	35,857	37,742
Total property, plant and equipment, net	1,224,659	1,232,758

Equity investment in investee	227,169	98,204
Other assets	7,651	2,642
Prepayments	19,418	16,766
Restricted cash, less current portion	24,210	40,865
Regulatory assets and liabilities - deferred taxes, net	58,545	61,427
Long-term receivable	5,904	895
Other deferred charges	42,517	44,115
Total assets	$ 1,768,125	$ 1,753,320
	=======	=======

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

(Continued on next page)

CLECO CORPORATION

CONSOLIDATED BALANCE SHEETS
(Continued)

	At December 31,
	2001	2000
Liabilities and shareholders' equity
Current liabilities
Short-term debt	$ 179,555	$ 95,957
Long-term debt due within one year	30,843	30,665
Accounts payable	83,270	102,838
Retainage	6,439	8,770
Accrued payroll	1,130	1,159
Customer deposits	20,661	20,436
Taxes accrued	10,543	17,286
Interest accrued	14,660	15,177
Risk management liability	-	21,118
Other current liabilities	9,409	11,849
Total current liabilities	356,510	325,255
Deferred credits
Accumulated deferred federal and state income taxes, net	208,522	216,575
Accumulated deferred investment tax credits	22,487	24,252
Other deferred credits	45,875	48,088
Total deferred credits	276,884	288,915
Long-term debt, net	626,777	659,135
Total liabilities	1,260,171	1,273,305

Commitments and contingencies (Note 19)

Shareholders' equity
Preferred stock
Not subject to mandatory redemption	27,326	28,090
Deferred compensation related to preferred stock held by ESOP	(11,338)	(12,994)
Total preferred stock not subject to mandatory redemption	15,988	15,096
Common shareholders' equity
Common stock, $1 par value, authorized 100,000,000 shares, issued 45,063,740 shares at December 31, 2001, and 2000	45,064	45,064
Premium on capital stock	111,753	112,502
Long-term debt payable in Company's common stock	-	519
Retained earnings	337,254	308,047
Treasury stock, at cost, 102,242 and 73,072 shares at December 31, 2001, and 2000, respectively	(2,105)	(1,213)
Total common shareholders' equity	491,966	464,919
Total shareholders' equity	507,954	480,015

Total liabilities and shareholders' equity	$1,768,125	$1,753,320
	=======	=======

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,
	2001	2000	1999
	(Thousands)
Operating activities
Net income before preferred dividends	$ 70,238	$ 64,982	$ 56,766
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	61,775	56,958	51,153
Allowance for funds used during construction	(769)	(507)	(654)
Amortization of investment tax credits	(1,765)	(1,742)	(1,790)
Deferred income taxes	(6,898)	6,098	9,336
Deferred fuel costs	(4,362)	(6,255)	(1,975)
Loss on disposal of discontinued operations, net of tax	(2,555)	6,861	1,304
Extraordinary gain, net of tax	-	(2,508)	-
Gain on sale of property, plant and equipment, net	-	-	(711)
Changes in assets and liabilities, net of discontinued operations
Accounts receivable, net	21,542	(52,774)	1,908
Unbilled revenues	16,937	(18,503)	(12,078)
Fuel, material and supplies inventories	(4,953)	1,912	(2,830)
Accounts payable	(21,026)	28,490	21,118
Customer deposits	214	110	206
Long-term receivable	(5,009)	(895)	-
Taxes accrued	(8,639)	14,523	(7,948)
Interest accrued	(517)	5,543	2,295
Margin deposits	21,077	(21,159)	(498)
Risk management assets and liabilities, net	(3,866)	1,948	-
Other, net	(6,649)	(1,286)	(765)
Net cash provided by operating activities	124,775	81,796	114,837
Investing activities
Additions to property, plant and equipment	(49,371)	(113,343)	(179,226)
Allowance for funds used during construction	769	507	654
Proceeds from sale of property, plant and equipment	1,845	291	1,194
Proceeds from sale of discontinued operations	4,590	-	-
Equity investment in investee	(133,259)	(97,234)	-
Purchase of investments	-	-	(580)
Net cash used in investing activities	(175,426)	(209779)	(177,958)
Financing activities
Issuance of common stock	-	-	243
Repurchase of common stock	(3,017)	-	(3,833)
Redemption of preferred stock	-	-	(6,518)
Transfer of cash (into) from restricted accounts	25,667	21,908	(77,251)
Issuance of long-term debt	-	110,332	269,352
Retirement of long-term debt	(32,035)	(29,774)	(30,639)
Increase (decrease) in short-term debt, net	83,598	69,623	(43,383)
Dividends paid on common and preferred stock, net	(41,031)	(39,860)	(39,146)
Net cash provided by financing activities	33,182	132,229	68,825
Net increase (decrease) in cash and cash equivalents	(17,469)	4,246	5,704
Cash and cash equivalents at beginning of year	29,407	25,161	19,457
Cash and cash equivalents at end of year	$ 11,938	$ 29,407	$ 25,161
	======	======	======
Supplementary cash flow information
Interest paid (net of amount capitalized)	$ 60,353	$ 46,527	$ 30,819
	======	======	======
Income taxes paid	$ 41,261	$ 23,060	$ 24,614
	======	======	======
Supplementary noncash investing activity
Transfer of assets to joint venture, net	$ 5,156	$ -	$ -
	======	======	======
Supplementary noncash financing activity
Issuance of treasury stock	$ 2,125	$ 1,860	$ 1,545
	======	======	======

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,
	2001	2000	1999
	(Thousands)
Net income applicable to common stock	$ 68,362	$ 63,112	$ 54,756
Other comprehensive income (expense), net of tax
Transition adjustment from implementation of SFAS No. 133	(4,453)	-	-
Net unrealized gains from derivative instruments	4,453	-	-
Net other comprehensive income (expense)	-	-	-
Comprehensive income	$ 68,362	$ 63,112	$ 54,756
	======	======	======

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
	Shares	Amount	Stock	Stock	Earnings	Shares	Cost
	(Thousands, except share and per share amounts)
BALANCE JANUARY 1, 1999	45,535,508	$ 45,535	$113,871		$271,019	563,860	$ 5,734
Redemption of preferred stock			18
Repurchase of preferred stock			(62)
Incentive stock options exercised	21,600	22	217
Issuance of treasury stock			5			(125,646)	(1,545)
Treasury shares cancelled	(493,368)	(493)	(1,316)		(3,256)	(493,368)	(5,020)
Treasury shares purchased						235,342	3,833
Dividend requirements, preferred stock, net					(2,010)
Adjustment for step-by-step acquisition of subsidiary				$1,036	(2,558)
Cash dividends paid, common stock, $0.825 per share					(37,136)
Net Income					56,766
Balance, December 31, 1999	45,063,740	45,064	112,733	1,036	282,825	180,188	3,002
Redemption of preferred stock			(471)
Issuance of treasury stock			22			(79,898)	(1,329)
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	45,063,740	45,064	112,502	519	308,047	73,072	1,213
Treasury shares purchased						148,432	3,017
Issuance of treasury stock			(749)			(87,304)	(1,606)
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)
Balance, December 31, 2001	45,063,740	$ 45,064	$111,753	$ -	$337,254	102,242	$ 2,105
	======	=====	=====	=====	=====	=====	====

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Reorganization

Effective July 1, 1999, we reorganized into a holding company structure. This reorganization resulted in the current holding company (Cleco Corporation) which holds investments in the subsidiaries described in Note 2 - "Summary of Significant Accounting Policies." There was no impact on our Consolidated Financial Statements because the reorganization was accounted for similarly to a pooling of interest. Shares of preferred stock in three series that did not approve the reorganization were redeemed for $5.7 million.

On December 31, 2000, Cleco Utility Group Inc. (Utility Group) merged into Cleco Power LLC (Cleco Power). Prior to the merger, Cleco Power had nominal assets and liabilities. As a result of the merger, Cleco Power acquired all of the assets and assumed all of the liabilities and obligations of Utility Group.

Note 2 - Summary of Significant Accounting Policies

GENERAL

*	Cleco Power is an electric utility regulated by the Louisiana Public Service Commission (LPSC) which determines the rates Cleco Power can charge its customers. Cleco Power serves approximately 250,000 customers, mainly in central Louisiana.
*	Cleco Midstream Resources LLC (Midstream) owns and operates wholesale generation stations, invests in joint ventures that own and operate wholesale generation stations, owns and operate wholesale natural gas pipelines, and engages in energy marketing activities.
*	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 UTS' assets. Revenues and expenses associated with UTS are netted and shown on our Consolidated Statements of Income as loss from operations from a discontinued operation. For additional information on the selling of UTS's assets, see Note 18 - "Discontinued Operations."

The preparation of financial statements in conformity with generally accepted accounting principles 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 revenues 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 and its majority-owned subsidiaries after elimination of intercompany accounts and transactions.

RECLASSIFICATIONS

Certain reclassifications have been made to the 1999 and 2000 consolidated financial statements to conform to the presentation used in the 2001 consolidated financial statements. These reclassifications had no effect on net income applicable to common stock or total common shareholders' equity.

Regulation

Cleco Power maintains its accounts in accordance with the Uniform System of Accounts prescribed for electric utilities by the Federal Energy Regulatory Commission (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 the unresolved issues in the plan. The staff is also to monitor surrounding areas and if any commence retail access, they are to 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, Cleco Power has recorded regulatory assets and liabilities, primarily for the effects of income taxes, as a result of past 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 in the future, pursuant to SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71." At December 31, 2001, Cleco Power had recorded $58.6 million of regulatory assets, net of regulatory liabilities, 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 differences occur over the lives of relatively long-lived assets, up to 30 years or more. Under the current regulatory and competitive environment, Cleco Power believes these regulatory assets will be fully recoverable; however, if in the future, as a result of regulatory changes or increased competition, Cleco Power's ability to recover these regulatory assets would not be probable, then to the extent that such regulatory assets were determined not to be recoverable, Cleco Power would be required to write-off or write-down such assets.

Property, Plant and Equipment

Property, plant and equipment consist primarily of regulated generation assets, along with generation stations, natural gas pipelines and work-in-progress on nonregulated projects. Regulated assets, utilized for retail operations and electric transmission and distribution properties, 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.

Cleco Power's cost of improvements to property, plant and equipment is capitalized. Expenditures for repairs are expensed. Upon retirement or disposition, the cost of depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. Annual depreciation provisions expressed as a percentage of average depreciable property were 3.27% for 2001, 3.27% for 2000, and 3.28% for 1999.

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

	Years
Regulated Utility Plant	32-49
Nonregulated Utility Plant	30-40
Oil & Gas Pipeline	3-50
Other	3-7

Property, plant and equipment consists of:

	2001	2000
	(Thousands)
Regulated utility plant	$ 1,583,920	$ 1,548,990
Nonregulated utility plant	224,795	218,565
Oil and gas pipeline	28,687	26,583
Other	7,167	5,023
Total property, plant and equipment	$ 1,844,569	$ 1,799,161
	=========	========

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.

Cleco Power	At December 31,
Cleco Power	2001	2000
	(Thousands)
Plant acquisition adjustment	$ 5,359	$ 5,379
Less accumulated amortization	1,203	951
Total plant acquisition adjustment	$ 4,156	$ 4,428
	======	======

CASH EQUIVALENTS

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

RESTRICTED CASH

Restricted cash represents cash to be used for specific purposes. Approximately $15.0 million in restricted cash in 2001 was replaced with a standby letter of credit to be maintained as security for the performance of certain obligations by Cleco Evangeline LLC (Evangeline) in regard to the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling Agreement). At December 31, 2001, $29.7 million of cash remains restricted under the Evangeline bond indenture until certain of its provisions are met.

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 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 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.

REVENUES AND FUEL COSTS

Utility Revenues. Revenues from sales of electricity are 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 fuel adjustment clauses, 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 revenues 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. Effective December 31, 2001, Cleco Power no longer accrues fuel revenues as a component of unbilled revenues, which decreased the unbilled receivable and deferred fuel asset as of December 31, 2001.

Energy Marketing and Other Revenues. Revenues are recognized at the time products or services are provided to and accepted by customers.

Tolling Revenues. Cleco considers the Evangeline Tolling Agreement to be an operating lease as defined by SFAS No. 13, "Accounting for Leases" and SFAS No. 29, "Determining Contingent Rentals" because of Williams Energy Marketing and Trading Company's (Williams) ability to control the use of the plant, among other criteria, through 2020. The Evangeline Tolling Agreement contains a monthly shaping factor which provides for a greater portion of annual revenue to be received by Cleco during the summer months, which is designed to coincide with the physical usage of the plant. SFAS No. 13 generally requires lessors to recognize revenue using a straight-line approach unless another rational allocation of the revenue is more representative of the pattern in which the leased property is employed. Cleco believes that the recognition of revenue pursuant to the monthly shaping factor for several provisions contained within the Evangeline Tolling Agreement is a rational allocation method, which better reflects the expected usage of the plant. Other provisions are recognized as revenue using a straight-line approach. Certain provisions of the Evangeline Tolling Agreement, 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. See Note 14 - "Operating Lease" for more information.

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, for 2001 was 13.65% on a pretax basis (8.4% net of tax), for 2000 was 13.62% on a pretax basis (8.38% net of tax), and for 1999 was 13.75% on a pretax basis (8.46% net of tax).

CAPITALIZED INTEREST

Cleco and its subsidiaries, except Cleco Power, capitalize interest costs for construction in accordance with SFAS No. 34, "Capitalization of Interest Cost." SFAS No. 34 states interest should be capitalized on assets, other than inventory, that require a period of time to construct and when interest costs are incurred by the enterprise constructing the asset. During the year ended December 31, 2001, Cleco capitalized approximately $10.1 million in interest costs compared to approximately $7.8 million during the year ended December 31, 2000.

Cleco and its subsidiaries capitalize interest costs for investments accounted for by the equity method, while the investee has activities in progress necessary to commence its planned operations, in accordance with SFAS No. 58, "Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method." See Note 13 - "Equity Investment in Investee" for more information.

RISK MANAGEMENT

The market risk inherent in Cleco's market risk-sensitive instruments and positions is the potential change arising from increases or decreases in the short-, medium- and long-term interest rates, the commodity price of electricity traded on the Into Entergy and the Cinergy markets and the commodity price of natural gas traded. Generally, Cleco Power's market risk-sensitive instruments and positions are characterized as "other than trading;" however, Cleco Power does have positions that are considered "trading" as defined by Emerging Issues Task Force (EITF) Consensus No. 98-10 (EITF 98-10). All of the positions held by Cleco Marketing & Trading LLC (Marketing & Trading) and Cleco Energy LLC (Cleco Energy), subsidiaries of Midstream, are characterized as "trading" under EITF 98-10. Positions that are considered "trading" under EITF 98-10 are marked-to-market at the end of reporting periods. The mark-to-market gains or losses are reflected in the income statement as energy marketing and tolling operations. The offsetting unrealized gain or loss is recorded on the balance sheet in other current assets or other current liabilities. Positions that are considered "other than trading" under EITF 98-10 are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.

RECENT ACCOUNTING STANDARDS

We account for derivative contracts in accordance with SFAS No. 133 as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." The body of pronouncements that determine the accounting for derivatives has been clarified by the Derivatives Implementation Group (DIG) which periodically issues conclusions on implementation. The DIG conclusions are not final until they are approved by the Financial Accounting Standards Board (FASB).

Derivative transactions should be recorded on the balance sheet as either an asset or liability at their fair market value. Changes in the fair market value must be recognized in current earnings unless the derivative meets certain criteria for hedge treatment or one of the exceptions are met. If hedge accounting criteria are met, the effective changes in the fair value of derivatives are recorded in other comprehensive income (OCI). The ineffective changes in fair market value are recorded in current earnings. The main exception applicable to our derivative contracts is the normal purchases/sales exception. If the contract is to meet customer demand and the contract is made in the normal course of business, then the changes in fair market value are not recorded in current earnings. Instead the revenue or expense is recognized when fulfillment of the contract terms or transactions has been completed.

Cleco Power has entered into various contracts for the purchase or sale of electricity and the purchase of fuel used at its generating stations in order to meet customer demand. These contracts meet the normal purchases/sales exception. Cleco Power has also entered into contracts that are marked-to-market because they are not for customer demand and do not meet hedge accounting criteria.

Midstream has two subsidiaries that engage in energy marketing and trading: Marketing & Trading and Cleco Energy.

Marketing & Trading enters into contracts for the purpose of trading, not to meet customer demand. All of its derivatives are marked-to-market because they do not meet the criteria for normal purchases/sales nor do they meet the criteria for hedge accounting.

During the first three quarters of 2001, Cleco Energy had contracts which qualified for hedge accounting treatment under the criteria for a cash flow hedge. The contracts met cash flow hedge criteria because they were entered into in order to hedge against fluctuations in the price of the natural gas it marketed to wholesale customers. On January 1, 2001, a transition adjustment was recorded in OCI which reduced equity by $4.5 million. During the year ended December 31, 2001, the transition adjustment has been reduced to zero primarily due to delivery of underlying natural gas and the assignment of certain contracts to Marketing & Trading. Subsequent to these events, hedge accounting was discontinued because the costs to meet the documentation requirements of SFAS No. 133 to qualify for hedge accounting outweighed the benefits.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Risk Management" for more information about the contracts marked-to-market.

In June 2001 the FASB issued SFAS No. 141, which established accounting and reporting standards for business combinations and supercedes Accounting Principles Board (APB) Opinion No. 16. This new standard requires that all business combinations that fall within its scope be accounted for using the purchase method and gives guidance on applying the purchase method. The effective date of the statement is for all business combinations initiated after June 30, 2001 and for all business combinations accounted for by the purchase method for which the date of acquisition is July 1, 2001 or later. The implementation of this standard had no impact on Cleco's financial statements.

In June 2001 FASB issued SFAS No. 142, which established accounting and reporting for intangible assets acquired individually or with a group of other assets (but not those acquired in a business combination). This new standard requires that any acquired intangible asset that falls within its scope be amortized over its useful life if it has a finite useful life, or not amortized if the intangible asset has an indefinite life (such as goodwill). This statement also requires impairment tests for all intangible assets. The effective date of the statement is for fiscal years beginning after December 15, 2001. Cleco does not expect implementation of this pronouncement to have a material effect on its financial statements.

In July 2001 FASB issued SFAS No. 143, which requires the recognition of a liability for an asset's retirement obligation in the period in which the event which triggers the liability occurs. When the liability is initially recorded, the cost of the related asset is increased. The capitalized cost of the retirement liability is 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. Cleco has not yet determined the effect of adopting this statement on its financial statements.

In October 2001 FASB issued SFAS No. 144, which established accounting and reporting standards for the impairment or disposal of long-lived assets and supercedes SFAS No. 121 and the accounting and reporting provisions of APB Opinion No. 30. This new standard requires that companies test certain long-lived assets for impairment and write down assets that are considered impaired. SFAS No. 144 differs from SFAS No. 121 by clarifying impairment testing and excluding goodwill. The effective date of the statement is for fiscal years beginning after December 15, 2001. Cleco has not yet determined the effect of adopting this statement on its financial statements.

EARNINGS PER AVERAGE COMMON SHARE

Earnings per average common share (EPS) is computed using the weighted average number of shares of common stock outstanding during the year. EPS is reported for the years 2001, 2000 and 1999 to reflect Cleco's adoption of SFAS No. 128, "Earnings per Share." 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 following table is a reconciliation of the components in the calculation of basic and diluted earnings per share.

Calculation of Earnings Per Share

	For the year ended December 31, (Thousands, except per share amounts)
	2001			2000			1999
	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	$72,273			$ 69,335			$ 58,070
Less: preferred dividend requirements, net	1,876			1,870			2,010

Basic EPS
Income from continuing operations available for common shareholders	$70,397	45,001	$1.56	$ 67,465	44,948	$ 1.50	$ 56,060	45,002	$ 1.25
	====		===	====		===	====		===
Effect of Dilutive Securities
Stock option grants		213			80
Convertible ESOP preferred stock	1,814	2,550		1,830	2,626		1,723	2,694

Diluted EPS
Income from continuing operations available to common shareholders plus assumed conversions	$72,211	47,764	$1.51	$ 69,295	47,654	$ 1.46	$ 57,783	47,696	$ 1.21
	====		===	====		===	====		===

The following outstanding options to purchase shares of common stock were not included in the computation of diluted EPS because the options' exercise price were greater than the average market price of the common shares during the period:

	2001: 10,000 options at $22.6875 and 3,334 options at $23.25.
	2000: 54,000 options at $21.96 and 54,000 options at $20.62.
	1999: None antidilutive.

Note 3 - Jointly Owned Generating Units

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

	At December 31, 2001
	Rodemacher	Dolet Hills
	Unit #2	Unit #1
	(Dollar amounts in thousands)
Ownership	30%	50%
Utility plant in service	$85,595	$275,191
Accumulated depreciation	$49,442	$127,003
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, 2001, and 2000, for cash and cash equivalents, accounts receivable, accounts payable and short-term debt approximate fair value because of their short-term nature. The fair value of Cleco's long-term debt and nonconvertible preferred stock is estimated based upon the quoted market price for the same or similar issues or by a discounted present value analysis of future cash flows using current rates obtained by Cleco 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, 2001, and 2000, with proceeds from the sale of the common stock used to repay the principal balance of Cleco'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 based on market conditions and observed volatility. These estimates are subjective in nature and involve uncertainties. Therefore, actual results may differ from these estimates.

Fair Value of Financial Instruments

	At December 31,
	2001		2000
	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
	(Thousands)
Financial instruments not marked-to-market
Long-term debt	$658,422	$729,684	$ 690,622	$ 718,610
Preferred stock not subject to mandatory redemption	$ 15,988	$ 43,778	$ 15,096	$ 56,867

	Original Value	Estimated Fair Value	Original Value	Estimated Fair Value
Financial instruments marked-to-market
Energy Market Positions
Assets	$168,776	$161,668	$ 39,205	$ 39,901
Liabilities	$165,337	$158,436	$ 77,523	$ 78,668

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

Note 5 - Debt

Cleco and its subsidiaries have revolving credit facilities totaling $346.8 million, consisting of five separate facilities. Compensating balances are not required for any of the facilities.

The Company has two credit facilities totaling $200 million. The first facility is a $120 million facility which provides for borrowings at interest rates based on either competitive bid, prime rate, or the London Interbank Offered Rate and will expire in June 2002. The commitment fees for this facility are based upon Cleco's lowest secured debt ratings and are currently 0.125%. The second facility is an $80 million, three-year facility that provides for borrowings at interest rates established by competitive bid and will expire in August 2002. The commitment fees for this facility are based upon Cleco's lowest secured debt ratings and are currently 0.15%. Both facilities provide support for the issuance of commercial paper. At December 31, 2001, there was approximately $37.0 million in commercial paper outstanding under the facilities. Also, at December 31, 2001, there was an outstanding draw under the $120 million facility in the amount of $77 million. The two credit facilities are uncollateralized. Off-balance sheet commitments issued by Cleco to third parties for certain types of transactions between those parties and Cleco's affiliates, other than Cleco Power, reduce the amount of the facilities available to Cleco by an amount equal to the stated or determinable amount of the primary obligation. In addition, certain indebtedness incurred by Cleco outside of the facilities reduces the amount of the facilities available to Cleco. The amount of off-balance sheet commitments provided by Cleco and other indebtedness reducing the amount of the facilities available to be utilized was $70.1 million at December 31, 2001 and $60.9 million at December 31, 2000. For more information about the commitments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Cash Generation and Cash Requirements - Off-balance Sheet Commitments."

Cleco Power has one credit facility for $100 million. This facility provides for uncollateralized borrowings at prevailing interest rates and is scheduled to expire in June 2002. The facility provides support for the issuance of commercial paper. At December 31, 2001, there was approximately $63.7 million in commercial paper outstanding under the facility. Interest rates are established by competitive bid. Commitment fees are based upon Cleco Power's lowest secured debt rating and are currently 0.10%.

On June 25, 2001, Midstream, an unregulated consolidated subsidiary of Cleco, became a party to a $36.8 million uncollateralized line of credit. The 364-day facility is scheduled to terminate in June 2002. At December 31, 2001, there was no balance outstanding under this credit facility.

Cleco Energy has one credit facility for $10 million. This facility provides for borrowings at prevailing interest rates and will expire in June 2005. At December 31, 2001, there was approximately $9.0 million outstanding under the facility. Commitment fees for the facility are based on a percentage of the unused line of credit. The facility is collateralized by the assets of Cleco Energy.

Total indebtedness as of December 31, 2001, and 2000, was as follows:

	At December 31,
	2001	2000
	(Thousands)
Commercial paper, net	$ 100,675	$ 95,617
Short-term bank loans	78,880	340
Total short-term debt	$ 179,555	$ 95,957
	=======	======

First mortgage bonds
Series X, 9.5%, due 2005	$ 60,000	$ 60,000
Pollution control revenue bonds, fixed rate of 5.875%, due 2029, callable after September 1, 2009	61,260	61,260
Long-term bank loans	7,361	9,741
Medium-term notes
7.55% due 2004, callable at 100%, 2002	15,000	15,000
7.50% due 2004, callable at 100%, 2002	10,000	10,000
7.00% due 2003	10,000	10,000
6.55%, due 2003	15,000	15,000
6.33%, due 2002	25,000	25,000
5.78%, due 2001	-	10,000
6.20%, due 2006	15,000	15,000
6.42%, due 2001	-	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	215,000	240,000

Senior secured bonds, 8.82%, due 2019	214,228	218,600
Senior notes, 8.75%, due 2005	100,000	100,000

Other long-term debt	573	1,061
Gross amount of long-term debt	658,422	690,662
Less:
Amount due within one year	(30,843)	(30,665)
Unamortized premium and discount, net	(802)	(862)

Total long-term debt, net	$ 626,777	$ 659,135
	=======	=======

The amounts payable under long-term debt agreements for each year through 2006 and thereafter are listed below:

	2002	2003	2004	2005	2006	Thereafter
	(Thousands)
Amounts payable under long-term debt agreements	$30,843	$32,875	$31,585	$170,040	$47,104	$345,975
	=====	=====	=====	======	=====	======

The weighted average interest rate on short-term debt at December 31, 2001, was 4.2% compared to 7.7% at December 31, 2000.

The first mortgage bonds are collateralized by the LPSC-jurisdictional property, plant and equipment owned by Cleco Power. In the various parishes 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 generating station assets held by Evangeline.

On May 25, 2000, Cleco sold $100 million aggregate principal amount of its five-year senior notes. These notes bear interest at 8.75% per year and mature on June 1, 2005, and are uncollateralized. Approximately $50 million of the proceeds from the sale of the notes were used to pay down commercial paper financing, and the remainder was used to invest in joint ventures.

On March 1, 2001, The Bank of New York issued a $15 million standby letter of credit on behalf of Evangeline to Williams pursuant to the Evangeline Tolling Agreement between Williams and Evangeline that expires July 2020. It is renewable annually, and no compensating balances are required. Letters of credit are issued under Cleco's revolving credit agreements.

Note 6 - Common Stock

In association with incentive compensation plans in effect during the three-year period ended December 31, 2001, certain officers and key employees of Cleco and its subsidiaries were awarded shares of restricted Company 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, 2001, the number of shares of restricted stock previously granted for which restrictions had not lapsed totaled 302,450 shares.

Cleco records no charge to expense with respect to the granting of options at fair market value or above to employees or directors. Options may be granted to certain officers, key employees or directors of Cleco or its subsidiaries. During 2001 Cleco granted basic non-qualified 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 2001 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, "Accounting for Stock Issued to Employees," Cleco has recognized no compensation expense for stock options granted.

Changes in incentive shares for the three-year period ended December 31, 2001, were as follows:

	Incentive Share
	Option Price per Share		Unexercised Option Shares	Available for Future Grants
Balance, January 1, 1999			46,606	1,353,434

Options exercised	$	8.3900	(21,600)	-
Options granted (directors)	$	15.9375	15,556	(15,556)
Options granted - basic (employees)	$	16.1250	332,600	(332,600)
Options granted - premium (employees)	$ $	19.205 to 21.580	742,800	(742,800)
Restricted stock granted			-	(98,148)
Restricted stock forfeited			-	1,104

Balance, December 31, 1999			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
			======	======

Had the compensation cost for Cleco's stock-based compensation plans been determined consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," Cleco's net income and net income per common share would approximate the pro forma amounts below:

	For the year ended December 31,
	2001		2000		1999
	____________________________________________________________________
	As Reported	Pro Forma	As Reported	Pro Forma	As Reported	Pro Forma
	____________________________________________________________________
	(Thousands, except per share amounts)
SFAS No. 123 expense	$ -	$ 2,156	$ -	$ 311	$ -	$ 1,036
Estimated reduction in income tax for SFAS No. 123 expense	-	(744)		(103)		(342)
Net income applicable to common stock	$ 68,362	$ 66,950	$63,112	$62,904	$54,756	$54,062
Net income per basic common share	$ 1.52	$ 1.49	$ 1.41	$ 1.40	$ 1.22	$ 1.20

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

	For the year ended December 31,
	2001	2000	1999
Expected term (in years)	5.85	5.26	6.31
Volatility	15.13%	14.22%	12.94%
Expected dividend yield	4.20%	4.75%	5.11%
Risk-free interest rate	4.87%	6.32%	5.94%
Weighted average fair value (Black-Scholes value)	$2.82	$ 3.01	$ 2.15

The effects of applying SFAS No. 123 in this pro forma disclosure are not necessarily indicative of future amounts. SFAS No. 123 does not apply to awards prior to 1995, and Cleco anticipates making awards in the future under its stock-based compensation plans.

The following table summarizes information about employee and director stock options outstanding at December 31, 2001:

Options Outstanding
Range of Exercise Price	Number Outstanding	Number Exercisable at 12/31/2001	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life
_____________________________________________________________________________________
$15.938	23,338	23,338	$15.938	6.33
$15.938	10,000	10,000	$15.938	7.38
$16.125	289,400	-	$16.125	7.56
$19.205 to $21.58	572,800	-	$20.380	7.56
$15.938	556	556	$15.938	7.96
$17.315	28,000	20,000	$17.315	8.33
$20.62 to $23.17	54,000	-	$21.883	8.33
$18.44	37,800	-	$18.440	8.58
$21.96 to $24.675	54,000	-	$23.305	8.58
$22.6875	10,000	10,000	$22.688	9.33
$23.25	3,334	3,334	$23.250	9.42
$22.25	240,000	-	$22.250	9.58
$20.375	9,000	-	$20.375	9.76

Various debt agreements contain covenants that restrict the amount of retained earnings that may be distributed as dividends to common shareholders. The most restrictive covenant requires that common shareholders' equity be not less than 30% of total capitalization, including short-term debt. At December 31, 2001, approximately $68.7 million of retained earnings was not restricted.

Shareholder Rights Plan

In July 2000 Cleco'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's common stock, the rights would, in essence, allow the holder to purchase Cleco's common stock at half the current fair market value. Cleco 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's board of directors adopted the Cleco Corporation Employee Stock Purchase Plan (ESPP). Shareholders approved the plan in April 2000. The ESPP provides the opportunity for employees to purchase shares of Cleco's common stock at a discounted price. Cleco implemented the ESPP effective October 1, 2000.

Regular, full-time and part-time employees of Cleco and its participating affiliates, except officers and general managers and employees who own 5% or more of Cleco'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 will be established in connection with the ESPP. At the end of each offering period, payroll deductions are automatically applied to the purchase of shares of common stock. The number of shares of common stock purchased is determined by dividing each participant's payroll deductions during the offering period by the option price of a share of common stock.

A maximum of 684,000 shares of common stock may be purchased under the ESPP, subject to adjustment for changes in the capitalization of Cleco. The Compensation Committee of Cleco'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 subject to the ESPP.

Stock Split

On April 27, 2001, Cleco shareholders approved a two-for-one stock split of Cleco's common stock. As a result of the stock split, Cleco'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's common stock was effective for shareholders of record at the close of business on May 7, 2001. After the stock split, Cleco had approximately 45,000,000 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.

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 debtholder 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. 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 extraordinary gain, net of income tax, of approximately $2.5 million.

Note 8 - Preferred Stock

Within the Employee Stock Ownership Plan (ESOP), each share of Cleco 8.125% preferred stock is convertible into 9.6 shares of Cleco 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 amount shown in the consolidated financial statements for preferred dividend requirements in 2001, 2000 and 1999 has been reduced by $326,000, $391,000 and $435,000, respectively, to reflect the benefit of the income tax deduction for dividend requirements on unallocated shares held by the ESOP.

Upon involuntary liquidation, 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 Jan. 1, 1999	Change	Balance Dec. 31, 1999	Change	Balance Dec. 31, 2000	Change	Balance Dec. 31, 2001
	(Thousands, except share amounts)
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	28,689	$ (838)	27,851	$ (790)	27,061	$ (764)	26,297
	$ 29,718	$ (838)	$ 28,880	$ (790)	$ 28,090	$ (764)	$ 27,326
	=====	====	=====	====	=====	====	=====
Subject To Mandatory Redemption 4.50%, Series of 1955	$ 280	$(280)	$ -	$ -	$ -	$ -	$ -
4.65%, Series of 1964	2,800	(2,800)	-	-	-	-	-
4.75%, Series of 1965	2,600	(2,600)	-	-	-	-	-
	$ 5,680	$(5,680)	$ -	$ -	$ -	$ -	$ -
	=====	====	=====	====	=====	====	=====
Deferred compensation related to convertible preferred stock held by the ESOP	$ (16,923)	$ 1,932	$ (14,991)	$ 1,997	$ (12,994)	$ 1,656	$ (11,338)
	=====	====	=====	====	=====	====	=====
Cumulative Preferred Stock, $100 par value Number of shares Authorized	1,406,000	(54,000)	1,352,000	-	1,352,000	-	1,352,000
Issued and outstanding	353,978	(65,174)	288,804	(7,904)	280,900	(7,640)	273,260
	=====	====	=====	====	=====	====	=====
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's option, subject to 30 days' prior written notice to holders. The convertible preferred stock is redeemable at any time at Cleco's option. If Cleco were to elect to redeem the convertible preferred stock, shareholders may 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. Cleco's policy is to fund contributions to the employee pension plan based 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, 2001. Cleco Power is considered the plan sponsor, and Cleco Support Group LLC is considered the plan administrator.

Cleco's retirees and their dependents are eligible to receive health, dental and life insurance benefits (other benefits). Cleco 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, 2001, and 2000, are presented in the following table.

	Pension Benefits		Other Benefits
	2001	2000	2001	2000
	(Thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$ 129,611	$ 129,970	$ 18,213	$ 16,194
Service cost	3,932	3,825	1,076	848
Interest cost	10,697	9,706	1,484	1,321
Plan participants' contributions	-	-	518	454
Amendments	1,629	-	-	-
Actuarial (gain)/loss	23,742	(6,076)	2,081	362
Expenses paid	(1,202)	(1,212)	-	-
Benefits paid	(7,298)	(6,602)	(1,084)	(966)
Benefit obligation at end of year	161,111	129,611	22,288	18,213

Change in plan assets
Fair value of plan assets at beginning of year	194,834	184,613	-	-
Actual return on plan assets	5,616	18,035	-	-
Expenses paid	(7,298)	(6,602)	-	-
Benefits paid	(1,202)	(1,212)	-	-
Fair value of plan assets at end of year	191,950	194,834	-	-

Funded status	30,839	65,223	(22,288)	(18,213)
Unrecognized net actuarial (gain)	(23,194)	(60,375)	(329)	(2,646)
Unrecognized transition obligation/(asset)	(2,673)	(3,990)	5,646	6,160
Prior service cost	12,368	11,806	-	-
Prepaid/(accrued) benefit cost	$ 17,340	$ 12,664	$ (16,971)	$ (14,699)
	======	======	======	======

Employee pension plan assets are invested in Cleco'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 2001, 2000 and 1999 are as follows, along with assumptions used:

	Pension Benefits			Other Benefits
	2001	2000	1999	2001	2000	1999
	(Thousands)
Components of periodic benefit costs
Service cost	$ 3,932	$ 3,825	$ 4,353	$ 1,076	$ 848	$ 661
Interest cost	10,697	9,706	9,198	1,484	1,321	1,099
Expected return on plan assets	(17,404)	(15,912)	(14,267)	-	-	-
Amortization of transition obligation(asset)	(1,650)	(1,318)	(1,317)	513	513	513
Prior period service cost amortization	1,067	969	969	-	-	-
Net (gain)loss	(1,318)	(1,194)	-	(2)	5	-
Net periodic benefit cost/(income)	$ (4,676)	$ (3,924)	$ (1,064)	$ 3,071	$ 2,687	$ 2,273
	=====	=====	=====	=====	====	====

	Pension Benefits			Other Benefits
	2001	2000	1999	2001	2000	1999
Weighted-average assumptions as of December 31:
Discount rate	7.25%	8.00%	7.50%	7.25%	8.00%	7.50%
Expected return on plan assets	9.50%	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, 2001, and 2000, the pension plan held 28,292 shares of Cleco Corporation common stock, after adjustment for the two-for-one stock split. None of the plan participants' future annual benefits are covered by insurance contracts.

The assumed health care cost trend rate used to measure the expected cost of other benefits was 9.0% in 2001, 8.0% in 2000, and 8.5% in 1999, declining to 4.4% by 2010 and remaining at 4.4% thereafter. The initial health care cost trend rate was reduced from 8.5% in 1999 to 8.0% in 2000, which resulted in an unrecognized gain. The increase to 9.0% in 2001 significantly reduced the gain. 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	$ 216	$ (216)
Effect on post-retirement benefit obligation	$ 1,494	$ (1,548)

Most employees are eligible to participate in a savings and investment plan (401(k) Plan). Cleco 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, 2001, and 2000, the ESOP had allocated to employees 163,487 and 152,189 shares, respectively.

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

	For the year ended December 31,
	2001	2000	1999
	(Thousands)
401(k) Plan expense	$ 803	$ 1,061	$ 1,108
Dividend requirements to ESOP on convertible preferred stock	$ 2,155	$ 2,231	$ 2,283
Interest incurred by ESOP on its indebtedness	$ 914	$ 1,109	$ 1,296
Company contributions to ESOP	$ 520	$ 1,391	$ 1,513

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,
	2001		2000		1999
	(Thousands, except for %)
	Amount	%	Amount	%	Amount	%
Book income before tax	$110,629	100.0	$104,296	100.0	$ 85,836	100.0
Tax at statutory rate on book income before tax	38,720	35.0	36,504	35.0	30,043	35.0
Increase (decrease):
Tax effect of AFUDC	(645)	(0.6)	(381)	(0.4)	(261)	(0.3)
Amortization of investment tax credits	(1,765)	(1.6)	(1,742)	(1.7)	(1,790)	(2.1)
Tax effect of prior-year tax benefits not deferred	797	0.7	988	0.9	1,119	1.3
AFUDC gross up - SFAS No. 109	(1,807)	(1.6)	(1,732)	(1.6)	(1,548)	(1.8)
Other, net	(673)	(0.6)	(2,262)	(2.1)	(1,891)	(2.2)
Total federal income tax expense	34,627	31.3	31,375	30.1	25,672	29.9
Current and deferred state income tax expense, net of federal benefit for state income tax expense	3,729	3.4	3,586	3.4	2,094	2.4
Total federal and state income tax expense	$ 38,356	34.7	$ 34,961	33.5	$ 27,766	32.3
	=====	===	=====	===	=====	===

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

	2001	2000	1999
	(Thousands)
Current federal income tax expense	$ 40,448	$ 26,381	$ 17,967
Deferred federal income tax expense	(5,903)	4,960	8,457
Amortization of accumulated deferred investment tax credits	(1,765)	(1,742)	(1,790)
Total federal income tax expense	32,780	29,599	24,634
Current state income tax expense	6,571	4,224	2,253
Deferred state income tax expense	(995)	1,138	879
Total state income tax expense	5,576	5,362	3,132
Total federal and state income tax expense	$ 38,356	$ 34,961	$ 27,766
	======	======	======
Discontinued operation
Income tax expense from loss from operations
Federal current	$ -	$ (2,344)	$ (565)
Federal deferred	-	(575)	1
State current and deferred	-	(471)	(98)
Total tax expense from loss from discontinued operation	$ -	$ (3,390)	$ (662)
	======	======	======
Income tax expense from loss on disposal of segment
Federal current	$ (2,624)	$ -	$ -
Federal deferred	1,522	(825)	-
State current	(610)	-	-
State deferred	437	(83)	-
Total tax expense from loss on disposal of segment	$ (1,275)	$ (908)	$ -
	======	======	======
Income tax expense from gain on extraordinary item
Federal current	$ -	$ 1,408	$ -
Total federal and state income tax expenses	$ 37,081	$ 32,071	$ 27,104
	======	======	======

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2001, and 2000, was comprised of the tax effect of the following:

	2001		2000
	Current	Non Current	Current	Non Current
	(Thousands)
Depreciation and property basis differences	$ -	$ (156,382)	$ -	$ (162,920)
Allowance for funds used during construction	-	(30,018)	-	(28,756)
Investment tax credits	-	15,196	-	16,259
SFAS No. 109 adjustments	-	(40,621)	-	(44,258)
Post retirement benefits other than pension	3,802	3,661	2,698	3,100
Other	447	(358)	266	-
Accumulated deferred federal and state income taxes	$ 4,249	$ (208,522)	$ 2,964	$ (216,575)
	=====	=======	=====	=======

Management considers it more likely than not that all deferred tax assets net of deferred tax liabilities 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, 2001, and 2000, were $58.5 million and $61.4 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

========================================================================
2001 (Thousands)	Cleco Power	Midstream	UTS	Other	Unallocated Items, Reclassifications & Eliminations	Consolidated

Revenues
Retail electric operations	$ 623,062	$ -	$ -	$ -	$ -	$ 623,062
Energy marketing operations	31,212	404,584	-	-	-	435,796
Other operations	-	1,461	-	100	-	1,561
Customer credits	(1,800)	-	-	-	-	(1,800)
Intersegment revenues	3,530	14,030	-	70,762	(88,322)	-
Total operating revenue	$ 656,004	$ 420,075	$ -	$ 70,862	$ (88,322)	$1,058,619
	======	======	=====	======	======	======

Depreciation expense	$ 50,594	$ 9,188	$ -	$ 464	$ -	$ 60,246
Interest charges	$ 26,819	$ 21,055	$ -	$ 330	$ -	$ 48,204
Segment profit from continuing operations	$ 90,427	$ 23,188	$ -	$ 49,805	$ (52,791)	$ 110,629
Loss on disposal of segment, net	-	-	(2,035)	-	-	(2,035)
Segment profit (loss) ⁽¹⁾	$ 90,427	$ 23,188	$ (2,035)	$ 49,805	$ (52,791)	$ 108,594
	======	======	=====	======	======	======
Segment assets	$1,185,224	$ 556,305	$ 2,517	$ 480,076	$ (455,997)	$1,768,125

	Segment Profit	$ 108,594
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	(38,356)
	Preferred dividends	(1,876)
		$ 68,362
		======

========================================================================
2000 (Thousands)
Revenues
Retail electric operations	$ 619,528	$ -	$ -	$ -	$ -	$ 619,528
Energy marketing operations	18,078	183,166	-	-	-	201,244
Other operations	-	403	-	73	-	476
Customer credits	(1,233)	-	-	-	-	(1,233)
Intersegment revenues	9,256	37,667		-	(46,923)	-
Total operating revenue	$ 645,629	$ 221,236	$ -	$ 73	$ (46,923)	$ 820,015
	======	======	=====	======	======	======

Depreciation expense	$ 49,787	$ 5,952	$ -	$ 101	$ -	$ 55,840
Interest charges	$ 28,722	$ 13,469	$ -	$ 7,114	$ -	$ 49,305
Segment profit from continuing operations	$ 90,855	$ 15,221	$ -	$ 57,630	$ (59,410)	$ 104,296
Loss on disposal of segment, net	-	-	(6,861)	-	-	(6,861)
Extraordinary gain, net	-	2,508	-	-	-	2,508
Segment profit (loss) ⁽¹⁾	$ 90,855	$ 17,729	$ (6,861)	$ 57,630	$ (59,410)	$ 99,943
	======	======	=====	======	======	======
Segment assets	$1,212,443	$ 484,213	$ 8,790	$ 427,581	$ (379,707)	$1,753,320

	Segment Profit	$ 99,943
^{(1) Reconciliation of segment profit to consolidated profit}	Unallocated items
	Income taxes	(34,961)
	Preferred dividends	(1,870)
		$ 63,112
		======


========================================================================
1999 (Thousands)	Cleco Power	Midstream	UTS	Other	Unallocated Items, Reclassifications & Eliminations	Consolidated

Revenues
Retail electric operations	$ 508,790	$ -	$ -	$ -	$ -	$ 508,790
Energy marketing operations	238,082	$ 18,698	-	-	-	256,780
Other operations	-	1,641	-	-	-	1,641
Customer credits	(2,776)	-	-	-	-	(2,776)
Intersegment revenues	7,816	6,493	-	$ 43,308	$ (57,617)	-
Total operating revenues	$ 751,912	$ 26,832	$ -	$ 43,308	$ (57,617)	$ 764,435
	======	======	=====	======	======	======

Depreciation expense	$ 49,285	$ 668	$ -	$ 13	$ -	$ 49,966
Interest charges	$ 28,414	$ 862	$ -	$ 675	$ (348)	$ 29,603
Segment profit from continuing operations	$ 83,955	$ 1,603	$ -	$ 39,700	$ (39,422)	$ 85,836
Loss on disposal of segment, net	-	-	(1,304)	-	-	(1,304)
Segment profit (loss) ⁽¹⁾	$ 83,955	$ 1,603	$ (1,304)	$ 39,700	$ (39,422)	$ 84,532
	======	======	=====	======	======	======
Segment assets	$1,414,579	$ 247,021	$ 2,848	$ 263,889	$ (223,687)	$1,704,650


	Segment profit	$ 84,532
^{(1) Reconciliation of segment profit to consolidated profit}	Unallocated items
	Income taxes	(27,766)
	Preferred dividends	(2,010)
		$ 54,756
		======

Cleco's reportable segments are based on our method of internal reporting, which disaggregates its business units by major first-tier subsidiary. Cleco's reportable segments from continuing operations are Cleco Power, Midstream and Other. The reportable business segment from discontinued operations is UTS. Reportable segments were determined by applying SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." Each reportable segment engages in business activities from which it earns revenues and incurs expenses. Segment managers report at least monthly to Cleco's chief executive officer (the chief decision maker) with discrete financial information, present quarterly discrete financial information to Cleco's board of directors and meet quantitative thresholds as defined by SFAS No. 131. Cleco's chief executive officer, as well as Cleco's board of directors, primarily uses results from continuing operations as a measure to determine allocation of resources. Budgets were prepared by each reportable segment for 2002, which were presented to, and approved by, Cleco's board of directors.

In December 2000 management decided to dispose of UTS. See Note 18 - "Discontinued Operations" for more information.

The Other segment consists of costs within the parent company, costs within a shared services subsidiary, start-up costs associated with a retail services subsidiary, and revenue and expenses associated with an investment subsidiary. These subsidiaries operate within Louisiana and Delaware.

The accounting for transactions with unaffiliated third parties and among Cleco's segments are recorded and reported on an accrual basis. Significant differences among the accounting policies of the segments compared to Cleco's consolidated financial statements principally involve the classification of revenue and expense between operating and other. Management evaluates the performance of its segments and allocates resources to them based on segment profit (loss) before income taxes and preferred stock dividends. In the first six months of 1999, Midstream and UTS reported profit (loss) as other income (expense) within Cleco Power. For purposes of this note, gross amounts of revenue and expenses are reported on the appropriate line. The "Unallocated Items, Reclassifications & Eliminations" column reclassifies the items of revenue and expense recorded under the equity method to other income (expense). Material intersegment transactions occur on a regular basis.

Note 12 - Accrual of Estimated Customer Credits

Cleco's reported earnings in the year ended December 31, 2001, reflect a $1.8 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 million in 1997 and $2 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.

Of the $1.8 million accrual, $1.0 million relates to the 12 months ended September 30, 2001, cycle and was recorded as a reduction in revenue due to the nature of the customer credits. The amount of the credit for the cycle ending September 30, 2001, if any, has not yet been determined by the LPSC. The remaining $0.8 million relates to other prior refund years and was based on settlement of those years with the LPSC.

Note 13 - Equity Investment in Investees

Equity investment in investee represents Midstream's approximate $223.0 million investment in Acadia Power Partners LLC (APP), Midstream's approximate $3.4 million investment in Perryville Energy Partners LLC (PEP), and Cleco Energy's approximate $0.7 million investment in Hudson SVD LLC. For the year 2001, Cleco's share of PEP net income was $0.7 million, while no material earnings have been recorded for APP and Hudson SVD LLC

APP is a joint venture 50% owned by Midstream and 50% owned by Calpine Corporation. APP was formed in order to construct, own and operate a combined cycle, natural gas-fired power plant to be located near Eunice, Louisiana. Total construction costs of the plant to be incurred by APP are estimated to be $564 million. Cleco reports its investment in APP on the equity method of accounting as defined in APB No. 18. As of December 31, 2001, Midstream had invested $223.0 million in cash and land to APP. Midstream's member's equity as reported in the balance sheet of APP at December 31, 2001, was $210.3 million. The majority of the difference of $12.7 million between the equity investment in investee and the member's equity was the interest capitalized on funds used to contribute to APP as required by SFAS No. 58. The table below is unaudited summarized financial information for 100% of APP. No income statement information is presented because APP is in the construction phase so all costs are capitalized.

	Unaudited At December 31,
	2001	2000
	(Thousands)
Current assets	$ 16,954	$ 1,138
Construction work in progress	426,666	210,267
Total assets	$ 443,620	$ 211,405
	=======	=======
Current liabilities	$ 22,870	$ 21,751
Partners' capital	420,750	189,654
Total liabilities and partners' capital	$ 443,620	$ 211,405
	=======	=======

Cleco expects APP to obtain non recourse project financing in the third quarter of 2002 and to reimburse Cleco for a large portion of its equity investment in APP.

PEP, a joint venture 50% owned by Midstream and 50% owned by Mirant Corporation, is in the process of constructing a 725-MW, natural gas-fired power plant in Perryville, Louisiana. Total construction costs of the plant to be incurred by PEP are estimated to be $336.0 million. The Company reports its investment in PEP on the equity method of accounting as defined in APB No. 18. As of December 31, 2001, Midstream had invested $3.4 million in PEP, net of a distribution from PEP stemming from the PEP financing discussed below. Midstream's member's equity as reported in the balance sheet of PEP at December 31, 2001 was zero. The reduction of Midstream's investment in PEP and member's equity as reported on PEP's balance sheet is due to an interim medium-term nonrecourse financing that occurred in the second quarter of 2001 and a subsequent distribution from PEP to Midstream. The difference of $3.4 million between the equity investment in investee and the member's equity was the interest capitalized on funds used to contribute to PEP as required by SFAS No. 58. A 157-MW combustion turbine commenced simple-cycle operation on July 1, 2001. Full commercial operation of the 568-MW combined-cycle unit is expected for the summer of 2002. A $300 million interim construction facility at PEP was entered into on June 7, 2001. This facility is non-recourse to Midstream and Cleco. The interim facility is convertible to an eight-year mini-perm term loan by July 2002. A mini perm loan is short term financing used to pay off construction or commercial property loans, usually in four to six years.

Cleco Energy owns 50% of Hudson SVD LLC, which owns interests in several other entities that own and operate natural gas pipelines in Texas and Louisiana. Cleco reports its investment in Hudson SVD LLC on the equity method of accounting as defined in APB No. 18. 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 Lease

Under the terms of the Evangeline Tolling Agreement, until the year 2020, Williams has the right to own, dispatch and market the electricity produced by the Evangeline facility and will supply the required natural gas to the facility. Evangeline will collect a fee from Williams for operating and maintaining the Evangeline facility. The Evangeline Tolling Agreement is accounted for as an operating lease and its revenues are recognized as described Note 2 - "Summary of Significant Accounting Policies, Revenues and Fuel Costs."

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

	At December 31,
	2001	2000
	(Thousands)
Evangeline power station	$ 224,795	$ 218,564
Construction work in progress	519	7,141
Less: accumulated depreciation	11,406	4,277
Net plant	$ 213,908	$ 221,428
	========	========

The following is a schedule by years of future minimum rental payments (assumes no change to the tested capacity or heat rate of the plant) required under the Evangeline Tolling Agreement, which is in effect until July 2020.

Year ending December 31:	(Thousands)
2002	$ 50,845
2003	51,371
2004	51,905
2005	52,442
2006	52,987
Thereafter	771,512
Total future rental payments	$ 1,031,062
	========

Future rental payments have not been adjusted for contingent items such as bonuses or penalties that may change the actual amounts received from Williams under the Evangeline Tolling Agreement. For the year ending December 31, 2001, tolling rental revenues of $60.5 million were recognized, including contingent rents of approximately $4.2 million.

In June 2000 Unit #6 of the Evangeline power plant was declared in commercial operation. The other unit at the plant, Unit #7, was declared in commercial operation during July 2000. Revenues and operating expenses associated with Unit #7 prior to the July commercial operation date are reflected in construction work in progress on Cleco's Consolidated Balance Sheets. Revenues and operating expenses relating to both units are reflected on Cleco's Consolidated Statements of Income after they were declared in commercial operation.

Note 15 - Change in Accounting Estimate

Effective July 1, 2001, in accordance with APB Opinion No. 20, Evangeline changed its accounting estimates relating to depreciation. The estimated service lives for the majority of the plant assets were extended from 27 to 46 years. The change was based upon a study performed by an independent third party engineering firm. As a result of the change, net income applicable to common stock for 2001, increased $0.7 million, or $0.02 per basic share.

Note 16 - Legal Proceeding: Fuel Supply - Lignite

Cleco Power and Southwestern Electric Power Company (SWEPCO), each a 50% owner of Dolet Hills Unit 1, jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982 Cleco Power and SWEPCO entered into a lignite mining agreement (LMA) with the Dolet Hills Mining Venture (DHMV), a partnership for the mining and delivery of lignite from a portion of these reserves (Dolet Hills Mine). The LMA was to expire in 2011.

In April 1997 Cleco Power and SWEPCO filed a Federal Court Suit against DHMV and its partners, seeking to enforce various obligations of DHMV to Cleco Power and SWEPCO under the LMA, including provisions relating to the quality of the delivered lignite, pricing, and mine reclamation practices. In June 1997 DHMV filed an answer denying the allegations in the Federal Court Suit and filed a counterclaim asserting various contract-related claims against Cleco Power and SWEPCO. Cleco Power and SWEPCO denied the allegations in the counterclaims.

As a result of the counterclaims filed by DHMV in the Federal Court Suit, in August 1997 Cleco Power and SWEPCO filed a State Court Suit against the parent companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA, Inc.

In March 2000 the court in the Federal Court Suit ruled that DHMV was not in breach of certain financial covenants under the LMA and denied Cleco Power's and SWEPCO's claim to terminate the LMA on that basis. The ruling had no material adverse effect on the operations of Cleco Power and did not affect the other claims scheduled for trial. Cleco Power and SWEPCO appealed the federal court's ruling to the United States Court of Appeals for the Fifth Circuit.

On May 31, 2001, all parties to the litigation executed a definitive settlement agreement and agreed to dismiss the State Court Suit, the Federal Court Suit and the appeal pending before the Fifth Circuit. The LMA among Cleco Power, SWEPCO and DHMV was canceled as were all other operative contracts among the parties.

Contemporaneously with the execution of the settlement agreement on May 31, 2001, DHMV and Dolet Hills Lignite Company LLC (DHLC), a subsidiary of SWEPCO, entered into an Asset Purchase Agreement under the terms of which DHLC purchased the assets necessary to operate the Dolet Hills Mine and assumed certain obligations of DHMV. Cleco Power, SWEPCO and DHLC entered into a new LMA on May 31, 2001, under the terms of which DHLC assumed operations of the Dolet Hills Mine.

The LPSC issued Order Nos. U-21453, U-20925(SC) and U-22029(SC) (Subdocket G) on May 31, 2001, formally approving Cleco Power's requested ratemaking effects of the settlement.

A stipulation of dismissal was filed by the parties to the Federal Court Suit on July 19, 2001, and the judge approved the dismissal on July 25, 2001. A motion to dismiss was filed by the parties to the State Court Suit on July 19, 2001, and the judge signed the order dismissing the State Court Suit on July 30, 2001. A motion to dismiss the appeal pending in the United States Court of Appeals for the Fifth Circuit was filed on July 19, 2001, and on July 24, 2001, the Clerk of the Fifth Circuit advised that the appeal had been dismissed in light of the settlement.

Note 17 - Louisiana Department of Environmental Quality (LDEQ) Litigation

Air and water permits issued in July 2000 by the LDEQ to APP were judicially appealed by APP-related Petitioners in early August 2000. APP is constructing and will own and operate a new electric generating plant near Eunice, Louisiana. APP-related Petitioners filed their appeals to the air and water permits in the 19^th Judicial District Court in Baton Rouge, Louisiana. APP-related Petitioners asked the court to reverse the air and water permits issued by the LDEQ and allege that LDEQ's decision to issue the permits was arbitrary, capricious and procedurally inadequate. APP-related Petitioners have also asked the court to stay APP's power plant construction activities pending resolution of the litigation. APP has denied APP-related Petitioners' allegations and is vigorously defending the validity of the permits issued to it by the LDEQ. The permits could be upheld, reversed, or remanded in whole or in part. If the permits were to be reversed in material part by the court, APP may be required to cease its construction of the generating plant temporarily or permanently, depending on the nature and details of the reversal. If the court were to remand the permits, without reversing them, to the LDEQ for further proceedings, APP's continuation of construction of the generating plant may be jeopardized, depending upon the nature and details of the remand. Oral arguments on the appeal of these permits were held on February 5, 2001. In its decision issued on February 23, 2001, the court ordered the matter remanded to the LDEQ but did not vacate the permits or halt construction. On December 17, 2001, the Court signed its Order formally remanding this matter to the LDEQ, ordering LDEQ to, among other things, (1) request additional information from APP regarding alternative site analysis; (2) allow for a new public comment period and public hearing; and (3) reconsider its permit decisions in light of additional information and comments, and issue a revised basis for decision. The parties are in the process of attempting to determine if sufficient common ground exists to settle this matter. Although the ultimate outcome of this action cannot be predicted at this time, based on information currently available to Cleco, management does not believe the outcome of this action will have a material adverse effect on Cleco's financial condition or results of operations.

An air permit issued by the LDEQ in August 2000, to PEP, a joint venture in which Midstream has a 50 percent interest with Mirant Corporation, was judicially appealed by PEP-related Petitioners. Similarly, the PEP-related Petitioners judicially appealed the water permit issued by LDEQ in June 2001. PEP is constructing and will own and operate a new electric generating plant near Perryville, Louisiana. PEP-related Petitioners filed their appeals of the air and water permits in the 19^th Judicial District Court in Baton Rouge, Louisiana, alleging that the issuance of the permits violates the Louisiana Constitution, the public trustee doctrine and state and federal environmental laws. In January 2002, following a confidential settlement agreement reached between PEP and most of the PEP-related Petitioners, the Court dismissed with prejudice the judicial appeals of the air and water permits. The settlement will not have a material adverse effect on Cleco's financial condition or results of operations.

Note 18 - Discontinued Operations

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

During 2001 the $2.0 million loss on disposal of a segment, net, 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 the year ended December 31, 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, 2001, UTS had only nominal assets since receivables have been either collected or written off.

As of December 31, 2001, several contingent liabilities relating to UTS exist. 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 until April 1, 2003. The limitation does not apply to fraudulent misrepresentations. At December 31, 2001, 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,
	2001		2000		1999
	(Thousands)
Revenues	$	5,043	$	18,125	$	6,866
Loss from operations, net	$	-	$	(5,411)	$	(1,304)
Income tax benefit associated with
loss from operations	$	-	$	3,390	$	662
Loss on disposal of segment, net	$	2,035	$	1,450	$	-
Income tax benefit associated with
loss on disposal of segment	$	1,275	$	908	$	-

Note 19 - Commitments and Contingencies

Construction and investment in joint ventures expenditures for 2002 are estimated to be $162 million, excluding AFUDC, and for the five-year period ending 2006 are expected to total $663 million, excluding AFUDC. Scheduled maturities of debt and preferred stock will total approximately $30.8 million for 2002 and approximately $312.4 million for the five-year period ending 2006.

For information on legal proceedings affecting us, see Note 18 - "LDEQ Litigation."

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

Cleco Power has accrued for liabilities to third parties, employee medical benefits, storm damages and deductibles under insurance policies that it maintains on major properties, primarily generating stations and transmission substations. Consistent with regulatory treatment, annual charges to operating expense 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 five years.

Note 20 - Subsequent Event - Insured Retail Notes

On February 8, 2002, Cleco Power issued $25.0 million aggregate principal amount of its 6.125% retail notes due March 1, 2017 . The retail notes were registered under the Securities Act of 1933, as amended, pursuant to the shelf registration statement (Registration No. 333-52540) of Cleco Power. Payment of regularly scheduled principal and interest on the retail notes is insured by a financial guaranty insurance policy issued by Ambac Assurance Corporation. Cleco Power can redeem the retail notes at its option on or after March 1, 2005. Representatives of deceased beneficial owners of the retail notes have the option to redeem the retail notes, subject to certain limitations.

Note 21 - Risks and Uncertainties

Evangeline is engaged in operating and maintaining the generation assets under a tolling agreement with Williams as discussed in Note 2 - "Summary of Significant Accounting Policies." The agreement exposes Cleco to credit risk in the event of nonperformance by Williams. Additionally, in the event of nonperformance, Cleco would potentially be required to sell power in the open market, which would subject Cleco to fluctuations in market prices rather than receiving the guaranteed minimum payments due under the tolling agreement.

Note 22 - Miscellaneous Financial Information (Unaudited)

Quarterly information for Cleco for 2001 and 2000 is shown in the following table. All share and per share amounts have been adjusted to reflect the April 27, 2001 two-for-one stock split.

	______________________________________________
	2001
	______________________________________________
	(Thousands, except per share amounts)
	1st Quarter	2^ndQuarter	3rd Quarter	4th Quarter
Operating revenue	$253,111	$303,700	$306,969	$194,839
Operating income	30,128	33,689	59,396	26,327
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	0.2200	0.2200
Closing market price per share High	25.03	23.59	22.92	22.08
Low	20.36	21.25	19.48	19.60
	______________________________________________
	2000
	______________________________________________
	(Thousands, except per share amounts)
	1^st Quarter	2^nd Quarter	3^rd Quarter	4^th Quarter
Operating revenues as reported in 10-Q	$141,026	$189,003	$273,668	$233,605
Adjustments:
Operating revenue from UTS	(3,609)	(3,541)	(4,543)	(6,431)
Reclassification to/from Other income (expense)	(322)	1,159	-	-
Operating revenues adjusted	137,095	186,621	269,125	227,174
Operating income as reported in 10-Q	$ 23,103	$ 31,748	$ 59,805	$ 21,466
Adjustments:
Operating loss from UTS	660	2,407	1,794	3,289
Reclassification to/from Other income (expense)	430	2,477	16	-
Operating income adjusted	24,193	36,632	61,615	24,755
Loss from discontinued operations, net of tax	(438)	(1,599)	(1,192)	(2,182)
Loss on disposal of segment, net of tax	-	-	-	(1,450)
Extraordinary gain, net of tax	2,508	-	-	-
Net income applicable to common stock	$ 12,258	$ 16,454	$ 29,677	$ 4,725
Net income applicable to common stock before extraordinary gain	$ 9,750	$ 16,454	$ 29,677	$ 4,725
Basic net income per average common share before extraordinary gain	$ 0.22	$ 0.37	$ 0 .66	$ 0.11
Basic net income per average common share	$ 0.27	$ 0.37	$ 0.66	$ 0.11
Diluted net income per average common share before extraordinary gain	$ 0.22	$ 0.36	$ 0.63	$ 0.11
Diluted net income per average common share	$ 0.27	$ 0.36	$ 0.63	$ 0.11
Dividends paid per common share	$ 0.2075	$ 0.2125	$ 0.2125	$ 0.2125
Closing market price per share High	$ 16.97	$ 18.13	$ 23.38	$ 27.69
Low	$ 15.22	$ 16.44	$ 17.07	$ 22.32

Cleco's common stock is listed for trading on the New York and Pacific stock exchanges under the ticker symbol "CNL." Cleco's preferred stock is not listed on any stock exchange. On December 31, 2001, Cleco had 8,990 common and 115 preferred shareholders, as determined from the records of the transfer agent.

On January 25, 2002, Cleco's Board of Directors declared a quarterly dividend of 22.00 cents per share payable February 15, 2002, to common shareholders of record on February 4, 2002. Preferred dividends were also declared payable March 1, 2002, to preferred shareholders of record on February 15, 2002.

REPORT OF THE COMPANY

The Company is responsible for the preparation, integrity and objectivity of the consolidated financial statements of Cleco Corporation and subsidiary companies as well as other information contained in this Annual Report. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of the Company giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the consolidated financial statements.

The consolidated financial statements have been audited by Cleco's independent public accountants who were given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the board of directors and committees of the board. Cleco and its subsidiaries believe that representations made to the independent public accountants during their audit were valid and appropriate. The reports of independent public accountants are presented elsewhere in this report.

Cleco, together with its subsidiary companies, maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with the Company's authorization, that the consolidated financial statements are prepared in accordance with generally accepted accounting principles, and that the assets of Cleco and its subsidiaries are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures, and the careful selection, training and development of our employees.

Internal auditors regularly monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by the Company to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of Cleco or its subsidiaries, provides oversight to the financial reporting process.

Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, the Company strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.

Cleco and its subsidiaries believe that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively as of December 31, 2001.

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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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 consolidated financial statements, effective January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana
January 29, 2002, except for Note 20
as to which the date is February 8, 2002

Five-Year Selected Financial Data (Unaudited)
	2001	2000	1999	1998	1997
	(Thousands, except per share amounts and percentages)
Operating revenues (excluding intersegment revenues)
Cleco Power	$ 652,474	$ 636,373	$ 744,096	$ 515,175	$ 456,245
Cleco Midstream	406,045	183,569	20,339	-	-
Other	100	73	-	-	-
	________________________________________________________________________
Total	$ 1,058,619	$ 820,015	$ 764,435	$ 515,175	$ 456,245
	========================================
EBITDA (Earnings before interest, taxes, depreciation, and amortization)
Cleco Power	$ 161,388	$ 169,364	$ 160,823	$ 156,111	$ 154,297
Cleco Midstream	51,949	31,530	2,986	-	-
Other	(2,460)	1,919	(101)	-	-
	___________________________________________________________
Total	$ 210,877	$ 202,813	$ 163,708	$ 156,111	$ 154,297
	========================================
Net income before income taxes, discontinued operations, extraordinary
item, and preferred dividends	$ 110,629	$ 104,296	$ 85,836	$ 80,741	$ 80,272
Net income applicable to common stock	$ 68,362	$ 63,112	$ 54,756	$ 51,664	$ 50,402
Basic EPS from continuing operations	$ 1.56	$ 1.50	$ 1.25	$ 1.16	$ 1.12
Basic EPS applicable to common stock	$ 1.52	$ 1.41	$ 1.22	$ 1.15	$ 1.12
Diluted EPS from continuing operations	$ 1.51	$ 1.46	$ 1.21	$ 1.12	$ 1.09
Diluted EPS applicable to common stock	$ 1.47	$ 1.36	$ 1.18	$ 1.12	$ 1.09
Return on average common equity	14.3 %	14.0 %	12.7 %	12.4 %	12.6 %
Effective tax rate	34.7 %	33.5 %	32.3 %	33.2 %	34.5 %

Capital expenditures
Cleco Power	$ 45,642	$ 47,900	$ 51,700	$ 94,030	$ 77,525
Cleco Midstream	131,553	158,000	127,300	-	-
Other	5,435	4,677	226	-	-
	________________________________________________________________________
Total	$ 182,630	$ 210,577	$ 179,226	$ 94,030	$ 77,525
	========================================
Internal cash generation (% of capital expenditures)
Cleco Power	100.0 %	100.0 %	100.0 %	63.3 %	100.0 %
Cleco Midstream	19.2 %	15.3 %	1.6 %	- %	- %
Other	100.0 %	100.0 %	100.0 %	- %	- %
	________________________________________________________________________
Total	41.8 %	33.3 %	30.1 %	63.3 %	100.0 %
	========================================
Utility plant, net -Cleco Power
Production	$ 218,802	$ 231,108	$ 246,810	$ 264,891	$ 277,779
Transmission	$ 236,009	$ 240,256	$ 231,953	$ 226,493	$ 219,239
Distribution	$ 428,477	$ 419,737	$ 411,520	$ 406,063	$ 386,990
Other	$ 93,661	$ 90,162	$ 92,756	$ 92,832	$ 95,341

Total capitalization
Common shareholders' equity	43.36 %	40.81 %	42.50 %	54.02 %	51.60 %
Preferred stock	1.41 %	1.33 %	1.35 %	2.35 %	2.20 %
Long-term debt	55.23 %	57.86 %	56.15 %	43.63 %	46.20 %

Total assets	$ 1,768,125	$ 1,753,320	$ 1,704,650	$ 1,429,000	$ 1,361,044

Embedded cost of debt	8.08 %	8.02 %	7.89 %	6.75 %	6.76 %
Ratio of earnings to fixed charges (pre-tax)	2.68x	2.92x	3.77x	3.81x	3.74x

Total return to shareholders	(16.6)%	76.0 %	(2.5)%	11.0 %	22.9 %
Average shares outstanding for year, basic	45,000,955	44,947,718	45,002,648	44,960,326	44,919,540
Average shares outstanding for year, diluted	47,763,713	47,654,954	47,697,030	47,734,916	47,728,062
Market price per share at year-end	$ 21.97	$ 27.38	$ 16.03	$ 17.16	$ 16.19
Market capitalization at year-end	$ 987,804	$ 1,231,620	$ 719,551	$ 771,556	$ 727,237
Price-earnings ratio at year-end	14.5x	19.4x	13.1x	14.9x	14.5x
Market-to-book ratio at year-end	2.01x	2.65x	1.64x	1.82x	1.78x
Book value per share at year-end	$ 10.94	$ 10.33	$ 9.75	$ 9.45	$ 9.10
Dividends paid per common share	$ 0.87	$ 0.85	$ 0.83	$ 0.81	$ 0.79
Dividend payout ratio	57.3%	60.2 %	67.8 %	70.1 %	70.0 %
Dividend yield at year-end	4.0%	3.1 %	5.1 %	4.7 %	4.8 %

Five-Year Selected Operating Data (Unaudited)
	2001	2000	1999	1998	1997

Non-fuel recovery revenue by customer class-Cleco Power (thousands)
Residential	$ 140,547	$ 144,999	$ 139,660	$ 142,484	$ 128,002
Commercial	64,127	63,475	60,486	58,494	54,641
Industrial	52,578	54,733	51,772	49,344	47,675
Other	29,641	27,692	24,427	23,698	23,943
Unbilled	1,012	3,588	3,795	(136)	(466)
	_______________________________________________________________
Total	$ 287,905	$ 294,487	$ 280,140	$ 273,884	$ 253,795
	===================================
Sales of Electricity On-System Customers-Cleco Power (millions of kilowatt-hours)
Residential	3,201	3,296	3,147	3,215	2,852
Commercial	1,655	1,636	1,573	1,534	1,401
Industrial	2,640	2,883	2,717	2,529	2,468
Other	979	912	924	959	845
Unbilled	34	162	105	(7)	(23)
	_______________________________________________________________
Total	8,509	8,889	8,466	8,230	7,543
	===================================
Average retail customers by class-Cleco Power
Residential	219,809	217,538	213,860	209,605	200,216
Commercial	30,634	30,136	29,513	28,902	27,579
Industrial	750	767	786	790	787
Other - Including unbilled	6,178	6,121	5,976	5,876	5,711
	_______________________________________________________________
Total	257,371	254,562	250,135	245,173	234,293
	===================================
Average revenue per kWh sold-Cleco Power
Residential	$ 0.0814	$ 0.0778	$ 0.0682	$ 0.0679	$ 0.0684
Commercial	0.0764	0.0722	0.0621	0.0615	0.0626
Industrial	0.0553	0.0502	0.0421	0.0416	0.0423
Other	0.0583	0.0672	0.0546	0.0489	0.0539
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Total composite	$ 0.0696	$ 0.0665	$ 0.0570	$ 0.0564	$ 0.0566
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Average annual kWh use per residential customer-Cleco Power	14,563	15,151	14,715	15,338	14,245
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Average annual revenue per residential customer-Cleco Power	$ 1,186	$ 1,178	$ 1,003	$ 1,041	$ 975
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Degree-days - increase (decrease) from normal
Heating	(15.4)%	(6.6)%	(31.3)%	(28.0)%	5.7 %
Cooling	6.1 %	15.3 %	15.5 %	20.9 %	3.5 %

Capacity (mw)
Cleco Power:
Coal and lignite	482	482	482	482	482
Natural gas and oil	880	885	1,211	1,211	1,211
Firm capacity purchases	772	625	20	20	20
Midstream:
Natural gas	848	775	-	-	-
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Total	2,982	2,767	1,713	1,713	1,713
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Peak demand (MW)-Cleco Power	1,751	1,839	1,767	1,627	1,560

Generation (MWh)-Cleco Power
Net generation - system plants	5,536	6,254	6,378	6,764	6,227
Purchased power	3,739	3,109	8,730	3,031	1,985
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Total energy supply	9,275	9,363	15,108	9,795	8,212
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Cost of fuel per kWh	$ 0.0358	$ 0.0328	$ 0.0236	$ 0.0228	$ 0.0235

Fuel Mix-Cleco Power
Coal & lignite	33.0 %	35.4 %	33.3 %	37.3 %	43.0 %
Natural gas & oil	26.7 %	30.4 %	39.7 %	39.0 %	33.7 %
Purchased power	40.3 %	34.2 %	27.0 %	23.7 %	23.3 %

System annual load factor	57.2 %	55.4 %	54.3 %	56.2 %	56.1 %

System Average Interruption Duration Index (SAIDI) - Cleco Power	2.40	1.82	1.78	1.75	1.43
(Average amount of hours a customer's service is interrupted)
System Average Interruption Frequency Index (SAIFI) - Cleco Power	1.82	1.41	1.39	1.25	1.47
(Average number of times a customer's service is interrupted)
Customer Satisfaction Percentage- Cleco Power	92 %	94 %	97 %	95 %	95 %
Number of employees at year end	1,392	1,622	1,383	1,210	1,214