Cleco Corporate 8K Management's Discussion and Analysis of Financial Condition and Results of Operations | SEC 4 Mar 02

EXHIBIT 99.1

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

In this report Cleco (which includesCleco Corporation and all of its regulated and 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 replac ement 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, 20001999VarianceChange

(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. &n bsp;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 legislatio n 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 followi ng 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 anno unced 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 operation s 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 electr icity 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.

Cleco Corporate 8-KManagement's Discussion and Analysis of Financial Condition and Results of Operations