10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.  20549
FORM 10-Q
[X] COMBINED QUARTERLY REPORTS PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2001

Or[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-15759

CLECO CORPORATION
(Exact name of registrant as specified in its charter)

Louisiana (State or other jurisdiction of incorporation or organization)	72-1445282 (I.R.S. Employer Identification No.)
2030 Donahue Ferry Road, Pineville, Louisiana (Address of principal executive offices)	71360-5226 (Zip Code)
Registrant's telephone number, including area code:  (318) 484-7400

Commission file number 0-01272

CLECO POWER LLC
(Exact name of registrant as specified in its charter)

Louisiana (State or other jurisdiction of incorporation or organization)	72-0244480 (I.R.S. Employer Identification No.)
2030 Donahue Ferry Road, Pineville, Louisiana (Address of principal executive offices)	71360-5226 (Zip Code)
Registrant's telephone number, including area code:  (318) 484-7400

Indicate by check mark whether the Registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days.

Yes x      No ____

Indicate the number of shares outstanding at each of the issuer's classes of Common Stock, as of the latest practicable date.
Registrant	Description Of Class	Shares Outstanding At October 31, 2001
Cleco Corporation	Common Stock, $1.00 Par Value	44,980,915

Cleco Power LLC meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

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

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	1
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS	3
PART I
ITEM 1     FINANCIAL STATEMENTS
Cleco Corporation Consolidated Financial Statements	4
Cleco Corporation - Results of Operations	14
Cleco Power LLC Financial Statements	26
Cleco Power LLC- Narrative Analysis of the Results of Operations	32
Notes To Financial Statements	34
ITEM 2     MANAGEMENT'S DISCUSSION AND ANALYSIS OF                   FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF                   CLECO CORPORATION	45
ITEM 3     QUANTITATIVE AND QUALITATIVE DISCLOSURES                   ABOUT MARKET RISK OF CLECO CORPORATION	51
PART II
ITEM 1     LEGAL PROCEEDINGS	54
ITEM 6     EXHIBITS AND REPORTS ON FORM 8-K	54
SIGNATURE	55

Glossary of Terms

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

Abbreviation or Acronym	Definition
Acadia Calpine Tolling Agreement.............	Capacity Sale and Tolling Agreement between APP     and Calpine Energy Services
APP.........................................................	Acadia Power Partners LLC
APP-related Petitioners.............................	Various citizens and environmental action groups
APB No. 16.............................................	Accounting Principles Board Opinion No. 16 -     Business Combinations
APB No. 18.............................................	Accounting Principles Board Opinion No. 18 - The     Equity Method of Accounting for Investments in     Common Stock
APB No. 20.............................................	Accounting Principles Board Opinion No. 20 - Accounting Changes
APB No. 25.............................................	Accounting Principles Board Opinion No. 25 - Accounting for Stock Issued to Employees
Calpine.....................................................	Calpine Corporation
Cleco's 2000 Form 10-K..........................	The Company's Annual Report on Form 10-K for     the Year ended December 31, 2000
Cleco Power's 2000 Form 10-K...............	Cleco Power's Annual Report on Form 10-K for the     year ended December 31, 2000
Cleco Power.............................................	Cleco Power LLC
Company..................................................	Cleco Corporation
Dynegy.....................................................	Dynegy Power Marketing, Inc.
EITF........................................................	Emerging Issues Task Force of the FASB
EITF No. 98-10.......................................	Accounting for Contracts Involved in Energy     Trading and Risk Management Activities
Energy......................................................	Cleco Energy LLC
ESOP.......................................................	Employee Stock Ownership Plan
Evangeline.................................................	Cleco Evangeline LLC
Evangeline Tolling Agreement....................	Capacity Sale and Tolling Agreement between     Evangeline and Williams Energy
FASB.......................................................	Financial Accounting Standards Board
FERC.......................................................	Federal Energy Regulatory Commission

1

Hudson.....................................................	Hudson SVD LLC
KW..........................................................	Kilowatt
KWh........................................................	Kilowatt-hour
LDEQ......................................................	Louisiana Department of Environmental Quality
LPSC.......................................................	Louisiana Public Service Commission
Marketing & Trading.................................	Cleco Marketing & Trading LLC
Midstream................................................	Cleco Midstream Resources LLC
Mini-perm.................................................	Short term financing used to pay off construction or     commercial property loans, usually in 4-6 years
Mirant.......................................................	Mirant Corporation, formerly Southern Energy Inc.
Mirant Marketing......................................	Mirant Americas Energy Marketing, LP
MMBtu....................................................	Million British thermal units
MW.........................................................	Megawatt
PEP..........................................................	Perryville Energy Partners LLC
PEP-related Petitioners.............................	Various citizens and community action groups
Quanta......................................................	Quanta Services, Inc.
RTO.........................................................	Regional Transmission Organization
SFAS.......................................................	Statement of Financial Accounting Standards
SFAS No. 58...........................................	Capitalization of Interest Cost in Financial     Statements That Include Investments Accounted     for by the Equity Method
SFAS No. 121.........................................	Accounting for the Impairment of Long-Lived    Assets and for Long-Lived assets to be    Disposed of
SFAS No. 128.........................................	Earnings per Share (EPS)
SFAS No. 131.........................................	Disclosures about Segments of an Enterprise and     Related Information
SFAS No. 133.........................................	Accounting for Derivative Instruments and Hedging     Activities
SFAS No. 141.........................................	Business Combinations
SFAS No. 142.........................................	Goodwill and Other Intangible Assets
SFAS No. 143.........................................	Accounting for Asset Retirement Obligations
SFAS No. 144.........................................	Accounting for the Impairment or Disposal of    Long-Lived Assets
SPP..........................................................	Southwest Power Pool
UtiliTech...................................................	Utility Construction & Technology Solutions LLC
UTS.........................................................	UTS, LLC (successor entity to UtiliTech)
VAR.........................................................	Value-at-risk
Williams Energy........................................	Williams Energy Marketing and Trading Company

2

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

          This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements other than statements of historical fact included in this report are forward-looking statements.  Although the Company and Cleco Power believe that the expectations reflected in such forward-looking statements are reasonable, such forward-looking statements are based on numerous assumptions (some of which may prove to be incorrect) and are subject to risks and uncertainties that could cause the actual results to differ materially from the Company's and Cleco Power's expectations.  In addition to any assumptions and other factors referred to specifically in connection with these forward-looking statements, the following list identifies some of the factors that could cause the Company's and Cleco Power's actual res ults to differ materially from those contemplated in any of the Company's and Cleco Power's forward-looking statements:

• the effects of competition in the power industry,
• legislative and regulatory changes affecting electric utilities,
• the weather and other natural phenomena,
• the timing and extent of changes in commodity prices and interest rates,
• the operating performance of the facilities of Cleco Power and Midstream, and
• changes in general economic and business conditions, as well as other factors discussed in this and the Company's and Cleco Power's other filings with the Securities and Exchange Commission.

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

3

CLECO CORPORATION
PART I - FINANCIAL INFORMATION

ITEM 1          FINANCIAL STATEMENTS

          The consolidated financial statements for the Company included herein are unaudited but reflect, in management's opinion, all adjustments, consisting only of normal recurring adjustments, that are necessary for a fair presentation of the Company's financial position and the results of its operations for the interim periods presented. Because of the seasonal nature of the business of several of the Company's subsidiaries, the results of operations for the three months and nine months ended September 30, 2001 are not necessarily indicative of the results that may be expected for the full fiscal year.  The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in Cleco's 2000 Form 10-K.

          On April 27, 2001, the Company's shareholders approved a charter amendment to increase the amount of authorized common stock and to effect a two-for-one stock split of the Company's common stock.  The charter amendment became effective at the close of business May 7, 2001, which was also the record date for the stock split. Distribution of certificates representing the split shares occurred on May 21, 2001.  After the split, the Company has approximately 45 million shares of common stock outstanding and has authorization to issue up to an aggregate of 100 million shares (including the shares currently 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.

4

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
For the three months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands, except share and per share amounts)
Operating revenue:
Retail electrical operations	$  181,790	$  203,144
Energy marketing and tolling operations	123,358	66,192
Other operations	688	(204)
Gross operating revenue	305,836	269,132
Retail electric customer credits	1,133	(8)
Total operating revenue	306,969	269,124
Operating expenses:
Fuel used for electric generation	49,635	52,447
Power purchased for utility customers	36,992	54,381
Purchases for energy marketing operations	92,786	34,542
Other operations	34,925	28,731
Maintenance	8,964	11,352
Depreciation	14,466	15,056
Taxes other than income taxes	9,805	10,274
Total operating expenses	247,573	206,783
Operating income	59,396	62,341
Interest income	286	360
Allowance for other funds used during construction	(292)	3
Other income (expense), net	147	893
Income before interest charges	59,537	63,597
Interest charges:
Interest charges, including amortization of           debt expenses, premium and discount	12,049	14,543
Allowance for borrowed funds used during construction	(727)	12
Total interest charges	11,322	14,555
Net income from continuing operations before income taxes and      preferred dividends	48,215	49,042
Federal and state income taxes	17,095	17,725
Net income from continuing operations	31,120	31,317
Discontinued operations:
Loss from operations, net of income taxes	-	1,174
Loss on disposal of segment, net of income taxes	-	-
Total discontinued operations	-	1,174
Net income before preferred dividends	31,120	30,143
Preferred dividend requirements, net	525	466
Net income applicable to common stock	$  30,595	$   29,677
	======	======
(Continued on next page)

5

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Continued)
For the three months ended September 30
(UNAUDITED)

	2001		2000
	(Thousands, except share and per share amounts)
Average shares of common stock outstanding:
Basic	45,004,241		44,976,074
Diluted	47,722,790		47,662,244
Basic earnings per share:
From continuing operations	$	0.68	$	0.69
From discontinued operations	$	-	$	(0.03)
Net income applicable to common stock	$	0.68	$	0.66
Diluted earnings per share:
From continuing operations	$	0.65	$	0.66
From discontinued operations	$	-	$	(0.03)
Net income applicable to common stock	$	0.65	$	0.63
Cash dividends paid per share of common stock	$	0.2200	$	0.2125

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

6

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
For the nine months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands, except share and per share amounts)
Operating revenue:
Retail electrical operations	$   511,323	$  462,168
Energy marketing and tolling operations	352,371	131,520
Other operations	886	386
Gross operating revenue	864,580	594,074
Retail electric customer credits	(800)	(1,233)
Total operating revenue	863,780	592,841
Operating expenses:
Fuel used for electric generation	174,003	126,496
Power purchased for utility customers	94,665	94,425
Purchases for energy marketing operations	290,883	91,095
Other operations	82,642	62,138
Maintenance	24,223	27,038
Depreciation	45,245	40,674
Taxes other than income taxes	28,905	28,534
Total operating expenses	740,566	470,400
Operating income	123,214	122,441
Interest income	1,652	812
Allowance for other funds used during construction	212	657
Other income (expense), net	229	2,363
Income before interest charges	125,307	126,273
Interest charges:
Interest charges, including amortization of           debt expenses, premium and discount	38,094	33,854
Allowance for borrowed funds used during construction	(1,221)	(226)
Total interest charges	36,873	33,628
Net income from continuing operations before income taxes and      preferred dividends	88,434	92,645
Federal and state income taxes	31,144	32,029
Net income from continuing operations	57,290	60,616
Discontinued operations:
Loss from operations, net of income taxes	-	3,337
Loss on disposal of segment, net of income taxes	2,468	-
Total discontinued operations	2,468	3,337
Net income before extraordinary item	54,822	57,279
Extraordinary item, net of income taxes	-	2,508
Net income before preferred dividends	54,822	59,787
Preferred dividend requirements, net	1,405	1,400
Net income applicable to common stock	$     53,417	$     58,387
	=======	=======
(Continued on next page)

7

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Continued)
For the nine months ended September 30
(UNAUDITED)

	2001		2000
	(Thousands, except share and per share amounts)
Average shares of common stock outstanding:
Basic	45,008,890		44,934,720
Diluted	47,817,172		47,603,878
Basic earnings per share:
From continuing operations	$	1.24	$	1.32
From discontinued operations	$	(0.05)	$	(0.07)
Extraordinary item	$	-	$	0.05
Net income applicable to common stock	$	1.19	$	1.30
Diluted earnings per share:
From continuing operations	$	1.19	$	1.27
From discontinued operations	$	(0.05)	$	(0.07)
Extraordinary item	$	-	$	0.05
Net income applicable to common stock	$	1.14	$	1.25
Cash dividends paid per share of common stock	$	0.6500	$	0.6325

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

8

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	At	At
	September 30, 2001	December 31, 2000
	(Thousands)
Assets
Current assets:
Cash and cash equivalents	$         7,067	$       29,407
Accounts receivable, net	76,698	74,620
Other accounts receivable	18,381	24,200
Unbilled revenues	28,790	37,547
Fuel inventory, at average cost	11,961	7,275
Materials and supplies inventory, at average cost	15,902	15,956
Margin deposits	7,325	21,657
Risk management assets	6,066	19,070
Accumulated deferred fuel	-	3,617
Other current assets	6,215	4,857
Total current assets	178,405	238,206
Property, plant and equipment:
Property, plant and equipment	1,823,995	1,799,161
Accumulated depreciation	(643,030)	(604,145)
Net property, plant and equipment	1,180,965	1,195,016
Construction work-in-progress	41,814	37,742
Total property, plant and equipment, net	1,222,779	1,232,758
Equity investment in investees	202,691	98,204
Other assets	1,747	2,642
Prepayments	17,128	16,766
Restricted cash	28,405	55,343
Regulatory assets - deferred taxes	96,616	100,267
Other deferred charges	50,348	45,010
Accumulated deferred federal and state income taxes	64,396	56,508
Total assets	$  1,862,515	$  1,845,704
	========	=======
(Continued on next page)

9

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS (Continued)
(UNAUDITED)

	At	At
	September 30, 2001	December 31, 2000
	(Thousands)
Liabilities and shareholders' equity
Current liabilities:
Short-term debt	$     137,517	$        95,957
Long-term debt due within one year	30,837	30,665
Accounts payable	67,155	102,838
Retainage	6,406	8,770
Customer deposits	20,802	20,447
Taxes accrued	55,848	17,286
Interest accrued	5,848	15,177
Risk management liabilities	7,739	21,118
Accumulated deferred fuel	18,046	-
Other current liabilities	7,267	12,997
Total current liabilities	357,465	325,255
Deferred credits:
Accumulated deferred federal and state income taxes	267,544	270,118
Accumulated deferred investment tax credits	22,928	24,252
Regulatory liabilities - deferred taxes	37,852	38,840
Other deferred credits	46,635	48,089
Total deferred credits	374,959	381,299
Long-term debt, net	627,415	659,135
Total liabilities	1,359,839	1,365,689
Shareholders' equity:
Preferred stock
Not subject to mandatory redemption	27,326	28,090
Deferred compensation related to preferred stock held by                     ESOP	(11,501)	(12,994)
Total preferred stock not subject to mandatory                     redemption	15,825	15,096
Common shareholders' equity:
Common stock, $1 par value, authorized 100,000,000                shares, issued 45,063,740 shares at                September 30, 2001 and December 31, 2000	45,064	45,064
Premium on capital stock	111,826	112,502
Long-term debt payable in Company's common stock	-	519
Retained earnings	332,441	308,047
Accumulated other comprehensive income	(886)	-
Treasury stock, at cost, 74,985 and 73,072 shares at           September 30, 2001 and December 31, 2000, respectively	(1,594)	(1,213)
Total common shareholders' equity	486,851	464,919
Total shareholders' equity	502,676	480,015
Total liabilities and shareholders' equity	$  1,862,515	$  1,845,704
	=======	=======

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

10

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the nine months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
OPERATING ACTIVITIES:
Net income before preferred dividends	$      54,822	$    59,787
Adjustments to reconcile net income to net cash        provided by (used in) operating activities:
Loss on disposal of segment, net of tax	(2,122)	-
Loss from discontinued operation, net of tax	-	3,337
Depreciation and amortization	46,291	41,610
Allowance for funds used during construction	(212)	(657)
Amortization of investment tax credits	(1,324)	(1,306)
Net deferred income taxes	(11,874)	5,871
Deferred fuel costs	21,663	(13,281)
Extraordinary gain, net of income tax	-	(2,508)
Changes in assets and liabilities:
Accounts receivable, net	(192)	(66,612)
Unbilled revenues	6,522	(8,926)
Fuel inventory, materials and supplies	(4,718)	2,575
Accounts payable	(37,167)	(792)
Customer deposits	355	177
Other deferred accounts	(2,861)	(6,313)
Taxes accrued	39,560	27,699
Interest accrued	(9,329)	(3,353)
Margin deposits	14,332	(2,857)
Risk management assets and liabilities, net	(375)	(2,720)
Other, net	(2,543)	(146)
Net cash provided by operating activities	110,828	31,585
INVESTING ACTIVITIES:
Additions to property, plant and equipment	(36,645)	(91,641)
Allowance for funds used during construction	212	657
Proceeds from sale of property, plant and equipment	589	211
Loss on disposal - proceeds	4,590	-
Equity investment in investees	(108,730)	(50,845)
Net cash used in investing activities	(139,984)	(141,618)
FINANCING ACTIVITIES:
Cash transferred from restricted account	26,938	11,663
Change in short-term debt, net	41,560	48,749
Retirement of long-term obligations	(31,403)	(29,780)
Issuance of long-term debt	-	110,179
Dividends paid on common and preferred stock, net	(30,663)	(29,829)
Repurchase of common stock	384	-
Net cash provided by financing activities	6,816	110,982
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(22,340)	949
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	29,407	25,161
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$       7,067	$   26,110
	======	======
Supplementary cash flow information
Interest paid (net of amount capitalized)	$     55,090	$   36,276
	======	======
Income taxes paid	$       7,761	$   19,250
	======	======
Supplementary non-cash investing activity
Transfer of assets to joint venture, net	$       5,156	$            -
	======	======

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

11

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
For the three months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
Net income applicable to common stock	$  30,595	$  29,677
Other comprehensive expense, net of tax
Net unrealized loss from derivative instruments	(1,314)	-
Net other comprehensive expense	(1,314)	-
Comprehensive income	$  29,281	$  29,677
	======	======

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

12

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
For the nine months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
Net income applicable to common stock	$   53,417	$  58,387
Other comprehensive income (expense), net of tax
Transition adjustment from implementation of SFAS No. 133	(4,453)
Net unrealized gains from derivative instruments	3,567	-
Net other comprehensive income (expense)	(886)	-
Comprehensive income	$  52,531	$  58,387
	======	======

The accompanying notes, as they relate to Cleco Corporation, are an integral part of the consolidated financial statements.

13

CLECO CORPORATION - RESULTS OF OPERATIONS

          Set forth below is information concerning the consolidated results of operations of Cleco Corporation for the three months and nine months ended September 30, 2001, and September 30, 2000.  The following discussion should be read in combination with the Company's Financial Statements and the notes contained in this Form 10-Q.

Comparison of the Three Months Ended September 30, 2001 and 2000

	For the three months ended September 30
	2001		2000		Variance		Change
			(Thousands)
Operating revenues	$	306,969	$	269,124	$	37,845	14.1 %
Operating expenses	$	247,573	$	206,783	$	40,790	19.7 %
Net income from continuing    operations	$	31,120	$	31,317	$	(197)	(0.6)%
Loss from discontinued    operations, net	$	- -	$	1,174	$	(1,174)	(100)%
Net income applicable to    common stock	$	30,595	$	29,677	$	918	3.1 %

          Consolidated net income from continuing operations decreased 0.6% in the third quarter of 2001 as compared to the third quarter of 2000 due primarily to decreased earnings at Midstream, which were partially offset by a slight increase of earnings at Cleco Power.  Net income from continuing operations from Midstream decreased $2.2 million in the third quarter of 2001 as compared to the third quarter of 2000 largely due to lower margins on energy marketing and trading functions.  Offsetting the decrease in the energy marketing business at Midstream were increases in net income from continuing operations of $0.8 million from Midstream power plant operations, $1.3 million at Cleco Power and $0.2 million from other businesses.

          Increased operating revenues for the third quarter of 2001 as compared to the third quarter of 2000 were due primarily to a $46.8 million increase in energy marketing and tolling operations at Midstream, which were partially offset by decreased revenues of $9.6 million at Cleco Power.  The $46.8 million increase is due to a $47.1 million increase in energy trading revenues, which was partially offset by a decrease of $0.3 million in tolling revenues from Midstream power plant operations.  The decrease of $9.6 million in revenues at Cleco Power is due to a $18.4 million decrease in fuel cost recovery revenues and a $2.9 million decrease in base revenues.  The decrease in revenue at Cleco Power was partially offset by an increase in energy marketing revenues of $10.4 million, an increase in affiliate revenues of $0.2 million and a decrease in the estimated customer credit of $1.1 million.

          The 19.7% increase in operating expenses for the third quarter of 2001 as compared to the third quarter of 2000 was caused mainly by increased purchases for energy marketing at Midstream and Cleco Power which were partially offset by decreased fuel and purchased power expenses at Cleco Power.  Purchases for energy marketing at Midstream and Cleco Power

14

increased $48.9 million and $9.3 million, respectively, in the third quarter of 2001 as compared to the third quarter of 2000.  The increase at Midstream is due to a $50.0 million increase in purchases for energy marketing at its energy trading business, which was partially offset by a $1.1 million decrease in purchases for energy marketing from its power plant operations.  Depreciation at Midstream decreased $0.8 million in the third quarter of 2001 as compared to the third quarter of 2000 due to a $0.5 million decrease from its power plant operations, resulting from an extension in the estimated useful life of the Evangeline Power Station and a $0.3 million decrease from its energy marketing business.  Fuel and purchased power expenses at Cleco Power decreased $20.2 million in the third quarter of 2001 as compared to the third quarter of 2000 due primarily to a decrease in the price of purchased power.

MIDSTREAM

Marketing & Trading

          Marketing & Trading generally does not take physical delivery of electricity or natural gas marketed, but settles the transactions through the financial markets.

          The amount of kWh's of electricity and MMBtu's of natural gas traded during a particular period are generally influenced by several factors:

• The market prices of gas or power,
• The market price volatility of gas or power,
• The power generating and natural gas assets available and
• The overall economy in the region.

          The combination and intensity of these factors acting in concert or in opposition to each other will affect trading volumes in various degrees.  In addition, other factors may occasionally affect trading volumes.  Based on the influences on trading volumes, general trends are difficult to predict.

          The chart below presents a summary of electricity and natural gas marketed during the three months ended September 30, 2001 and 2000.

	For the three months ended September 30
	2001	2000	Change
Electricity marketed (Million kWh)	738	307	140.4%
Natural gas (MMBtu)	3,356510	1,883,921	78.2%

          The increase of $46.0 million in revenues in the third quarter of 2001 as compared to the third quarter of 2000 at Marketing & Trading was due primarily to an increase in electricity and natural gas marketed.  Purchases for energy marketing increased $50.0 million in the third quarter of 2001 as compared to the third quarter of 2000 due primarily to the same reason for the increase in revenues.  Marketing & Trading experienced a 36.2% decrease in its average per unit cost of natural gas and a 4.8% decrease in its average cost of purchased power in the third quarter of 2001 as compared to the third quarter of 2000.

15

Energy

          Energy generally takes physical delivery of natural gas marketed and sells physical gas instead of settling the transactions through the financial markets.  The chart below presents a summary of natural gas marketed for the three months ended September 30, 2001 and 2000.

	For the three months ended September 30
	2001	2000	Change
Natural gas marketed (MMBtu)	3,125,964	1,545,651	102.2%

          The increase of $1.1 million in energy marketing revenues in the third quarter of 2001 as compared to the third quarter of 2000 at Energy was due primarily to an increase in natural gas marketed and an increase in the per unit price of natural gas.  The increase in natural gas marketed was due primarily to Energy's acquisition of two natural gas pipelines in the fourth quarter of 2000.  Energy experienced a 51.0% increase in its average per unit cost of natural gas in the third quarter of 2001 as compared to the third quarter of 2000.

          Purchases for energy marketing increased $0.1 million in the third quarter of 2001 as compared to the third quarter of 2000 due primarily to the same reasons for the increase in revenues.

Power Plant Operations

          Evangeline had tolling revenues of $25.5 million, as compared to the third quarter of 2000, when Evangeline recorded tolling revenues of $25.8 million.

          Operating expenses at Evangeline decreased $2.7 million during the third quarter of 2001 as compared to the same period in 2000.  The $2.7 million decrease is due to a $1.1 million decrease relating to replacement power purchased in 2000 under the Evangeline Tolling Agreement, a $1.1 million decrease in other operations and a $0.5 million decrease in depreciation expense caused by the companies evaluation of the estimated useful life of Evangeline.

16

CLECO POWER

          Cleco Power's net income in the third quarter of 2001 increased $1.3 million from the third quarter of 2000.  Base revenues were down 3.0% for the third quarter of 2001, as compared to the same period in 2000, due primarily to continued moderate weather.  Additionally, operating expenses for the third quarter of 2001 were $10.1 million lower compared to the same period in 2000, driven mainly by a decrease in fuel and power purchased and partially offset by an increase in purchases for energy marketing.

For the three months ended September 30
Operating revenues:	2001	2000	Variance	Change
	(Thousands)
Base	$  94,824	$    97,784	$  (2,960)	(3.0)%
Fuel cost recovery	86,966	105,360	(18,394)	(17.5)%
Affiliate revenue	801	604	197	32.6 %
Estimated customer credits	1,133	(8)	1,141	-
Energy marketing	12,957	2,592	10,365	399.9 %
Total operating revenues	$  196,681	$  206,332	$   (9,651)	(4.7)%
	========	========	=======

	For the three months ended September 30
	2001	2000	Change
	(Millions kWh)
Electric sales
Residential	1,026	1,113	(7.8)%
Commercial	483	491	(1.6)%
Industrial	696	710	(2.0)%
Other retail	167	172	(2.9)%
Total retail	2,372	2,486	(4.6)%
Sales for resale	160	138	1.6 %
Total sales to regular customers	2,532	2,624	(3.5)%
Short-term sales to other utilities	35	27	29.6 %
Sales from marketing activities	3	4	(0.3)%
Total electric sales	2,570	2,655	(3.2)%
	=====	=====

          Base revenues during the third quarter of 2001 decreased $3.0 million over the same period in 2000.  Base revenues from energy sales decreased $3.4 million.  Partially, offsetting this decrease was an increase of $0.3 million in transmission related base revenues and a $0.2 million increase in miscellaneous base revenues.

          Weather influences the demand for electricity, especially among residential customers.  Much of this demand is 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,

17

while a heating degree day is an indication of the likelihood of a consumer utilizing heating.  Normal cooling degree days are calculated for a month by separately calculating the average actual cooling degree days for that month over a period of approximately 30 years.  The following chart indicates the percentage variance from normal conditions and from the prior year for cooling degree days for the third quarters of 2001 and 2000.

Cooling degree days For the three months ended September 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	3.9 %	15.7 %
Increase/(Decrease) from Prior Year	(9.8)%	2.6 %

          Short-term sales to other utilities increased significantly during the third quarter of 2001 as compared to the same period in 2000.  This increase was due primarily 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 that began in June 2001 to supply all of its power.

          Fuel cost recovery revenues collected from customers decreased primarily as a result of a decrease in the average per unit cost of fuel to $3.22 per MMBtu in the third quarter of 2001 compared to $4.59 per MMBtu in the same period in 2000.  The decrease in the average per unit cost of fuel is primarily a result of a 29.8% decrease in the per unit cost of natural gas for the third quarter of 2001 as compared to 2000.  Changes in fuel costs historically have had no effect on net income, as fuel costs are generally recovered through fuel cost adjustment clauses that enable Cleco Power to pass on to customers substantially all changes in the cost of generating fuel and purchased power.  These adjustments are audited monthly and are regulated by the LPSC (representing about 99% of the total fuel cost adjustment) and the FERC.  Until approval is received, the adjustments are subject to refund.

          An earnings review settlement was reached with the LPSC in 1996 pursuant to which accruals for estimated customer credits are sometimes required. Revenues for the third quarter of 2001 were increased by a $1.1 million reversal of previous accruals due to management's revised rate refund estimate as compared to the third quarter of 2000 when a small accrual was made.  Preliminary analysis indicates that Cleco Power's regulatory return on equity will not exceed the allowable rate of return of 12.25%; therefore, management does not anticipate Cleco Power will be required to make a refund for the 12-month cycle ended September 30, 2001.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 Note K. - Accrual for Estimated Customer Credits in the Notes to the Unaud ited Financial Statements in this Report.

          Energy marketing revenues for the third quarter of 2001 increased $10.4 million as compared to the same period in 2000.   The increase in energy marketing revenues is due primarily to excess natural gas marketed.  Cleco Power's energy trading activity is considered "trading" under EITF No. 98-10, requiring open positions to be reported at fair market value or

18

"marked-to-market."  The mark-to-market related to these open positions was a gain of $2.1 million in the third quarter of 2001 compared to a small loss in the same period of 2000.

Energy Marketing Operations For the three months ended September 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 10,883	$  2,626	$   8,257	314.4 %
Mark-to-market	2,074	(34)	2,108	- %
Total revenue	$ 12,957	$  2,592	$ 10,365	399.9 %
	======	======	======
Energy trading expenses	$ 10,892	$  1,594	$   9,298	583.3 %
	======	======	======

          Operating expenses decreased $10.1 million or 6.0% during the third quarter of 2001 compared to the same period in 2000.  The decrease in operating expenses is primarily the result of decreased purchased power.  Energy marketing expenses increased $9.3 million in the third quarter of 2001 compared to the same period in 2000 due to the same reasons described above for increases in energy marketing revenues.  The decrease of $20.2 million in fuel and purchased power for utility operations is due to decreased energy prices primarily driven by decreases in the cost of purchased power as compared to the same period in 2000.   The 14.3% increase in other operations expense in the third quarter of 2001 as compared to the third quarter of 2000 is due primarily to increased earnings within the pension plan in 2000 which results in lower net pension expenses.

OTHER

          Interest expense in the third quarter of 2001 decreased $2.5 million or 17.2% compared to the third quarter of 2000 due primarily to the capitalization of interest expense relating to the construction of Acadia.

          Discontinued operations at UtiliTech reduced earnings $1.2 million for the three months ended September 30, 2001.  For additional information regarding the disposal of UtiliTech, see Note H - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this Report.

19

Comparison of the Nine Months Ended September 30, 2001 and 2000

	For the nine months ended September 30
	2001		2000		Variance		Change
	(Thousands)
Operating revenues	$	863,780	$	592,841	$	270,939	45.7 %
Operating expenses	$	740,566	$	470,400	$	270,166	57.4 %
Net income from continuing    operations	$	57,290	$	60,616	$	(3,326)	(5.5)%
Loss from discontinued    operations, net	$	2,468	$	3,337	$	(869)	(26.0)%
Extraordinary item, net	$	-	$	2,508	$	(2,508)	(100.0)%
Net income applicable to    common stock	$	53,417	$	58,387	$	(4,970)	(8.5)%

          Consolidated net income from continuing operations decreased 5.5% for the nine months ended September 30, 2001 as compared to the same period in 2000 due primarily to decreased earnings at Cleco Power, which were partially offset by increased earnings at Midstream.  Net income from continuing operations from Midstream increased $3.7 million for the nine months ended September 30, 2001 as compared to the same period in 2000 largely due to higher margins on energy marketing and trading functions and the tolling operations of Evangeline, which commenced full commercial operations in July 2000.  Offsetting the increase at Midstream was a $7.0 million decrease in net income from continuing operations from Cleco Power due primarily to higher capacity costs related to purchased power agreements.

          Increased operating revenues for the nine months ended September 30, 2001 as compared to the same period in 2000 were due primarily to a $207.5 million increase in energy marketing and tolling operations at Midstream and an increase of $58.1 million in revenues at Cleco Power.  The $207.5 million increase in energy marketing and tolling revenues is largely due to a $185.5 million increase in energy trading revenues from Midstream's energy trading business and a $22.0 million increase in tolling revenues from Midstream's power plant operations.  The increase in revenues at Cleco Power is primarily due to a $49.7 million increase in fuel cost recovery revenues, a $13.4 million increase in energy marketing revenues and a decrease of $0.4 million in the estimated retail electric customer credit.  The increase in revenues at Cleco Power was partially offset by a decrease of $0.6 million in base revenues due to milder weather compared to 2000.

          The 57.4% increase in operating expenses for the nine months ended September 30, 2001 as compared to the same period in 2000 was caused mainly by increased purchases for energy marketing and depreciation at Midstream and increased fuel and purchased power expenses at Cleco Power.  Purchases for energy marketing at Midstream increased $181.9 million for the nine months ended September 30, 2001 as compared to the same period in 2000 due to a $183.0 million increase in purchases for energy marketing at Midstream's energy trading business and a $1.1 million decrease in purchases for energy marketing from power plant operations.  Depreciation at Midstream increased $3.5 million for the nine months ended

20

September 30, 2001 as compared to the same period in 2000 largely due to the commercial operation of the Evangeline Power Station beginning in July 2000.  Fuel and purchased power expenses at Cleco Power increased $47.8 million for the nine months ended September 30, 2001 as compared to the same period in 2000 due primarily to an increase in natural gas prices.

          Discontinued operations at UtiliTech reduced earnings for the nine months ending September 30, 2001 by $2.5 million or $0.05 per basic average common share.  For additional information regarding the disposal of UtiliTech, see Note H. - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this Report.

          There was no extraordinary item for the nine months ended September 30, 2001, as compared to a $2.5 million extraordinary gain in the same period in 2000 that resulted from the repurchase of outstanding debt by Midstream.

MIDSTREAM

Marketing & Trading

          The chart below presents a summary of electricity and natural gas marketed during the nine months ended September 30, 2001 and 2000.

	For the nine months ended September 30
	2001	2000	Change
Electricity marketed (Million kWh)	2,204	911	141.9%
Natural gas (MMBtu)	7,952,438	7,014,316	13.4%

          The increase of $153.1 million in revenues for the nine months ended September 30, 2001 as compared to the same period in 2000 at Marketing & Trading was due primarily to an increase in electricity marketed and an increase in the per unit price of natural gas.  Purchases for energy marketing increased $158.9 million for the nine months ended September 30, 2001 as compared to the same period in 2000 due primarily to the same reasons for the increase in revenues.  Marketing & Trading experienced a 31.7% increase in its average per unit cost of natural gas and a 54.3% increase in its average cost of purchased power for the nine months ended September 30, 2001 as compared to the same period in 2000.

Energy

          The chart below presents a summary of natural gas marketed for the nine months ended September 30, 2001 and 2000.

	For the nine months ended September 30
	2001	2000	Change
Natural gas marketed (MMBtu)	9,003,473	5,718,025	57.5%

          The increase of $26.9 million in revenues for the nine months ended September 30, 2001 as compared to the same period in 2000 at Energy was due primarily to an increase in natural gas

21

marketed and an increase in the per unit price of natural gas.  The increase in natural gas marketed was due primarily to Energy's acquisition of two natural gas pipelines in the fourth quarter of 2000.  Energy experienced a 99.7% increase in its average per unit cost of natural gas for the nine months ended September 30, 2001 as compared to the same period in 2000.

          Purchases for energy marketing increased $24.1 million for the nine months ended September 30, 2001 as compared to the same period in 2000 due primarily to the same reasons for the increase in revenues.

Power Plant Operations

          Evangeline was in full commercial operation during the nine months ended September 30, 2001 and had tolling revenues of $49.3 million, as compared to the same period in 2000, when Evangeline began partial operations in July and recorded revenues of $27.3 million.

          Operating expenses at Evangeline increased $3.6 million during the nine months ended September 30, 2001 as compared to the same period in 2000 due to the Evangeline power plant being in commercial operation during all of 2001.  The increase is due to an increase in maintenance expenses of $1.3 million, an increase of $3.4 million in depreciation and a decrease in energy marketing operations of $1.1 million relating to replacement power purchased in 2000 under the Evangeline Tolling Agreement.

22

CLECO POWER

          Cleco Power's net income for the nine months ended September 30, 2001 is $7.0 million lower than the same period in 2000.  The decrease was largely due to lower margins from marketing and trading operations as well as lower revenues from retail customer sales, which sales were partially offset by higher transmission and wholesale revenue.  Higher costs for fuel and power purchased and purchases for energy marketing contributed largely to a $70.0 million increase in operating expenses above the same period of 2000.

	For the nine months ended September 30
Operating revenues:		2001	2000	Variance	Change
		(Thousands)
Base		$ 246,792	$ 247,369	$    (576)	(0.2)%
Fuel cost recovery		264,530	214,799	49,731	23.2 %
Affiliate revenue		2,360	7,781	(5,422)	(69.7)%
Estimated customer credits		(800)	(1,233)	433	35.1 %
Energy marketing		26,392	12,999	13,393	103.0 %
Total operating revenues		$ 539,274	$ 481,715	$  57,559	11.9 %
		=======	=======	=======

	For the nine months ended September 30
	2001	2000	Change
	(Millions kWh)
Electric sales
Residential	2,506	2,590	(3.2)%
Commercial	1,270	1,290	(1.6)%
Industrial	2,045	2,198	(7.0)%
Other retail	448	455	(1.5)%
Total Retail	6,269	6,533	(4.0)%
Sales for resale	312	299	4.3 %
Total sales to regular customers	6,581	6,832	(3.7)%
Short-term sales to other utilities	97	37	162.6%
Sales from marketing activities	4	73	(94.5)%
Total electric sales	6,682	6,942	(3.8)%
	=====	=====

          Base revenues during the nine months ended September 30, 2001 decreased slightly over the same period in 2000.  Base revenues from energy sales decreased $3.7 million.  Offsetting this decrease was an increase of $1.9 million in transmission related base revenues and a $1.2 million increase in miscellaneous base revenues.

          Weather influences the demand for electricity, especially among residential customers.  Much of this demand is 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

23

increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days due to the customers' ability to 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.  The following chart indicates the percentage variance from normal conditions and from the prior year for cooling/heating degree days for the nine months ended September 30, 2001 and 2000.

Cooling/Heating degree days For the nine months ended September 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	6.5 %	16.9 %
Increase/(Decrease) from Prior Year	(8.5)%	0.1 %
Heating Degree Days:
Increase/(Decrease) from Normal	(2.3)%	(35.8)%
Increase/(Decrease) from Prior Year	3.1 %	1.8 %

          Short-term sales to other utilities increased significantly during the nine months ended September 30, 2001 as compared to the same period in 2000.  This increase was due primarily 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, that began June 1, 2001.

          Fuel cost recovery revenues collected from customers increased primarily as a result of an increase in the average per unit cost of fuel to $3.13 per MMBtu for the nine months ended September 30, 2001 compared to $2.60 per MMBtu in the same period in 2000.  The increase in the average per unit cost of fuel is primarily a result of a 27.0% increase in the per unit cost of natural gas for the nine months ended September 30, 2001 as compared to 2000.

          An earnings review settlement was reached with the LPSC in 1996 pursuant to which accruals for estimated customer credits are sometimes required.  The Company accrued $0.8 million during the nine months ended September 30, 2001, compared to $1.2 million for the same period in 2000.  The $0.8 million was necessary to comply with the LPSC's final order for the refund for the 12-month cycle ended September 30, 2000.  Preliminary analysis indicates that Cleco Power's regulatory return on equity will not exceed the allowable rate of return of 12.25%; therefore, we do not anticipate that Cleco Power will be required to make a refund for the 12-month cycle ended September 30, 2001.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 Note K. - A ccrual for Estimated Customer Credits in the Notes to the Unaudited Financial Statements in this Report.

          Energy marketing revenues for the nine months ended September 30, 2001 increased $13.4 million as compared to the same period in 2000.  The increase in energy marketing revenues is due primarily to excess natural gas marketed and an increase in the price of natural gas for the nine months ended September 30, 2001.  Cleco Power's energy trading activity is considered

24

"trading" under 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 loss of $0.8 million for the nine months ended September 30, 2001 compared to a gain of $0.9 million in the same period of 2000.  We expect that most or all of these mark-to-market losses will be eliminated by the end of the year.

Energy Marketing Operations For the nine months ended September 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$  27,186	$ 12,103	$  15,083	124.6 %
Mark-to-market	(794)	896	(1,690)	(188.6)%
Total	$  26,392	$ 12,999	$  13,393	103.0 %
	=======	=======	=======
Energy trading expenses	$  27,401	$   9,487	$  17,914	188.8 %
	=======	=======	=======

          Operating expenses increased $70.0 million or 18.2% during the nine months ended September 30, 2001 compared to the same period in 2000.  Energy marketing expenses increased $17.9 million for the nine months ended September 30, 2001 compared to the same period in 2000 due to the same factors described above for increases in energy marketing revenues.  Fuel and purchased power for utility operations increased $47.8 million due to increased energy prices primarily driven by increases in natural gas prices as compared to the same period in 2000.  The 20.0% increase in other operations expense for the nine months ended September 30, 2001 as compared to the same period in 2000 is due primarily to a $5.3 million increase in capacity payments and increased net pension expense.

OTHER

          Interest expense for the nine months ended September 30, 2001 increased $4.2 million or 12.5% compared to the same period in 2000 due primarily to interest expense associated with Evangeline.  During the construction phase of the Evangeline Power Station, interest was capitalized and reflected as a component of plant, property and equipment.  Since the commencement of commercial operations of Evangeline in July 2000, interest has been recorded as interest expense.  Interest charges related to Evangeline for the nine months ended September 30, 2001 were $14.7 million.

          Discontinued operations at UtiliTech reduced the earnings for the nine months ended September 30, 2001 by $2.5 million or $0.05 per basic average common share.  For additional information regarding the disposal of UtiliTech, see Note H - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this Report.

25

CLECO POWER
PART I - FINANCIAL INFORMATION

ITEM 1          FINANCIAL STATEMENTS

          The financial statements for Cleco Power included herein are unaudited but reflect, in management's opinion, all adjustments, consisting only of normal recurring adjustments, that are necessary for a fair presentation of Cleco Power's financial position and the results of its operations for the interim periods presented.  Because of the seasonal nature of Cleco Power's business, the results of operations for the three months and nine months ended September 30, 2001 are not necessarily indicative of the results that may be expected for the full fiscal year.  The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in Cleco Power's 2000 Form 10-K.

26

Cleco Power LLC
STATEMENTS OF INCOME
For the three months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
Operating revenue:
Retail electric operations	$  181,790	$  203,144
Energy marketing operations	12,957	2,592
Affiliate revenues	801	604
Gross operating revenue	195,548	206,340
Retail electric customer credits	1,133	(8)
Total operating revenue	196,681	206,332
Operating expenses:
Fuel used for electric generation	49,635	52,447
Power purchased for utility customer	36,991	54,381
Purchases for energy marketing operations	10,892	1,594
Other operations	29,773	26,051
Maintenance	7,505	9,842
Depreciation	12,664	12,500
Taxes other than income taxes	9,332	10,041
Affiliate costs	770	797
Total operating expenses	157,562	167,653
Operating income	39,119	38,679
Interest income	29	-
Allowance for other funds used during construction	(292)	3
Other income (expense), net	(210)	(481)
Income before interest charges	38,646	38,201
Interest charges:
Interest on debt and other, net of amount capitalized	6,523	6,937
Allowance for borrowed funds used during construction	(727)	12
Amortization of debt discount, premium and expense, net	218	230
Total interest charges	6,014	7,179
Net income before income taxes	32,632	31,022
Federal and state income taxes	11,543	11,190
Net income applicable to member's equity and common stock	$    21,089	$    19,832
	======	======

The accompanying notes, as they relate to Cleco Power, are an integral part of the financial statements.

27

CLECO POWER LLCSTATEMENTS OF INCOME
For the nine months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
Operating revenue:
Retail electric operations	$  511,323	$  462,168
Energy marketing operations	26,392	12,999
Affiliate revenues	2,360	7,781
Gross operating revenue	540,075	482,948
Retail electric customer credits	(800)	(1,233)
Total operating revenue	539,275	481,715
Operating expenses:
Fuel used for electric generation	174,004	126,437
Power purchased for utility customer	94,665	94,425
Purchases for energy marketing operations	27,401	9,487
Other operations	69,846	58,192
Maintenance	21,128	24,372
Depreciation	37,991	37,162
Taxes other than income taxes	27,211	27,786
Affiliate costs	2,007	6,420
Total operating expenses	454,253	384,281
Operating income	85,022	97,434
Interest income	74	-
Allowance for other funds used during construction	212	657
Other income (expense), net	(122)	(1,081)
Income before interest charges	85,186	97,010
Interest charges:
Interest on debt and other, net of amount capitalized	21,038	21,251
Allowance for borrowed funds used during construction	(1,221)	(226)
Amortization of debt discount, premium and expense, net	667	721
Total interest charges	20,484	21,746
Net income before income taxes	64,702	75,264
Federal and state income taxes	22,444	25,974
Net income applicable to member's equity and common stock	$    42,258	$   49,290
	======	======

The accompanying notes, as they relate to Cleco Power, are an integral part of the financial statements.

28

Cleco Power LLCBalance Sheets
(UNAUDITED)

	At September 30,	At December 31,
	2001	2000
	(Thousands)
Assets
Utility plant and equipment:
Property, plant and equipment	$  1,574,130	$  1,550,756
Accumulated depreciation	(627,011)	(595,136)
Net property, plant and equipment	947,119	955,620
Construction work-in-progress	24,754	25,864
Total utility plant, net	971,873	981,484
Current assets:
Cash and cash equivalents	3,284	2,224
Accounts receivable, net
Customer accounts receivable (less allowance for                   doubtful accounts of $993 in 2001 and $840 in 2000)	45,609	41,637
Other accounts receivable	18,119	19,878
Affiliates	1,351	1,457
Notes receivable - affiliates	-	2
Unbilled revenues	25,563	26,863
Fuel inventory, at average cost	11,962	7,275
Material and supplies inventory, at average cost	14,049	14,513
Risk management assets	147	525
Margin deposit	2,065	3,128
Accumulated deferred fuel	-	3,617
Other current assets	3,918	3,630
Total current assets	126,067	124,749
Prepayments	7,636	7,974
Regulatory assets - deferred taxes	96,617	100,267
Accumulated deferred federal and state income taxes	59,447	52,144
Other deferred charges	37,284	37,014
Total Assets	$  1,298,924	$  1,303,632
	=======	=======
(Continued on next page)

29

Cleco Power LLCBALANCE SHEETS (Continued)
(UNAUDITED)

	At September 30,	At December 31,
	2001	2000
	(Thousands)
Capitalization and Liabilities
Member's equity:
Member's equity units	$     172,376	$      172,376
Retained earnings	245,301	234,734
Total member's equity	417,677	407,110
Long-term debt, net	310,444	335,282
Total capitalization	728,121	742,392
Current liabilities:
Short-term debt	44,313	41,397
Long-term debt due within one year	25,000	25,000
Accounts payable	37,384	67,919
Accounts payable - affiliates	19,387	10,846
Customer deposits	20,803	20,447
Taxes accrued	36,960	8,679
Taxes accrued - payable to parent	-	8,161
Interest accrued	1,365	8,021
Risk management liabilities	1,313	1,562
Accumulated deferred fuel	18,046	-
Other current liabilities	3,941	4,933
Total current liabilities	208,512	196,965
Deferred credits
Accumulated deferred federal and state income taxes	265,044	268,311
Accumulated deferred investment tax credits	22,928	24,252
Regulatory liabilities - deferred taxes	37,852	38,840
Other deferred credits	36,467	32,872
Total deferred credits	362,291	364,275
Total Capitalization and Liabilities	$  1,298,924	$  1,303,632
	=======	=======

The accompanying notes, as they relate to Cleco Power, are an integral part of the financial statements.

30

CLECO POWER LLC
STATEMENTS OF CASH FLOWS
For the nine months ended September 30
(UNAUDITED)

	2001	2000
	(Thousands)
OPERATING ACTIVITIES:
Net income	$  42,258	$  49,290
Adjustments to reconcile net income to net cash      provided by operating activities:
Depreciation and amortization	38,658	37,883
Allowance for funds used during construction	(212)	(657)
Amortization of investment tax credits	(1,324)	(1,306)
Deferred income taxes	(7,303)	6,080
Deferred fuel costs	21,663	(13,281)
Changes in assets and liabilities:
Accounts receivable, net	(2,213)	(34,600)
Accounts and notes receivable, affiliate	108	20,760
Unbilled revenues	1,300	(8,663)
Fuel, material and supplies inventories	(4,223)	2,878
Accounts payable	(30,535)	(6,162)
Accounts payable, affiliate	8,541	614
Customer deposits	356	176
Other deferred accounts	(609)	2,482
Taxes accrued	20,120	1,284
Interest accrued	(6,656)	(7,155)
Risk management assets and liabilities, net	129	(2,276)
Margin deposits	1,063	319
Other, net	1,066	(4,945)
Net cash provided by operating activities	82,187	42,721
INVESTING ACTIVITIES:
Additions to property, plant and equipment	(28,315)	(31,665)
Allowance for funds used during construction	212	657
Sale of utility plant, including associated land	589	256
Net cash used in investing activities	(27,514)	(30,752)
FINANCING ACTIVITIES:
Retirement of long-term obligations	(24,838)	(24,956)
Increase in short-term debt, net	2,916	55,777
Distribution to member	(31,691)	(39,578)
Net cash provided by financing activities	(53,613)	(8,757)
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,060	3,212
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2,224	547
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$    3,284	$    3,759
	=====	=====
Supplementary cash flow information
Interest paid (net of amount capitalized)	$  29,541	$  28,928
	=====	=====
Income taxes paid	$  11,027	$  23,130
	=====	=====

The accompanying notes, as they relate to Cleco Power, are an integral part of the financial statements.

31

CLECO POWER - NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS

          Set forth below is information concerning the results of operations of Cleco Power for the three months and nine months ended September 30, 2001 and September 30, 2000.  The following narrative analysis should be read in combination with Cleco Power's Financial Statements and notes contained in this Form 10-Q.

          Cleco Power meets the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and is therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies.  Accordingly, Cleco Power has omitted from this report the information called for by Item 2 (Management's Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I of Form 10-Q and the following Part II items of Form 10-Q: Item 2 (Changes in Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders).  The following discussion explains material changes in the amount of revenue and expense items of Cleco Power between the third quarter of 2001 and the third quarter of 2000 and between the nine months ended September 30, 2001 and the nine months end ed September 30, 2000.  Reference is made to Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of Cleco Power's 2000 Form 10-K.

          For discussions of changes in operating income of Cleco Power, see "Item 1. Financial Statements - Cleco Corporation - Results of Operations - Comparison of the Three Months Ended September 30, 2001 and 2000 -Cleco Power" and "Item 1. Financial Statements - Cleco Corporation - Results of Operations - Comparison of the Nine Months Ended September 30, 2001 and 2000 - Cleco Power" of this Form 10-Q, which discussions are incorporated herein by reference.

          Net income applicable to member's equity and common stock increased $1.3 million in the third quarter of 2001 as compared to the third quarter of 2000 largely due to the $1.6 million increase in net income before income taxes, which was partially offset by the $0.4 million increase in federal and state taxes.  The increase in net income before income taxes is primarily due to higher transmission and wholesale revenue, higher marketing and trading margins and a decline in fuel and purchased power expense.

          Affiliate revenues for the nine months ended September 30, 2001 decreased by $5.4 million or 69.7% as compared to the same period in 2000.  The decrease is due primarily to a reduction in affiliate transactions between Cleco Power and UtiliTech, as stipulated in an agreement between Cleco Power and the LPSC, related to the leasing of crews.

          Net income applicable to member's equity and common stock decreased $7.0 million for the nine months ended September 30, 2001 as compared to the same period in 2000 due primarily to the $10.6 million decrease in net income before income taxes partially offset by the

32

$3.5 million decrease in federal and state taxes.  The decrease in net income before income taxes is largely due to lower margins from marketing and trading operations as well as lower revenues from retail customer sales which were partially offset by higher transmission and wholesale revenue.

33

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

NOTE A	Reclassification	Cleco Corporation and Cleco Power
NOTE B	Extraordinary Gain	Cleco Corporation
NOTE C	Disclosures About Segments	Cleco Corporation
NOTE D	Restricted Cash	Cleco Corporation
NOTE E	Equity Investment in Investee	Cleco Corporation
NOTE F	LDEQ Litigation	Cleco Corporation
NOTE G	New Accounting Standards	Cleco Corporation and Cleco Power
NOTE H	Loss on Disposal of Segment	Cleco Corporation
NOTE I	Stock Split	Cleco Corporation
NOTE J	Debt	Cleco Corporation
NOTE K	Accrual for Estimated Customer Credits	Cleco Corporation and Cleco Power
NOTE L	Tolling Agreement	Cleco Corporation
NOTE M	Options on Common Stock	Cleco Corporation
NOTE N	Earnings Per Share	Cleco Corporation
NOTE O	Change in Accounting Estimate	Cleco Corporation

NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)

Note A.     Reclassification

          Certain prior-period amounts have been reclassified to conform to the presentation shown in the current year's financial statements.  These reclassifications had no effect on net income or shareholders' (member's) equity.

Note B.     Extraordinary Gain

          In March 2000, Four Square Gas, a wholly owned subsidiary of Energy, which is 100% 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 Energy.  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 interests in the production assets.  Four Square Gas borrowed the $2.1 million from the Company.  The gain of approximately $3.9 million was offset against the income tax related to the gain of approximately $1.4 million to arrive at the extraordinary gain, net of income tax, of approximately $2.5 million.

34

Note C.     Disclosures About Segments

          The Company has determined that its reportable segments are based on the Company's method of internal reporting, which disaggregates its business units by first-tier subsidiary.  Reportable segments were determined by applying SFAS No. 131.  The Company's reportable segments are Cleco Power, Midstream and UTS.  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.  The Other segment subsidiaries operate within Louisiana and Delaware.  For additional information, see Note H - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this Report.

          Each reportable segment engages in business activities from which it earns revenues and incurs expenses.  Segment managers report at least monthly to the Company's CEO (the chief decision maker) with discrete financial information and present quarterly discrete financial information to the Company's Board of Directors.  Each reportable segment prepared budgets for 2001, which were presented to, and approved by, the Company's Board of Directors.  The reportable segments exceeded the quantitative thresholds as defined in SFAS No. 131.

          The financial results of the Company's segments are presented on an accrual basis.  Significant differences among the accounting policies of the segments as compared to the Company'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.  Material intersegment transactions occur on a regular basis.

          The tables below present information about the reported operating results and net assets of the Company's reportable segments.

35

Segment Information
For the quarter ending September 30(Thousands)

2001	Cleco Power	Midstream	UTS	Other	Unallocated Items, Reclassifications & Eliminations	Consolidated
Revenues
Retail electric operations	$   182,923					$    182,923
Energy marketing operations	12,957	$  110,401				123,358
Other operations	-	651	$         -	$         37	$              -	688
Intersegment revenue	801	3,159	-	15,725	(19,685)	-
Total operating revenue	$   196,681	$  114,211	$         -	$  15,762	$   (19,685)	$    306,969
	======	======	====	=====	======	======
Segment profit from continuing    operations	$     32,632	$    15,780		$      (197)		$      48,215
Segment profit (loss) (1)	$     32,632	$    15,780	$         -	$      (197)	$              -	$      48,215
	======	======	====	=====	======	======
Segment assets	$1,298,924	$  542,104	$      791	$ 469,925	$  (449,229)	$ 1,862,515

	Segment profit	$  48,215
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	17,095
	Preferred dividends	525
		$  30,595
		=====

2000
Revenues
Retail electric operations	$    203,136					$     203,136
Energy marketing operations	2,592	$    63,600				66,192
Other operations	-	(229)	$         -	$          25	$               -	(204)
Intersegment revenue	604	9,703	-	27,191	(37,498)	-
Total operating revenue	$    206,332	$    73,074	$         -	$   27,216	$     (37,498)	$     269,124
	======	======	====	=====	======	=======
Segment profit from continuing    operations	$      31,022	$    18,861	$          -	$       (841)	$               -	$       49,042
Loss from discontinued    operations, net of income    taxes	$              -	$            -	$   1,174	$            -	$               -	$         1,174
Segment profit (loss) (1)	$      31,022	$    18,861	$  (1,174)	$       (841)	$               -	$       47,868
	======	======	====	=====	======	=======
Segment assets	$ 1,309,825	$  407,986	$   5,838	$  378,821	$   (336,034)	$  1,766,436

	Segment profit	$     47,868
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	17,725
	Preferred dividends	466
		$     29,677
		======

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Segment Information
For the nine months ending September 30
(Thousands)

2001	Cleco Power	Midstream	UTS	Other	Unallocated Items, Reclassifications & Eliminations	Consolidated
Revenues
Retail electric operations	$    510,523					$    510,523
Energy marketing operations	26,392	$ 325,979				352,371
Other operations	-	800	$          -	$        86	$                -	886
Intersegment revenue	2,360	10,785	-	53,091	(66,236)	-
Total operating revenue	$    539,275	$ 337,564	$          -	$  53,177	$     (66,236)	$    863,780
	======	======	====	=====	======	======
Segment profit from continuing   operations	$      64,702	$   25,075	$           -	$   (1,343)	$                -	$      88,434
Loss on disposal of segment	$              -	$           -	$   2,468	$           -	$                -	$        2,468
Segment profit (loss) (1)	$      64,702	$   25,075	$ (2,468)	$  (1,343)	$                -	$      85,966
	======	======	====	=====	======	======
Segment assets	$ 1,298,924	$ 542,104	$     791	$ 469,925	$   (449,229)	$ 1,862,515

	Segment profit	$  85,966
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	31,144
	Preferred dividends	1,405
		$  53,417
		=====

2000
Revenues
Retail electric operations	$    460,935					$    460,935
Energy marketing operations	12,999	$ 118,521				131,520
Other operations	-	336	$          -	$          50	$              -	386
Intersegment revenue	7,781	29,584	-	75,923	$  (113,288)	$               -
Total operating revenue	$    481,715	$ 148,441	$          -	$   75,973	$  (113,288)	$    592,841
	======	=====	====	=====	======	======
Segment profit from continuing    operations	$      75,264	$   18,649	$	$    (1,268)	$              -	$      92,645
Loss from discontinued    operations, net of income    taxes	$             -	$           -	$   3,337	$           -	$              -	$        3,337
Extraordinary item, net of income    taxes	$             -	$     2,508	$         -	$           -	$              -	$        2,508
Segment profit (loss) (1)	$      75,264	$   21,157	$ (3,337)	$   (1,268)	$              -	$      91,816
	======	=====	====	=====	======	======
Segment assets	$ 1,309,825	$ 407,986	$   5,838	$ 378,821	$ (336,034)	$ 1,766,436

	Segment profit	$  91,816
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	32,029
	Preferred dividends	1,400
		$  58,387
		=====

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Note D.     Restricted Cash

          Restricted cash represents cash to be used for specific purposes.  Approximately $15.0 million in restricted cash at December 31, 2000 was replaced with a letter of credit to be maintained as security for the performance of certain obligations by Evangeline in regard to the Evangeline Tolling Agreement.  At September 30, 2001, $28.4 million of cash remains restricted under the Evangeline bond indenture until certain of its provisions are met.

Note E.     Equity Investment in Investee

          Equity investment in investee represents Midstream's approximately $199.9 million investment in APP, Midstream's approximate $2.0 million investment in PEH and Energy's approximate $0.8 million investment in Hudson SVD LLC.  For the first nine months of 2001 PEP recorded net income of $0.2 million, APP recorded a net loss of $0.2 million while no material earnings have been recorded for Hudson SVD LLC.

          APP is a joint venture 50% owned by Midstream and 50% owned by Calpine.  APP was formed in order to construct, own and operate a combined cycle, natural gas-fired power plant to be located near Eunice, Louisiana.  The Company reports its investment in APP on the equity method of accounting as defined in APB No. 18.  Midstream's member's equity as reported in the unaudited balance sheet of APP at September 30, 2001, was $190.1 million.  The majority of the difference of $9.8 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.

          PEP, a joint venture 50% owned by Midstream and 50% owned by Mirant, is in the process of constructing a 700 MW combined-cycle, natural gas-fired power plant in Perryville, Louisiana.  The Company reports its investment in PEP on the equity method of accounting as defined in APB No. 18.  Midstream's member's equity as reported in the unaudited balance sheet of PEP at September 30, 2001 was reduced to zero.  The reduction of Midstream's investment in PEP and member's equity as reported on PEP's balance sheet is due to the long-term non-recourse financing that occurred during June 2001 and a subsequent distribution from PEP to Midstream.  The difference of $2.0 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.

          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.  The Company 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 unaudited balance sheet was approximately $0.8 million, which equals the investment at Energy.

38

Note F.     LDEQ Litigation

          Air and water permits issued on or about July 13, 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 electricgenerating 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 order issued on February 23, 2001, the court ordered the matter remanded to the LDEQ but did not vacate the permits or halt construction.  The precise issues that LDEQ must take up on remand will not be determined until the court issues its judgement on its February 23, 2001 ruling which has not yet occurred.  Although the ultimate outcome of this action cannot be predicted at this time, based on information currently available to the Company, management does not believe the outcome of this action will have a material adverse effect on the Company's financial condition or results of operations.

          An air permit issued by the LDEQ on or about August 25, 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 on or about June 30, 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.  PEP-related Petitioners have asked that the district court reverse the permit decisions or remand the permit decisions to require the LDEQ to address certain alleged deficiencies in its issuan ce of the permits and have also requested that the court stay the permits.  PEP denies PEP-related Petitioners' allegations and is vigorously defending the validity of the permits.  The permits could be upheld, reversed or remanded, in whole or in part.  In the event of a reversal or remand by the court, PEP's construction of the generating plant may be delayed, depending upon the nature and details of the reversal or remand.  On or about March 29, 2001, as a result of an agreement by the parties, the court ordered that the air permit appeal be remanded to the LDEQ for the purpose of receiving additional information from PEP, reopening the public comment period, and issuing a revised

39

decision for the issuance of the permit.  Although the ultimate outcome of this action cannot be predicted at this time, based on information currently available to the Company, management does not believe the outcome of this action will have a material adverse effect on the Company's financial condition or results of operations.

Note G.     New Accounting Standards

          In June 2001, FASB issued SFAS No. 141, which established accounting and reporting standards for business combinations and supercedes APB 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.

          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.  The Company has not yet determined the effect of adopting this statement 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 it 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.  The Company 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 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.  The Company has not yet determined the effect of adopting this statement on its financial statements.

Note H.     Loss on Disposal of Segment

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

40

asset purchase agreement to sell UtiliTech to Quanta for approximately $3.1 million in cash and assumption of an operating lease for equipment of approximately $11.6 million.  Quanta acquired the trade names under which UtiliTech operated, crew tools, equipment under the operating lease with an aggregate unamortized balance of approximately $11.6 million, contracts, inventory relating to certain contracts and workforce in place.  UtiliTech (now known as 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.

          As of September 30, 2001, several contingent liabilities exist:

• The asset purchase agreement requires that within 45 days after the date of sale, purchase price adjustment calculations will be made that could adjust the purchase price for UtiliTech.  Purchase price adjustment calculations will be made on final amounts due at contract completion versus amounts billed at sale date for fixed price contracts, quality and quantity of acquired equipment and inventory.  During the third quarter, it was determined that 45 days were not adequate to complete the calculations.  The due date of the calculations was extended and should be completed by the end of the fourth quarter.  The purchase price adjustment calculations could result in a positive or negative adjustment to the purchase price.  The amount of the adjustments cannot yet be determined.

• 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 on specific assets relating to periods before the sale and other losses arising from events occurring prior to the sale.  The indemnification amount is limited to approximately $14.9 million until December 31, 2001 and $5.0 million until April 1, 2003.  The limitations do not apply to fraudulent misrepresentations.  At September 30, 2001, no amounts have been recorded for the indemnifications.

          Additional information about UTS is as follows:

	For the nine months ended September 30
	2001		2000
	(Thousands)
Revenues	$	3,947	$	11,694
Loss from operations, net	$	-	$	(5,408)
Income tax benefit associated with
loss from operations	$	-	$	2,071
Loss on disposal of segment, net	$	(2,468)	$	-
Income tax benefit associated with
loss on disposal of segment	$	1,539	$	-

41

          During the first nine months of 2001, the $2.5 million loss on disposal of a segment, net, resulted primarily from actual operating losses and updated estimated losses for 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 and the $1.3 million loss on the auction of equipment.

Note I.      Stock Split

          On April 27, 2001, holders of a majority of the outstanding shares of capital stock of the Company voted to amend the Amended and Restated Articles of Incorporation of the Company to effect the reclassification of the Company's common stock, par value $2 per share.  The amendment changed the Company's authorized shares of common stock, 50,000,000 shares of common stock, par value $2 per share, into 100,000,000 shares of common stock, par value $1 per share.  Each share of common stock, par value $2 per share, was changed into two shares of common stock, par value $1 per share.  The two-for-one stock split of the Company's common stock was effective for shareholders of record at the close of business on May 7, 2001.  After the stock split, the Company had approximately 45,000,000 shares of common stock outstanding.  Distribution of certificates representing the split shares occurred on May 21, 2001.&n bsp; 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 J.     Debt

          On June 25, 2001, Midstream entered into a $36.8 million, 364-day credit agreement.  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 or the bank's prime rate in effect on such date.  This line of credit is guaranteed by the Company.  At September 30, 2001, there were no balances outstanding under this credit agreement.

Note K.     Accrual for Estimated Customer Credits

          Cleco Power's reported earnings for the nine months ended September 30, 2001 reflect a $0.8 million accrual for estimated customer credits pursuant to terms of an earnings review settlement reached with the LPSC under order U-21496 in 1996.  Preliminary analysis indicates that Cleco Power's regulatory return on equity will not exceed the allowable rate of return of 12.25%; therefore, we do not anticipate that Cleco Power will be required to make a refund for the 12-month cycle ended September 30, 2001.  The $0.8 million relates to the 12-month-ended September 30, 2000 cycle.  On July 25, 2001 the LPSC's final report required a $1.8 million refund for the 12-month ended September 30, 2000 cycle.   The refund for the 12-month ended September 30, 2000 cycle was paid in September 2001.

42

Note L.     Tolling Agreement

          On July 30, 2001, APP executed the Acadia Calpine Tolling Agreement with Calpine Energy Services.  Under the terms of the agreement, for 20 years Calpine Energy Services will provide the natural gas needed to generate 580 MW of electricity at the Acadia facility and will have the right to own and market the electricity produced.  The agreement requires Calpine to pay APP various capacity reservation fees, the price of which depends upon the type of capacity and ultimate availability declared by APP.  In addition to the capacity reservation payments from Calpine, APP will collect revenues associated with both fixed and variable operating and maintenance expenses anticipated at the Acadia facility.  Tolling revenues are primarily affected by the availability of the APP power plant to operate and other characteristics of the plant.

Note M.     Options on Common Stock

          In July 2001, the Company granted basic non-qualified stock options under its 2000 Long-Term Incentive Compensation Plan to directors and key employees exercisable for 215,000 shares of common stock.  The options have an exercise price approximately equal to the fair value of the stock at grant date, and vest one-third each year beginning on the third anniversary of the grant date and expire after ten years.  In accordance with APB No. 25, the Company has not recognized any compensation expense for the stock options granted.

          The Company granted annual options to directors in July 2001 exercisable for 25,000 shares of common stock.  The options have an exercise price approximately equal to the fair value of the stock at the grant date, are immediately exercisable and expire after ten years.

Note N.     Earnings Per Share

          During 2000, two types of non-qualified stock options were granted under the Company's incentive plans-basic and premium.  During the three-month period ended September 30, 2001, premium options totaling 54,000 were considered anti-dilutive, as defined by SFAS No. 128, and were excluded from the calculation of diluted earnings per share.  The remaining 54,000 premium options granted plus all of the 65,800 basic options granted were included in the calculation of diluted earnings per share during the three-month and nine-month period ended September 30, 2001.

          During 2001, the Company granted 240,000 basic non-qualified stock options.  As defined by SFAS No. 128, the options were considered anti-dilutive during the three-month period ended September 30, 2001 and were excluded from the calculation of diluted earnings per share.  The options were included in the calculation of diluted earnings per share for the nine-month periods ended September 30, 2001.

43

Note O.     Change in Accounting Estimate

          Effective July 1, 2001, in accordance with APB 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 45 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 the three months and for the nine months ended September 30, 2001 was increased $0.4 million, or $0.01 per basic share.

44

ITEM 2     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                  CONDITION AND RESULTS OF OPERATIONS OF CLECO
                  CORPORATION

          The following discussion and analysis should be read in combination with Cleco's 2000 Form 10-K and the Cleco Corporation Financial Statements contained in this Form 10-Q.  The information included therein is essential to understanding the following discussion and analysis.

RESULTS OF OPERATIONS

          "Item 1. Financial Statements - Cleco Corporation - Results of Operations" of this Form 10-Q is incorporated herein by reference.

FINANCIAL CONDITION

Liquidity and Capital Resources

          At September 30, 2001, and December 31, 2000, the Company had $137.5 million and $96.0 million, respectively, of short-term debt outstanding in the form of commercial paper borrowing and bank loans.  The Company is a party to two separate credit facilities: a $120 million, 364-day credit facility that is scheduled to terminate in May 2002, and an $80 million facility that is scheduled to terminate in August 2002.  These facilities provide support for the issuance of commercial paper and working capital needs.  Guaranties issued by the Company to third parties for certain types of transactions between those parties and the Company's subsidiaries, other than Cleco Power, reduce the amount of credit available to the Company.  In addition, certain indebtedness incurred by the Company outside of the credit facilities reduces the amount of credit available to the Company under the facilities.  The amount o f credit available to the Company under the facilities totaled $77.0 million at September 30, 2001.  An uncommitted line of credit with a bank in the amount of $2.5 million is also available to support working capital needs.

          At September 30, 2001, and December 31, 2000, Cleco Power, a regulated consolidated subsidiary of the Company, had $44.3 million and $41.4 million, respectively, of short-term debt outstanding in the form of commercial paper borrowing and bank loans.  A $100 million Cleco Power revolving credit facility is scheduled to terminate in May 2002.  This facility provides support for the issuance of commercial paper and working capital needs.  A separate $2.5 million uncommitted line of credit with a bank is also available to support working capital needs of Cleco Power.

          On June 25, 2001, Midstream, an unregulated consolidated subsidiary of the Company, became a party to a $36.8 million line of credit.  The 364-day facility is scheduled to terminate in June 2002.  At September 30, 2001, there was no balance outstanding under this credit facility.

45

         On March 1, 2001, The Bank of New York issued a $15 million letter of credit on behalf of Evangeline to Williams Energy pursuant to the Williams Tolling Agreement between Williams Energy and Evangeline that expires July 7, 2020.  It is renewable annually and no compensating balances are required.  Letters of credit are issued through the Company's revolving credit agreements.

          APP is a joint venture between Midstream and Calpine that is in the process of constructing a combined-cycle, natural gas-fired power plant near Eunice, Louisiana.  Total construction costs of the plant to be incurred by APP are estimated to be $564 million.  As of September 30, 2001, Midstream had contributed $199.9 million in cash and land to APP.  The Company expects APP to receive non-recourse project financing and to reimburse the Company for a large portion of the contributions to APP in the first quarter of 2002.

          PEP is a joint venture between Midstream and Mirant that is in the process of constructing a 700 MW combined-cycle, natural gas-fired power plant in Perryville, Louisiana.  Total construction costs of the plant to be incurred by PEP are estimated to be $340 million.  As of September 30, 2001, Midstream had contributed $2.0 million to PEP, net of a distribution from PEP due to financing at PEP.  A 150 MW combustion turbine operating in simple cycle became operational on July 1.  Full commercial operation in combined cycle is expected for the summer of 2002.  A $300 million interim construction facility at PEP was completed on June 7, 2001.  This facility is non-recourse to Midstream and the Company.  The interim facility is convertible to an 8-year Mini-perm term loan by July 2002.

          At September 30, 2001, Cleco Power had an accumulated deferred fuel liability of $18.0 million as compared to an accumulated deferred fuel asset of $3.6 million at December 31, 2000.  The primary cause of the change in deferred fuel was the sharp decrease in natural gas prices over the nine-month period ending September 30, 2001 as compared to December 31, 2000.  The sharp decrease in natural gas prices caused Cleco Power to overcollect from its customers for fuel costs which results in a liability to its customers.  Under and over collections of fuel costs normally occur and the resulting asset or liability is collected or refunded to customers through the fuel adjustment clauses.

Regulatory Matters - Retail Electric Competition

          The LPSC has been continuing its investigation into whether retail choice is in the best interest of Louisiana electric utility customers.  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 proceedings before the LPSC since 1997.  However, the troubled electric supply situation in California has lead many in the industry to reexamine the restructuring process.  While the 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 believes the situation in California will continue to influence future decisions and plans at both the federal and state 

46

levels, including Louisiana.  Management expects the customer choice debate and other related issues to continue in legislative and regulatory bodies through 2001 and into 2002.  At this time, the Company cannot predict whether any legislation or regulation will be enacted or adopted during 2001 or shortly thereafter and, if enacted, what form such legislation or regulation would take.

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

Regulatory Matters - Wholesale Electric Competition

          In 1999, the FERC issued Order No. 2000, which, together with prior orders issued by the FERC, defines the operation of utilities' transmission systems.  This order establishes a general framework for all transmission-owning entities in the nation to voluntarily place their transmission facilities under the control of an appropriate RTO.  Although participation is voluntary, the FERC has made it clear that any jurisdictional entity not participating in an RTO will be subject to further regulatory directives.  Current objectives state that all electric utilities which own, operate or control interstate transmission facilities should participate in an RTO that will be operational no later than December 15, 2001.

          On October 13, 2000, SPP and Entergy jointly submitted a filing with the FERC outlining their plan to operate their hybrid RTO.  On March 28, 2001, FERC released an order regarding the SPP/Entergy RTO filing.  The FERC raised concerns about the scope and configuration of the proposed RTO, asserting that it did not completely accommodate the area's electricity market under guidelines FERC issued for RTOs last year.  The FERC directed the SPP to file a report by May 25, 2001 to outline how it expects to better meet these guidelines and urged SPP to look for opportunities to expand the RTO.  The SPP filed a report with the FERC on May 25, 2001 that attempted to address the FERC's concerns.

          On July 11, 2001, the FERC issued orders stating its intention to form four regional RTOs covering the Northeast, Southeast, Midwest and West.  The FERC ordered industry parties to participate in mediation proceedings to develop the Northeast and Southeast RTOs.  The FERC also formally rejected the SPP RTO proposal.  SPP has been ordered to participate in the mediation proceedings of the Southeast RTO as well as consider potential membership in the Midwest RTO.  The SPP has since removed itself from the mediation efforts of the Southeast RTO and begun discussions with the Midwest RTO.  Although the Company had earlier indicated that it would join the SPP's RTO, it is currently unclear whether Cleco Power will or will not remain a member of SPP.  Additionally, while the FERC has confirmed its intention to 

47

pursue the development of these large RTOs, 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 to show cause for why they should not be enjoined from transferring ownership or control of their bulk transmission assets, paid for by jurisdictional ratepayers, to another entity, such as an RTO.  This order also requires that Cleco Power and other 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 additionally states that the proceedings should, if at all possible, be concluded by December, 2001.  Management is currently evaluating the order, but the impact to Cleco Power's financial position has not been identified.

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

          Wholesale energy markets, including the market for wholesale electric power, have been competitive and are becoming even more so as the number of participants in these markets increases as a result of enactment of the Energy Policy Act and the regulatory activities of the FERC.

          No federal legislation was passed during the 2001 legislative session, although several bills were proposed that addressed both restructuring of the industry and transmission reliability issues.  Several of these bills in various new forms, as well as several new proposals, have been introduced and are being actively debated within Congress.  The Company cannot predict what future legislation may be proposed and/or passed and what effect it may have upon its results of operations or financial condition.

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 may vary from 10 years to 50 years.  In the past, Cleco Power has been substantially successful in the timely renewal of franchises as each reaches the end of its term.  In October 2001, the franchise with the city of Washington for its 1,891 customers was successfully renewed for a term of 25 years.

48

 NEW POWER PLANTS

          APP is a joint venture between Midstream and Calpine that is in the process of constructing a combined cycle, natural gas-fired power plant near Eunice, Louisiana.  Construction on the plant has begun, with a projected completion date of mid-2002.  Total construction costs of the plant to be incurred by APP are estimated to be approximately $564.00 million.  As of September 30, 2001 APP has spent $394.8 million on constructing the plant.  Long-term non-recourse financing is expected to be received in the first quarter of 2002.  APP is owned 50% by Midstream and 50% by Calpine.  The investment in APP is being accounted for using the equity method of accounting by the Company.  As of September 30, 2001, Midstream had contributed $199.9 million in cash and land to APP.

         APP has entered into a tolling agreement with Aquila Energy for 580 MW of capacity starting on July 1, 2002, and continuing for 20 years.  Under the tolling agreement, Aquila will supply the natural gas required to generate 580 MW and will own the electricity.  The agreement requires Aquila Energy to pay APP various capacity reservation fees, the price of which depends upon the type of capacity and ultimate availability declared by APP.  In addition to the capacity reservation payments from Aquila Energy, APP will collect revenues associated with both fixed and variable operating and maintenance expenses anticipated at the Acadia facility.  Tolling revenues are primarily affected by the availability of the APP power plant to operate and other characteristics of the plant.

        On July 30, 2001, APP executed the Acadia Calpine Tolling Agreement with Calpine Energy Services.  Under the terms of the agreement, for 20 years Calpine Energy Services will provide the natural gas needed to generate 580 MW of electricity at the Acadia facility and will have the right to own and market the electricity produced.  The agreement requires Calpine to pay APP various capacity reservation fees, the price of which depends upon the type of capacity and ultimate availability declared by APP.  In addition to the capacity reservation payments from Calpine, APP will collect revenues associated with both fixed and variable operating and maintenance expenses anticipated at the Acadia facility.  Tolling revenues are primarily affected by the availability of the APP power plant to operate and other characteristics of the plant.

          PEP is a joint venture between Midstream and Mirant that is in the process of constructing a 700 MW combined-cycle, natural gas-fired power plant in Perryville, Louisiana.  Total construction cost of the plant to be incurred by PEP are estimated to be $340.0 million.  As of September 30, 2001, PEP had incurred $206.1 million on constructing the plant.  Long-term non-recourse financing was received during the month of June 2001.  A 150 MW combustion turbine operating in simple cycle became operational on July 1.  Full commercial operation in combined cycle is expected for the summer of 2002.  The investment in PEP is accounted for using the equity method of accounting by the Company.  As of September 30, 2001, the difference of $2.0 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 b y SFAS No. 58.  The reduction of Midstream's investment in PEP and member's equity as reported on PEP's balance sheet is due to the long-term non-recourse financing that occurred during June 2001 and a subsequent distribution from PEP to Midstream.

 49

          On April 30, 2001, PEP announced the signing of a long-term power purchase agreement for the output of its 700-MW facility, the Perryville Power Station.  The 20-year contract is with Mirant Marketing, Mirant's risk management, trading and marketing organization.  Under the terms of the contract, Mirant Marketing will supply the natural gas needed to fuel the plant and will own the plant's output.  The agreement requires Mirant to pay PEP various capacity reservation fees, the price of which depends upon the type of capacity and ultimate availability declared by PEP.  In addition to the capacity reservation payments from Mirant, PEP will collect revenues associated with both fixed and variable operating and maintenance expenses anticipated at the Perryville facility.  Tolling revenues are primarily affected by the availability of the PEP power plant to operate and other characteristics of the plant.

CONSTRAINTS ON PURCHASED POWER

          In future years, Cleco Power's generating facilities may not supply enough electric power to meet its customers' growing demand (native load demand) and it may need to purchase additional generating capacity and/or purchase power to satisfy these needs.  In March 2000, following a competitive bid process, Cleco Power entered into three contracts for firm electric capacity and energy with Williams Energy and Dynegy, for 605 MW of capacity in 2000, increasing to 760 MW of capacity in 2004.  These contracts were approved by the LPSC in March 2000.  Management expects to meet substantially all of its native load demand through 2004 with Cleco Power's own generation capacity and the power purchase agreements with Williams Energy and Dynegy.  Because of its location on the transmission grid, Cleco Power relies on one main supplier of electric transmission and is sometimes constrained as to the amo unt of purchased power it can bring into its system.  The power contracts described above are not expected to be affected by such transmission constraints.

NEW ACCOUNTING STANDARDS

          For discussion of new accounting standards, see Note G. - New Accounting Standards in the Notes to the Unaudited Financial Statements in this Report, which is incorporated herein by reference.

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ITEM 3     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
                    RISK OF CLECO CORPORATION

          The market risk inherent in the Company'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 different electricity exchanges, and the commodity price of natural gas traded.  Cleco Power's market risk sensitive instruments and positions are characterized as "trading" under EITF No. 98-10 until used to provide fuel for generation or electricity to its retail utility customers.  When positions are used to secure fuel or power for the customers, the positions are characterized as "other than trading" as defined under EITF No. 98-10.  Substantially all of Marketing & Trading's positions are characterized as "trading" under EITF No. 98-10.  Generally, all of Energy's positions are characterized as "other than trading" under EITF No. 98-10.  T he Company's exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of 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 Rate Risks

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

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

          As of September 30, 2001, the carrying value of the Company's consolidated short-term variable-rate debt was approximately $137.5 million, which approximates the fair market value.  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 $1.4 million in the Company's pretax earnings.

          As of September 30, 2001, the carrying value of Cleco Power's short-term variable-rate debt was approximately $44.3 million, which approximates the fair market value.  Each 1.0% change in the average interest rates applicable to such debt would result in a change of approximately $0.4 million in Cleco Power's pretax earnings.

          The Company 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,

51

refinancing balances outstanding under its variable-rate commercial paper program with fixed-rate debt.

Commodity Price Risks

          Management believes the Company 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 VAR and current market conditions.  The Company'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 the Company's financial statements.  The net marked-to-market figure of trading positions of Marketing & Trading at September 30, 2001 was a loss of $0.3 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 September 30, 2001, the net marked-to-market figure for those positions was a loss of $0.8 million.

          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.  Energy's positions are considered as "other than trading" and changes in market values are not reflected in the income statement.  The positions are considered cash flow hedges under SFAS No. 133, as amended, and changes in market values of the positions are reflected in the statement of Other Comprehensive Income.

          Marketing & Trading, Cleco Power and 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.

52

          Based on these assumptions, the high, low and average VAR during the three months and for the nine months ended September 30, 2001, as well as the VAR at September 30, 2001, is summarized below:

	For the three months ended September 30, 2001			At
	High	Low	Average	September 30, 2001
	(Thousands)
Marketing & Trading	$  3,626.9	$  397.1	$  1,378.9	$     625.6
Cleco Power	$  1,225.3	$  194.6	$     606.4	$     215.4
Energy	$     352.0	$  130.1	$     189.9	$     162.1
Consolidated	$  4,567.6	$  918.9	$  2,175.2	$  1,003.1
	For the nine months ended September 30, 2001
	High	Low	Average
	(Thousands)
Marketing & Trading	$  4,056.8	$  166.7	$  1,543.8
Cleco Power	$  1,422.3	$    12.0	$     407.6
Energy	$     352.0	$      2.3	$     142.0
Consolidated	$  4,567.6	$  546.7	$  2,046.0

53

PART II

ITEM 1     LEGAL PROCEEDINGS

          For a description of legal proceedings affecting the Company, please review Note F - LDEQ Litigation, in the Notes to the Unaudited Financial Statements in this Report, which description is incorporated herein by reference.

ITEM 6     EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits
	Cleco Corporation:
	10	Form of Notice and Acceptance of Directors' Grant of Nonqualified Stock Options
	11(a)	Computation of Net Income Per Common Share for the three months ended September 30, 2001
	11(b)	Computation of Net Income Before Extraordinary Item Per Common Share for the nine months ended September 30, 2001
	11(c)	Computation of Net Income Per Common Share for the nine months ended September 30, 2001
	12(a)	Computation of Ratio of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends for the three, nine and twelve month periods ended September 30, 2001, for Cleco Corporation
	Cleco Power:
	12(b)	Computation of Ratio of Earnings to Fixed Charges for the three, nine and twelve month periods ended September 30, 2001, for Cleco Power
(b)	Reports on Form 8-K
	Cleco Corporation:
	None
	Cleco Power:
	None

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SIGNATURE

          Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

    CLECO CORPORATION

                 (Registrant)

By:   /s/ R. Russell Davis        

        R. Russell Davis

        Vice President and Controller

        (Principal Accounting Officer)

Date: November 13, 2001

55

SIGNATURE

          Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

    CLECO POWER LLC

                 (Registrant)

By:   /s/ R. Russell Davis        

        R. Russell Davis

        Vice President and Controller

        (Principal Accounting Officer)

Date: November 13, 2001

56

EX-11

Exhibit 11(a)

CLECO CORPORATION
COMPUTATION OF NET INCOME PER COMMON SHARE
(UNAUDITED)

	For the three months ended September 30
	2001	2000
	(Thousands, except share and per share amounts)
BASIC
Net income applicable to common stock	$        30,595	$       29,677
	=========	========
Weighted average number of shares of common      stock outstanding during the period	45,004,241	44,976,074
	=========	========
Basic net income per common share	$             .68	$            .66
	=========	========
DILUTED
Net income applicable to common stock	$        30,595	$       29,677
Adjustments to net income related to Employee    Stock Ownership Plan (ESOP) under the    "if-converted" method:
Add loss of deduction from net income for actual    dividends paid on convertible preferred stock,    net of tax	329	338
Add/(Deduct) additional cash contribution    required, which is equal to dividends    on preferred stock less dividends    paid at the common dividend rate, net    of tax	(13)	1
Add tax benefit associated with dividends    paid on allocated common shares	138	120
Adjusted income applicable to common stock	$        31,049	$      30,136
	=========	========
Weighted average number of shares of common    stock outstanding during the period	45,004,241	44,976,074
Number of equivalent common shares    attributable to ESOP	2,530,335	2,597,904
Common stock under stock option grants	188,214	88,266
Average shares	47,722,790	47,662,244
	=========	========
Diluted net income per common share	$             .65	$            .63
	=========	========

EX-11

Exhibit 11(b)

CLECO CORPORATION
COMPUTATION OF NET INCOME BEFORE EXTRAORDINARY ITEM
PER COMMON SHARE
(UNAUDITED)

EX-11

Exhibit 11(c)

CLECO CORPORATION
COMPUTATION OF NET INCOME PER COMMON SHARE
(UNAUDITED)

EX-12

Exhibit 12(a)

CLECO CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS (UNAUDITED)

EX-12

Exhibit 12(b)

CLECO POWER
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(UNAUDITED)