Cleco 2nd Quarter 2001 10-Q

10-Q 1 cleco2nd-qtr10q2001.htm CLECO CORP & CLECO POWER 2ND QTR 10-Q 2001 Cleco 2nd Quarter 2001 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 1934

For the quarterly period ended June 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 July 31, 2001
Cleco Corporation	Common Stock, $1.00 Par Value	44,999,368

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 ...........................................	4

PART I

ITEM 1 FINANCIAL STATEMENTS
Cleco Corporation Consolidated Financial Statements.............................................	6
Cleco Corporation - Results of Operations..............................................................	15
Cleco Power LLC Financial Statements..................................................................	29
Cleco Power LLC- Narrative Analysis of the Results of Operations.........................	34
Notes To Financial Statements................................................................................	40

ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CLECO CORPORATION..............................................................	52

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK OF CLECO CORPORATION..................	59


PART II

ITEM 1 LEGAL PROCEEDINGS ....................................................................	62

ITEM 2 CHANGES IN SECURITIES AND USE OF PROCEEDS ...............	62

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ............................................................................................	62

ITEM 5 OTHER INFORMATION ..................................................................	63

ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K ...................................	64


Signatures ................................................................................................................	65

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
1935 Act.................................................	Public Utility Holding Company Act of 1935
Acadia Aquila Tolling Agreement..............	Capacity Sale and Tolling Agreement between APP and Aquila Energy
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. 18............................................	Accounting Principles Board Opinion No. 18 - The Equity Method of Accounting for Investments in Common Stock
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
CPS........................................................	Coughlin Power Station
DIG........................................................	Derivatives Implementation Group of the FASB
Dynegy....................................................	Dynegy Power Marketing, Inc.
DHLC.....................................................	Dolet Hills Lignite Company, LLC
DHMV....................................................	Dolet Hills Mining Venture
Dolet Hills...............................................	Dolet Hills Power Station
Dolet Hills Mine.......................................	Lignite reserves located in the Dolet Hills area of northwestern Louisiana
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
Federal Court Suit......................................	Lawsuit filed by the Company and SWEPCO on April 15, 1997, against DHMV and its partners in the United States District Court for the Western District of Louisiana
FERC........................................................	Federal Energy Regulatory Commission
KW...........................................................	Kilowatt
KWh..........................................................	Kilowatt-hour
LDEQ.........................................................	Louisiana Department of Environmental Quality
LMA..........................................................	Lignite Mining Agreement
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
OCI............................................................	Other Comprehensive Income
PEP............................................................	Perryville Energy Partners LLC
PEP-related Petitioners................................	Various citizens and community action groups
Quanta........................................................	Quanta Services, Inc.
RTO...........................................................	Regional Transmission Organization
Rodemacher................................................	Rodemacher Power Station
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. 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. 137...........................................	Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133
SFAS No. 138...........................................	Accounting for Certain Derivative Instruments and Certain Hedging Activities
SPP............................................................	Southwest Power Pool

State Court Suit..........................................	Lawsuit filed by the Company and SWEPCO on August 13, 1997, against the parent companies of DHMV in the First Judicial District Court for Caddo Parish, Louisiana
SWEPCO..................................................	Southwestern Electric Power Company
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

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 results 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.

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 several of the Company's subsidiaries, the results of operations for the three months and six months ended June 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 Cleco Corporation 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.

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

	2001	2000
	(Thousands, except share and per share amounts)
Operating revenue:
Retail electrical operations	$ 173,547	$ 145,728
Energy marketing and tolling operations	131,984	40,444
Other operations	102	459
Gross operating revenue	305,633	186,631
Less: retail electric customer credits	1,933	9
Total operating revenue	303,700	186,622
Operating expenses:
Fuel used for electric generation	63,972	42,771
Power purchased for utility customers	30,020	25,531
Purchases for energy marketing operations	119,366	32,277
Other operations	23,673	19,608
Maintenance	7,948	8,117
Depreciation	15,379	12,497
Taxes other than income taxes	9,653	9,188
Total operating expenses	270,011	149,989
Operating income	33,689	36,633
Interest income	487	260
Allowance for other funds used during construction	332	285
Other income (expense), net	96	539
Income before interest charges	34,604	37,717
Interest charges:
Interest charges, including amortization of debt expenses, premium and discount	12,908	9,884
Allowance for borrowed funds used during construction	(298)	(114)
Total interest charges	12,610	9,770
Net income from continuing operations before income taxes and preferred dividends	21,994	27,947
Federal and state income taxes	7,924	9,435
Net income from continuing operations	14,070	18,512
Discontinued operations:
Loss from operations, net of income taxes	-	1,597
Loss on disposal of segment, net of income taxes	1,062	-
Total discontinued operations	1,062	1,597
Net income before preferred dividends	13,008	16,915
Preferred dividend requirements, net	407	461
Net income applicable to common stock	$ 12,601	$ 16,454
	======	======

(Continued on next page)

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

	2001		2000
	(Thousands, except share and per share amounts)
Average shares of common stock outstanding:
Basic	45,022,622		44,937,734
Diluted	47,813,125		47,589,482

Basic earnings per share:
From continuing operations	$	0.30	$	0.40
From discontinued operations	$	(0.02)	$	(0.03)
Net income applicable to common stock	$	0.28	$	0.37

Diluted earnings per share:
From continuing operations	$	0.29	$	0.39
From discontinued operations	$	(0.02)	$	(0.03)
Net income applicable to common stock	$	0.27	$	0.36

Cash dividends paid per share of common stock	$	0.2175	$	0.2125

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
For the six months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands, except share and per share amounts)
Operating revenue:
Retail electrical operations	$ 329,533	$ 259,023
Energy marketing and tolling operations	229,013	65,327
Other operations	198	591
Gross operating revenue	558,744	324,941
Less: retail electric customer credits	1,933	1,225
Total operating revenue	556,811	323,716
Operating expenses:
Fuel used for electric generation	124,369	74,049
Power purchased for utility customers	57,673	40,044
Purchases for energy marketing operations	198,097	56,554
Other operations	47,717	33,407
Maintenance	15,258	15,686
Depreciation	30,779	24,892
Taxes other than income taxes	19,100	18,260
Total operating expenses	492,993	262,892
Operating income	63,818	60,824
Interest income	1,366	452
Allowance for other funds used during construction	504	656
Other income (expense), net	82	744
Income before interest charges	65,770	62,676
Interest charges:
Interest charges, including amortization of debt expenses, premium and discount	26,046	19,311
Allowance for borrowed funds used during construction	(494)	(238)
Total interest charges	25,552	19,073
Net income from continuing operations before income taxes and preferred dividends	40,218	43,603
Federal and state income taxes	14,048	14,303
Net income from continuing operations	26,170	29,300
Discontinued operations:
Loss from operations, net of income taxes	-	2,163
Loss on disposal of segment, net of income taxes	2,468	-
Total discontinued operations	2,468	2,163
Net income before extraordinary item	23,702	27,137
Extraordinary item, net of income taxes	-	2,508
Net income before preferred dividends	23,702	29,645
Preferred dividend requirements, net	880	934
Net income applicable to common stock	$ 22,822	$ 28,711
	=======	=======

(Continued on next page)

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Continued)
For the six months ended June 30
(UNAUDITED)

	2001		2000
	(Thousands, except share and per share amounts)
Average shares of common stock outstanding:
Basic	45,012,715		44,914,866
Diluted	47,854,663		47,577,524

Basic earnings per share:
From continuing operations	$	0.56	$	0.63
From discontinued operations	$	(0.05)	$	(0.05)
Extraordinary item	$	-	$	0.06
Net income applicable to common stock	$	0.51	$	0.64

Diluted earnings per share:
From continuing operations	$	0.55	$	0.62
From discontinued operations	$	(0.05)	$	(0.05)
Extraordinary item	$	-	$	0.05
Net income applicable to common stock	$	0.50	$	0.62

Cash dividends paid per share of common stock	$	0.43	$	0.42

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

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	At	At
	June 30, 2001	December 31, 2000
	(Thousands)
Assets

Current assets:
Cash and cash equivalents	$ 6,552	$ 29,407
Accounts receivable, net	98,758	74,620
Other accounts receivable	20,943	24,200
Unbilled revenues	33,982	37,547
Fuel inventory, at average cost	12,901	7,275
Materials and supplies inventory, at average cost	15,765	15,956
Margin deposits	15,433	21,657
Risk management assets	23,390	19,070
Accumulated deferred fuel	-	3,617
Other current assets	5,274	4,857
Total current assets	232,998	238,206

Property, plant and equipment:
Property, plant and equipment	1,809,066	1,799,161
Accumulated depreciation	(631,746)	(604,145)
Net property, plant and equipment	1,177,320	1,195,016
Construction work-in-progress	51,406	37,742
Total property, plant and equipment, net	1,228,726	1,232,758

Equity investment in investees	164,794	98,204
Other assets	7,000	2,642
Prepayments	17,651	16,766
Restricted cash	27,659	55,343
Regulatory assets - deferred taxes	96,764	100,267
Other deferred charges	44,625	45,010
Accumulated deferred federal and state income taxes	60,654	56,508

Total assets	$ 1,880,871	$ 1,845,704
	========	========

(Continued on next page)

CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS (Continued)
(UNAUDITED)

	At	At
	June 30, 2001	December 31, 2000
	(Thousands)
Liabilities and shareholders' equity

Current liabilities:
Short-term debt	$ 130,417	$ 95,957
Long-term debt due within one year	15,285	30,665
Accounts payable	93,931	102,838
Retainage	8,200	8,770
Customer deposits	20,704	20,447
Taxes accrued	33,898	17,286
Interest accrued	15,216	15,177
Risk management liabilities	31,311	21,118
Accumulated deferred fuel	9,051	-
Other current liabilities	5,348	12,997
Total current liabilities	363,361	325,255

Deferred credits:
Accumulated deferred federal and state income taxes	267,318	270,118
Accumulated deferred investment tax credits	23,370	24,252
Regulatory liabilities - deferred taxes	37,852	38,840
Other deferred credits	48,142	48,089
Total deferred credits	376,682	381,299
Long-term debt, net	657,053	659,135

Total liabilities	1,397,096	1,365,689

Shareholders' equity:
Preferred stock
Not subject to mandatory redemption	27,403	28,090
Deferred compensation related to preferred stock held by ESOP	(11,602)	(12,994)
Total preferred stock not subject to mandatory redemption	15,801	15,096
Common shareholders' equity:
Common stock, $1 par value, authorized 100,000,000 shares, issued 45,070,408 and 45,063,740 shares at June 30, 2001 and December 31, 2000, respectively	45,071	45,064
Premium on capital stock	112,001	112,502
Long-term debt payable in Company's common stock	519	519
Retained earnings	311,606	308,047
Other comprehensive income	428	-
Treasury stock, at cost, 75,391 and 73,072 shares at June 30, 2001 and December 31, 2000, respectively	(1,651)	(1,213)
Total common shareholders' equity	467,974	464,919

Total shareholders' equity	483,775	480,015
Total liabilities and shareholders' equity	$ 1,880,871	$ 1,845,704
	========	========

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the six months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands)
OPERATING ACTIVITIES:
Net income before preferred dividends	$ 23,702	$ 29,645
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Loss on disposal of segment, net of tax	639	-
Loss from discontinued operation, net of tax	-	2,163
Depreciation and amortization	31,228	26,381
Allowance for funds used during construction	(504)	(656)
Amortization of investment tax credits	(882)	(871)
Net deferred income taxes	4,734	1,383
Deferred fuel costs	12,668	(9,469)
Extraordinary gain, net of income tax	-	(2,508)
Changes in assets and liabilities:
Accounts receivable, net	(24,098)	(23,819)
Unbilled revenues	1,330	(12,235)
Fuel inventory, materials and supplies	(5,521)	2,863
Accounts payable	(8,610)	(10,275)
Customer deposits	257	199
Other deferred accounts	(6,153)	(436)
Taxes accrued	18,562	21,415
Interest accrued	39	6,255
Margin deposits	6,224	(4,794)
Risk management assets and liabilities, net	5,873	999
Other, net	(13,805)	(8,745)
Net cash provided by operating activities	45,683	17,495

INVESTING ACTIVITIES:
Additions to property, plant and equipment	(25,347)	(70,613)
Allowance for funds used during construction	504	656
Proceeds from sale of property, plant and equipment	465	114
Proceeds from disposal of segment	4,590	-
Equity investment in investees	(70,577)	(28,880)
Net cash used in investing activities	(90,365)	(98,723)

FINANCING ACTIVITIES:
Cash transferred from restricted account	27,684	19,540
Change in short-term debt, net	34,460	(5,112)
Retirement of long-term obligations	(17,317)	(2,100)
Issuance of long-term debt	-	101,070
Extinguishment of operating lease from disposal of segment	(2,761)	-
Dividends paid on common and preferred stock, net	(20,239)	(19,802)
Net cash provided by financing activities	21,827	93,596

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(22,855)	12,368
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	29,407	25,161
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 6,552	$ 37,529
	=======	======
Supplementary cash flow information
Interest paid (net of amount capitalized)	$ 30,464	$ 16,534
	=======	======
Income taxes paid	$ 7,000	$ 1,000
	=======	======

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

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

	2001	2000
	(Thousands)
Net income applicable to common stock	$ 12,601	$ 16,454
Other comprehensive income, net of tax
Net unrealized gains from derivative instruments	521	-
Net other comprehensive income	521	-
Comprehensive income	$ 13,122	$ 16,454
	======	======

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

CLECO CORPORATION
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
For the six months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands)
Net income applicable to common stock	$ 22,822	$ 28,711
Other comprehensive income (expense), net of tax
Transition adjustment from implementation of SFAS No. 133	(4,453)	-
Net unrealized gains from derivative instruments	4,881	-
Net other comprehensive income	428	-
Comprehensive income	$ 23,250	$ 28,711
	======	======

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

CLECO CORPORATION - RESULTS OF OPERATIONS

Set forth below is information concerning the consolidated results of operations of Cleco Corporation for the three months ended June 30, 2001, and June 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 June 30, 2001 and 2000

Net income from continuing operations in the second quarter of 2001 was $14.1 million, down 24.0% from the same period 2000. The decline was due primarily to trading losses posted in both the Midstream and Cleco Power trading operations. An additional $1.1 million loss from discontinued operations was recorded during the 2001 second quarter, reflecting final expenses associated with the company's March 3, 2001 sale of UtiliTech, bringing net income applicable to common stock to $12.6 million, down 23.4% from the same period in 2000.

	For the three months ended June 30
	2001	2000	Variance	Change
		(Thousands)
Operating revenues	$ 303,700	$ 186,622	$ 117,078	62.7 %
Operating expenses	$ 270,011	$ 149,989	$ (120,022)	(80.0)%
Net income from continuing operations	$ 14,070	$ 18,512	$ (4,442)	(24.0)%
Loss from discontinued operations, net	$ 1,062	$ 1,597	$ 535	33.5 %
Net income applicable to common stock	$ 12,601	$ 16,454	$ (3,853)	(23.4)%

Consolidated net income from continuing operations decreased 24.0% in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to decreased earnings at Cleco Power, which were partially offset by increased earnings at Midstream. Net income from continuing operations from Cleco Power and Marketing & Trading decreased $4.4 million and $2.9 million, respectively, in the second quarter of 2001 as compared to the second quarter of 2000 largely due to lower margins on energy marketing and trading functions that were caused in part by mark-to-market losses. Offsetting these decreases was a $2.9 million increase in net income from continuing operations at Evangeline, which commenced full commercial operations in July 2000.

Increased operating revenues for the second quarter of 2001 as compared to the second quarter of 2000 were due primarily to an $80.3 million increase in energy marketing and tolling operations at Midstream and an increase of $32.9 million in revenues at Cleco Power. The increase of $80.3 million in revenues at Midstream in the second quarter of 2001 as compared to the second quarter of 2000 is due to a $63.6 million increase in energy trading revenues at Marketing & Trading, a $4.4 million increase in energy trading revenues at Energy and a $12.3 million increase in tolling revenues at Evangeline. The increase of $32.9 million in revenues at Cleco Power is due to a $26.7 million increase in fuel cost recovery revenues, a $11.2 million

increase in energy marketing revenues and a $1.1 million increase in base revenues. The increase in revenue at Cleco Power was offset by a increase in the estimated customer credit of $1.9 million and a decrease of $4.2 million in affiliate revenue.

The 80.0% increase in operating expenses for the second quarter of 2001 as compared to the second quarter 2000 was caused mainly by increased purchases for energy marketing and additional depreciation at Midstream and increased fuel and purchased power expenses at Cleco Power. Purchases for energy marketing at Midstream increased $71.5 million in the second quarter of 2001 as compared to the second quarter of 2000 due to a $68.3 million increase in purchases for energy marketing at Marketing & Trading and a $3.2 million increase in purchases for energy marketing at Energy. Depreciation at Midstream increased $2.5 million in the second quarter of 2001 as compared to the second quarter of 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 $25.7 million in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to an increase in natural gas prices and an increase in purchased power.

Discontinued operations at UtiliTech reduced second quarter 2001 earnings by $1.1 million or $0.02 per basic average common share. For additional information, see Note I. - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this report.

MIDSTREAM

Midstream net income for the second quarter of 2001 increased $0.4 million as compared to the same period in 2000. Evangeline contributed $3.1 million for the second quarter of 2001, compared to $0.2 million in the second quarter of 2000, which was prior to the plant's full commercial operation. Midstream marketing and trading operations posted a loss of $0.4 million for the second quarter of 2001, compared to a gain of $3.0 million recorded in the second quarter of 2000. Midstream asset and market development activities were a loss of $0.2 million for the second quarter of 2001 as compared to a $1.2 million loss for the same period in 2000.

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 the factors acting in concert or in opposition 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 for the periods indicated.

	For the three months ended June 30
	2001	2000	Change
Electricity marketed (Million kWh)	1,145	216	430.1 %
Natural gas (MMBtu)	2,893,483	3,386,879	(14.6)%

The increase of $59.7 million in revenues in the second quarter of 2001 as compared to the second quarter of 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 $68.3 million in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to the same reasons for the increase in revenues. Marketing & Trading experienced a 21.3% increase in its average per unit cost of natural gas and a 95.3% increase in its average cost of purchased power in the second quarter of 2001 as compared to the second quarter of 2000.

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 periods indicated.

	For the three months ended June 30
	2001	2000	Change
Natural gas marketed (MMBtu)	2,402,927	2,006,011	19.8%

The increase of $2.1 million in revenues in the second quarter of 2001 as compared to the second 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 49.4% increase in its average per unit cost of natural gas in the second quarter of 2001 as compared to the second quarter of 2000.

Purchases for energy marketing increased $3.2 million in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to the same reasons for the increase in revenues.

Power Plant Operations

Evangeline Power Station was in full commercial operation during the second quarter of 2001 and had tolling revenues of $13.8 million, as compared to the second quarter of 2000, during which Evangeline had begun partial operation and recorded revenues of $1.5 million.

Operating expenses at Evangeline increased $3.0 million during the second quarter of 2001 as compared to the same period in 2000. The increase is due to an increase in operations and maintenance expenses of $1.0 million and an increase of $2.0 million in depreciation related to the plant being in full commercial operation during 2001.

CLECO POWER

Cleco Power's net income was down $4.4 million from the second quarter of 2000. Two-thirds of the decline in income for the second quarter period was due to higher losses posted from trading operations. Cleco Power's mark-to-market losses for the second quarter of 2001 were $1.4 million. Virtually all of the mark-to-market losses are expected to turn around by the end of the year. Base revenues were down 1.4% for the second quarter of 2001, as compared to the same period in 2000, due primarily to the continued moderate weather. Additionally, operating expenses for the second quarter of 2001 were $40.4 million higher compared to the same period in 2000, driven mainly by fuel and power purchased and purchases for energy marketing.

For the three months ended June 30
Operating revenues:	2001	2000	Variance	Change
	(Thousands)
Base	$ 81,663	$ 80,516	$ 1,147	1.4 %
Fuel cost recovery	91,884	65,212	26,672	40.9 %
Affiliate revenue	449	4,624	(4,175)	(90.3)%
Estimated customer credits	(1,933)	(9)	(1,924)	-
Energy marketing	13,948	2,722	11,226	412.4 %
Total operating revenues	$ 186,011	$ 153,065	$ 32,946	21.5 %
	=======	========	=======

	For the three months ended June 30
	2001	2000	Change
	(Millions kWh)
Electric sales
Residential	795	805	(1.2)%
Commercial	440	443	(0.7)%
Industrial	669	740	(9.6)%
Other retail	153	155	(1.3)%
Total Retail	2,057	2,143	(4.0)%
Sales for resale	91	112	(18.7)%
Total sales to regular customers	2,148	2,255	(4.7)%
Short-term sales to other utilities	35	8	337.5 %
Sales from marketing activities	1	4	(75.0)%
Total electric sales	2,184	2,267	(3.7)%
	=====	=====

Base revenues during the second quarter of 2001 show a slight increase over the same period in 2000. Base revenues from energy sales decreased $0.8 million. Offsetting this decrease was an increase of $1.1 million in transmission revenues and a $0.8 million increase in miscellaneous 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. 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 second quarters of 2001 and 2000.

Cooling degree days For the three months ended June 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	15.2 %	8.4 %
Increase/(Decrease) from Prior Year	6.4 %	(10.4)%

The majority of the increase in cooling degree days can be attributed to April which accounted for greater than 80% of the total increase for the quarter. April is a low usage month and customers are billed at lower winter rates therefore a corresponding increase in revenue was not obtained.

Short-term sales to other utilities increased significantly during the second 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 December 2000 and sales to the City of Ruston, to supply all of its power, under a three-year contract 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 $3.19 per MMBtu in the second quarter of 2001 compared to $2.57 per MMBtu in the same period in 2000. The increase in the average per unit cost of fuel is primarily a result of a 29.3% increase in the per unit cost of natural gas for the second 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 costs 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 second quarter of 2001 were decreased by a $1.9 million accrual for estimated customer credits compared to the second quarter of 2000 when a small accrual was made. 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 L. - Estimated Customer Credits in the notes to the Unaudited Financial Statements in the Report.

price of natural gas in the second quarter of 2001. 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 "marked-to-market". The mark-to-market related to these open positions was a loss of $1.4 million in the second quarter of 2001 compared to a gain of $1.0 million in the same period of 2000.

Energy Marketing Operations For the three months ended June 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 15,378	$ 1,683	$ 13,695	813.7 %
Mark-to-market	(1,430)	1,039	(2,469)	(237.6)%
Total	$ 13,948	$ 2,722	$ 11,226	412.4 %
	======	=======	======
Energy trading expenses	$ 16,182	$ 600	$ 15,582	-
	======	=======	======

Operating expenses increased $40.4 million or 33.6% during the second quarter of 2001 compared to the same period in 2000. The increase in operating expenses is primarily the result of increased capacity charges and higher fuel costs. Energy marketing expenses increased $15.6 million in the second quarter of 2001 compared to the same period in 2000 due to the same described reasons above for increases in energy marketing revenues. The increase of $25.7 million in fuel and purchased power for utility operations is due to increased energy prices primarily driven by increases in natural gas prices as compared to the same period in 2000. The 12.4% increase in the second quarter of 2001 as compared to the second quarter of 2000 in other operations expense is due primarily to a $1.4 million increase in capacity payments.

OTHER

Interest expense in the second quarter of 2001 increased $3.0 million or 30.6% compared to the second quarter of 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 full commercial operations of Evangeline in July 2000, interest has been reflected in interest expense. Interest charges related to Evangeline in the second quarter of 2001 were $4.8 million.

Federal and state income taxes decreased $1.5 million in the second quarter of 2001 compared to the same period in 2000. This decrease is mainly attributable to lower earnings at Cleco Power and Marketing & Trading, which were partially offset by increased earnings at Evangeline.

Discontinued operations at UtiliTech reduced second quarter 2001 earnings by $1.1 million or $0.02 per basic average common share. For additional information, see Note I - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this report.

Set forth below is information concerning the consolidated results of operations of Cleco Corporation for the six months ended June 30, 2001, and June 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 Six Months Ended June 30, 2001 and 2000

Net income from continuing operations for the six months ended June 30, 2001 were $26.2 million, down 10.7% from the same period 2000. The decline was due primarily to trading losses posted in both the Midstream and Cleco Power trading operations. An additional $2.5 million loss from discontinued operations was recorded during the first six months of 2001, reflecting final expenses associated with the company's March 31, 2001 sale of UtiliTech , bringing net income applicable to common stock to $22.8 million, down 20.5% from the same period in 2000.

	For the six months ended June 30
	2001	2000		Variance	Change
	(Thousands)
Operating revenues	$ 556,811		$ 323,716	$ 233,095	72.0 %
Operating expenses	$ 492,993		$ 262,892	$ (230,101)	(87.5)%
Net income from continuing operations	$ 26,170		$ 29,300	$ (3,130)	(10.7)%
Loss from discontinued operations, net	$ 2,468		$ 2,163	$ (305)	(14.1)%
Extraordinary item, net	$ -		$ 2,508	$ (2,508)	(100.0)%
Net income applicable to common stock	$ 22,822		$ 28,711	$ (5,889)	(20.5)%

Consolidated net income from continuing operations decreased 10.7% for the six months ended June 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 $5.9 million for the six months ended June 30, 2001 as compared to the same period in 2000, largely due to higher margins on energy marketing and trading functions at Marketing & Trading and the tolling operations of Evangeline, which commenced full commercial operations in July 2000. Offsetting the increase at Midstream was an $8.3 million decrease in net income from continuing operations from Cleco Power due primarily to higher capacity costs related to purchased power agreements and mark-to-market losses on trading positions.

Increased operating revenues for the six-months ended June 30, as compared to the same period in 2000, were due primarily to a $160.7 million increase in energy marketing and tolling operations at Midstream and an increase of $67.2 million in revenues at Cleco Power. The increase of $160.7 million in revenues at Midstream for the six months ended June 30, 2001 as compared to the same period in 2000 is due to a $110.7 million increase in energy trading revenues at Marketing & Trading, a $27.7 million increase in energy trading revenues at Energy and a $22.3 million increase in tolling revenues at Evangeline. The increase of $67.2 million in revenues at Cleco Power is due to a $68.1 million increase in fuel cost recovery revenues, a $3.0 million increase in energy marketing revenues and a $2.4 million increase in base revenues. The

increase in revenues at Cleco Power was offset by an increase in the estimated customer credit of $0.7 million and a decrease of $5.6 million in affiliate revenues.

The 87.5% increase in operating expenses for the six months ended June 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 $132.9 million for the six months ended June 30, 2001 as compared to the same period in 2000 due to a $108.9 million increase in purchases for energy marketing at Marketing & Trading and a $24.0 million increase in purchases for energy marketing at Energy. Depreciation at Midstream increased $5.1 million for the six months ended June 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 $68.0 million for the six months ended June 30, 2001 as compared to the same period in 2000 due primarily to an increase in natural gas prices.

Discontinued operations at UtiliTech reduced the six months ending June 30, 2001 earnings by $2.4 million or $0.05 per basic average common share. For additional information, see Note I. - Loss on Disposal of Segment in the Notes to the Unaudited Financial Statements in this report.

There was no extraordinary item for the six months ended June 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

Midstream's net income from continuing operations for the six months ended June 30, 2001 increased $5.9 million as compared to the same period in 2000. Evangeline has contributed $3.9 million for the first six months of 2001, compared to a $0.6 million loss recorded in the first six months of 2000 prior to its full commercial operation. Midstream's marketing and trading operation has net income of $3.2 million, an increase of $0.6 million over the results during the first six months of 2000. Midstream asset development and administrative activities for the six months ended June 30, 2001 are a loss of $1.3 million as compared to a loss of $2.1 million for the same period in 2000.

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 combination and intensity of the factors acting in concert or in opposition will affect 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.

	For the six months ended June 30
	2001	2000	Change
Electricity marketed (Million kWh)	1,466	604	142.7 %
Natural gas (MMBtu)	4,595,928	5,130,395	(10.4)%

The increase of $107.0 million in revenues for the six months ended June 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 $108.9 million for the six months ended June 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 78.6% increase in its average per unit cost of natural gas and a 97.6% increase in its average cost of and purchased power, for the six months ended June 30, 2001 as compared to the same period in 2000.

Energy

	For the six months ended June 30
	2001	2000	Change
Natural gas marketed (MMBtu)	5,877,509	4,172,374	40.9%

The increase of $27.0 million in revenues for the six months ended June 30, 2001 as compared to the same period in 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 113.4% increase in its average per unit cost of natural gas for the six months ended June 30, 2001 as compared to the same period in 2000.

Purchases for energy marketing increased $24.0 million for the six months ended June 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 operations during the six months ended June 30, 2001 and had tolling revenues of $23.8 million, as compared to the same period in 2000, when Evangeline began partial operations in July and recorded revenues of $1.5 million.

Operating expenses at Evangeline increased $6.3 million during the six months ended June 30, 2001 as compared to the same period in 2000 due to the Evangeline power plant being in full commercial operation during 2001. The increase is due to an increase in operations and maintenance expenses of $2.4 million and an increase of $3.9 million in depreciation

CLECO POWER

Cleco Power's net income for the six months ended June 30, 2001 are $8.3 million lower than the same period in 2000. The decrease was largely due to trading mark-to-market losses and higher utility operating expenses. Utility revenues, excluding fuel, energy marketing and intercompany, are up $1.7 million over the same period in 2000 because of higher transmission and miscellaneous revenue. Higher costs for fuel and power purchased and purchases for energy marketing helped push utility operating expenses up $80.1 million above the same period of 2000. Trading results for the six months ended June 30, 2001 are $5.6 million lower than recorded during the first six months of 2000, but these losses include $2.9 million in mark-to-market losses that are expected to turn around by the end of the year.

	For the six months ended June 30
Operating revenues:		2001	2000	Variance	Change
		(Thousands)
Base		$ 151,969	$ 149,585	$ 2,384	1.6 %
Fuel cost recovery		177,564	109,438	68,126	62.3 %
Affiliate revenue		1,557	7,177	(5,620)	(78.3)%
Estimated customer credits		(1,933)	(1,225)	(708)	(57.8)%
Energy marketing		13,436	10,408	3,028	29.1 %
Total operating revenues		$ 342,593	$ 275,383	$ 67,210	24.4 %
		=======	=======	=======

	For the six months ended June 30
	2001	2000	Change
	(Millions kWh)
Electric sales
Residential	1,480	1,476	0.3 %
Commercial	787	798	(1.4)%
Industrial	1,349	1,488	(9.3)%
Other retail	281	283	(0.7)%
Total Retail	3,897	4,045	(3.7)%
Sales for resale	151	161	(6.2)%
Total sales to regular customers	4,048	4,206	(3.8)%
Short-term sales to other utilities	62	9	588.9 %
Sales from marketing activities	1	69	(98.6)%
Total electric sales	4,111	4,284	(4.0)%
	====	====

Base revenues during the six months ended June 30, 2001 show a slight increase over the same period in 2000. Base revenues from energy sales decreased $0.2 million. Offsetting this decrease was an increase of $1.6 million in transmission revenues and a $1.0 million increase in miscellaneous 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 increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree due to the customers ability to chose 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 six months ended June 30, 2001 and 2000.

Cooling/Heating degree days For the six months ended June 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	10.5 %	18.7 %
Increase/(Decrease) from Prior Year	(6.5)%	(3.4)%
Heating Degree Days:
Increase/(Decrease) from Normal	(2.2)%	(36.0)%
Increase/(Decrease) from Prior Year	51.3 %	9.0 %

Short-term sales to other utilities increased significantly during the six months ended June 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 December 2000 and sales to the City of Ruston, to supply all of its power, under a three-year contract 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 $3.69 per MMBtu for the six months ended June 30, 2001 compared to $2.37 per MMBtu in the same period in 2000. The increase in the average per unit cost of fuel is primarily a result of a 67.5% increase in the per unit cost of natural gas for the six months ended June 30, 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 costs 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. The Company determined that an accrual of $1.9 million was necessary for the six months ended June 30, 2001, compared to $1.2 million for the same period in 2000. The amount of credit due customers, if any, is determined by the LPSC annually based on results for the 12-month period ending September 30 of each year. For additional information see Note L. - Estimated Customer Credits in the notes to the Unaudited Financial Statements in the Report.

Energy marketing revenues for the six months ended June 30, 2001 increased $3.0 million as compared to the same period in 2000. Marketing & Trading markets excess electric capacity and excess natural gas at Cleco Power's power plants on Cleco Power's behalf. 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 six months ended June 30, 2001. 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 "marked-to-market". The mark-to-market related to these open positions was a loss of $2.9 million for the six months ended June 30, 2001 compared to a gain of $0.9 million in the same period of 2000. Virtually all of the mark-to-market losses are expected to turn around by the end of the year.

Energy Marketing Operations For the six months ended June 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 16,303	$ 9,478	$ 6,825	72.0 %
Mark-to-market	(2,867)	930	(3797)	(408.3)%
Total	$ 13,436	$ 10,408	$ 3,028	29.1 %
	======	======	======
Energy trading expenses	$ 16,509	$ 7,893	$ 8,616	109.2 %
	======	======	======

Operating expenses increased $80.1 million or 37.0% during the six months ended June 30, 2001 compared to the same period in 2000. The increase in operating expenses is primarily the result of increased capacity charges and higher fuel costs. Energy marketing expenses increased $8.6 million for the six months ended June 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 $68.0 million due to increased energy prices primarily driven by increases in natural gas prices as compared to the same period in 2000. The 24.7% increase for the six months ended June 30, 2001 as compared to the same period in 2000 in other operations expense is due primarily to a $5.1 million increase in capacity payments.

OTHER

Interest expense for the six months ended June 30, 2001 increased $6.8 million or 34.9% 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 six months ended June 30, 2001 were $9.7 million.

Federal and state income taxes decreased $0.3 million for the six months ended June 30, 2001 compared to the same period in 2000. This decrease is mainly attributable to lower earnings at Cleco Power and Marketing & Trading, which were partially offset by increased earnings at Evangeline.

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

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 six months ended June 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.

CLECO POWER LLC
STATEMENTS OF INCOME
For the three months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands)
Operating revenue:
Retail electric operations	$ 173,547	$ 145,728
Energy marketing operations	13,948	2,722
Affiliate revenues	449	4,624
Gross operating revenue	187,944	153,074
Less: retail electric customer credits	(1,933)	(9)
Total operating revenue	186,011	153,065

Operating expenses:
Fuel used for electric generation	63,972	42,731
Power purchased for utility customer	30,020	25,531
Purchases for energy marketing operations	16,182	600
Other operations	21,382	19,025
Maintenance	7,206	7,392
Depreciation	12,642	12,384
Taxes other than income taxes	8,933	8,990
Affiliate costs	302	3,575
Total operating expenses	160,639	120,228

Operating income	25,372	32,837

Interest income	30	-
Allowance for other funds used during construction	332	285
Other income (expense), net	202	(145)

Income before interest charges	25,936	32,977

Interest charges:
Interest on debt and other, net of amount capitalized	7,211	7,385
Allowance for borrowed funds used during construction	(298)	(114)
Amortization of debt discount, premium and expense, net	225	233
Total interest charges	7,138	7,504

Net income before income taxes	18,798	25,473

Federal and state income taxes	6,452	8,703


Net income applicable to member's equity and common stock	$ 12,346	$ 16,770
	========	========

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

CLECO POWER LLC
STATEMENTS OF INCOME
For the six months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands)
Operating revenue:
Retail electric operations	$ 329,533	$ 259,023
Energy marketing operations	13,436	10,408
Affiliate revenues	1,557	7,177
Gross operating revenue	344,526	276,608
Less: retail electric customer credits	(1,933)	(1,225)
Total operating revenue	342,593	275,383

Operating expenses:
Fuel used for electric generation	124,369	73,990
Power purchased for utility customer	57,673	40,044
Purchases for energy marketing operations	16,509	7,893
Other operations	40,073	32,141
Maintenance	13,623	14,530
Depreciation	25,327	24,662
Taxes other than income taxes	17,879	17,744
Affiliate costs	1,237	5,624
Total operating expenses	296,690	216,628

Operating income	45,903	58,755

Interest income	45	-
Allowance for other funds used during construction	504	656
Other income (expense), net	88	(602)

Income before interest charges	46,540	58,809

Interest charges:
Interest on debt and other, net of amount capitalized	14,514	14,315
Allowance for borrowed funds used during construction	(494)	(238)
Amortization of debt discount, premium and expense, net	449	490
Total interest charges	14,469	14,567

Net income before income taxes	32,071	44,242

Federal and state income taxes	10,901	14,784


Net income applicable to member's equity and common stock	$ 21,170	$ 29,458
	========	========

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

CLECO POWER LLC
Balance Sheets
(UNAUDITED)

	At June 30,	At December 31,
	2001	2000
	(Thousands)
Assets
Utility plant and equipment:
Property, plant and equipment	$ 1,560,243	$ 1,550,756
Accumulated depreciation	(617,645)	(595,136)
Net property, plant and equipment	942,598	955,620
Construction work-in-progress	37,304	25,864
Total utility plant, net	979,902	981,484

Current assets:
Cash and cash equivalents	3,820	2,224
Accounts receivable, net
Customer accounts receivable (less allowance for doubtful accounts of $834 in 2001 and $757 in 2000)	50,036	41,637
Other accounts receivable	19,655	19,878
Affiliates	512	1,457
Notes receivable - affiliates	-	2
Unbilled revenues	30,691	26,863
Fuel inventory, at average cost	12,901	7,275
Material and supplies inventory, at average cost	13,810	14,513
Risk management assets	4,621	525
Margin deposit	4,926	3,128
Accumulated deferred fuel	-	3,617
Other current assets	3,902	3,630
Total current assets	144,874	124,749

Prepayments	8,004	7,974
Regulatory assets - deferred taxes	96,764	100,267
Accumulated deferred federal and state income taxes	56,337	52,144
Other deferred charges	34,345	37,014
Total Assets	$ 1,320,226	$ 1,303,632
	=========	=========

(Continued on next page)

CLECO POWER LLC
BALANCE SHEETS (Continued)
(UNAUDITED)

	At June 30,	At December 31,
	2001	2000
	(Thousands)
Capitalization And Liabilities
Member's equity:
Member's equity units	$ 172,376	$ 172,376
Retained earnings	236,513	234,734
Total member's equity	408,889	407,110

Long-term debt, net	335,429	335,282

Total capitalization	744,318	742,392

Current liabilities:
Short-term debt	63,524	41,397
Long-term debt due within one year	10,000	25,000
Accounts payable	49,355	67,919
Accounts payable - affiliates	4,375	10,846
Customer deposits	20,708	20,447
Taxes accrued	33,390	8,679
Taxes accrued - payable to parent	-	8,161
Interest accrued	8,129	8,021
Risk management liabilities	9,196	1,562
Accumulated deferred fuel	9,050	-
Other current liabilities	2,884	4,933
Total current liabilities	210,611	196,965

Deferred credits
Accumulated deferred federal and state income taxes	265,044	268,311
Accumulated deferred investment tax credits	23,370	24,252
Regulatory liabilities - deferred taxes	37,852	38,840
Other deferred credits	39,031	32,872
Total deferred credits	365,297	364,275

Total Capitalization And Liabilities	$ 1,320,226	$ 1,303,632
	=========	=========

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

CLECO POWER LLC
STATEMENTS OF CASH FLOWS
For the six months ended June 30
(UNAUDITED)

	2001	2000
	(Thousands)
OPERATING ACTIVITIES:
Net income	$ 21,170	$ 29,458
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	25,776	25,152
Allowance for funds used during construction	(504)	(656)
Amortization of investment tax credits	(882)	(871)
Deferred income taxes	5,181	271
Deferred fuel costs	12,667	(9,469)
Changes in assets and liabilities:
Accounts receivable, net	(8,176)	(16,293)
Accounts and notes receivable, affiliate	947	21,804
Unbilled revenues	(3,828)	(9,424)
Fuel, material and supplies inventories	(4,923)	2,863
Accounts payable	(18,564)	(15,830)
Accounts payable, affiliate	(6,471)	1,404
Customer deposits	261	168
Other deferred accounts	(4,672)	10,923
Taxes accrued	16,550	5,535
Interest accrued	108	(178)
Risk management assets and liabilities, net	3,538	(1,937)
Margin deposits	(1,798)	(1,196)
Other, net	252	(10,040)
Net cash provided by operating activities	36,632	31,684
INVESTING ACTIVITIES:
Additions to property, plant and equipment	(23,740)	(21,477)
Allowance for funds used during construction	504	656
Sale of utility plant, including associated land	464	166
Net cash used in investing activities	(22,772)	(20,655)
FINANCING ACTIVITIES:
Retirement of long-term obligations	(15,000)	-
Increase in short-term debt, net	22,127	15,343
Distribution to member	(19,391)	(22,809)
Net cash provided by financing activities	(12,264)	(7,466)

NET INCREASE IN CASH AND CASH EQUIVALENTS	1,596	3,563
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2,224	547
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 3,820	$ 4,110
	=======	=======
Supplementary cash flow information
Interest paid (net of amount capitalized)	$ 15,214	$ 14,838
	=======	=======
Income taxes paid	$ 8,179	$ 20,630
	=======	=======

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

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 ended June 30, 2001, and June 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 3 (Quantitative and Qualitative Disclosure About Market Risk) of Part I and the following Part II items from Form 10-Q: Item 2 (Changes in Securities and Use of Proceeds) and Item 3 (Defaults Upon Senior Securities). The following discussion explains material changes in the amount of revenue and expense items of Cleco Power between the second quarter of 2001 and the second quarter of 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.

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

		For the three months ended June 30
	2001		2000	Variance	Change
	(Thousands)
Operating revenues:
Base	$ 81,663		$ 80,516	$ 1,147	1.4 %
Fuel cost recovery	91,884		65,212	26,672	40.9 %
Affiliate revenue	449		4,624	(4,175)	(90.3)%
Estimated customer credits	(1,933)		(9)	(1,924)	-
Energy marketing	13,948		2,722	11,226	412.4 %
Total operating revenues	$ 186,011		$ 153,065	$ 32,946	21.5 %
	========		=======	=======

	For the three months ended June 30
	2001	2000	Change
	(Millions kWh)
Electric sales Residential	795	805	(1.2)%
Commercial	440	443	(0.7)%
Industrial	669	740	(9.6)%
Other retail	153	155	(1.3)%
Total retail	2,057	2,143	(4.0)%
Sales for resale	91	112	(18.7)%
Total sales to regular customers	2,148	2,255	(4.7)%
Short-term sales to other utilities	35	8	337.5 %
Sales from marketing activities	1	4	(75.0)%
Total electric sales	2,184	2,267	(3.7)%
	====	====

Base revenues during the second quarter of 2001 show a slight increase over the same period in 2000. Base revenues from energy sales decreased $0.8 million. Offsetting this decrease was an increase of $1.1 million in transmission revenue and a $0.8 million increase in miscellaneous 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. 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 second quarters of 2001 and 2000.

Cooling degree days For the three months ended June 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	15.2 %	8.4 %
Increase/(Decrease) from Prior Year	6.4 %	(10.4)%

Short-term sales to other utilities increased significantly during the second 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 December 2000 and ends December 2001 and sales to the City of Ruston, to supply all of its power, under a three-year contract 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 $3.19 per MMBtu in the second quarter of 2001 compared to $2.57 per MMBtu in the same period in 2000. The increase in the average per unit cost of fuel is primarily a result of a 29.3% increase in the per unit cost of natural gas for the second 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.

Affiliate Revenues for the three months ended June 30, 2001 decreased by $4.1 million or 90.3% as compared to the same period in 2000. The decrease is due primarily to a reduction in affiliate transactions between Cleco Power and UtiliTech related to the leasing of crews as stipulated in an agreement between Cleco Power and the LPSC.

Energy marketing revenues for the second quarter of 2001 increased $11.2 million as compared to the same period in 2000. Marketing & Trading markets excess electric capacity and excess natural gas at Cleco Power's power plants on Cleco Power's behalf. 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 second quarter of 2001. 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 "marked-to-market". The mark-to-market related to these open positions was a loss of $1.4 million in the second quarter of 2001 compared to a gain of $1.0 million in the same period of 2000.

Energy Marketing Operations For the three months ended June 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 15,378	$ 1,683	$ 13,695	813.7 %
Mark-to-market	(1,430)	1,039	(2469)	(237.6)%
Total	$ 13,948	$ 2,722	$ 11,226	412.4 %
	=======	======	=======
Energy trading expenses	$ 16,182	$ 600	$ 15,582	-
	=======	======	=======

Operating expenses increased $40.4 million or 33.6% during the second quarter of 2001 compared to the same period in 2000. The increase in operating expenses is primarily the result of increased capacity charges and higher fuel costs. Energy marketing expenses increased $15.6 million in the second quarter of 2001 compared to the same period in 2000 due to the same factors noted above for increases in energy marketing revenues. The increase of $25.7 million in fuel and purchased power for utility operations is due to increased energy prices primarily driven by increases in natural gas prices as compared to the same period in 2000. The 12.4% increase in the second quarter of 2001 as compared to the second quarter 2000 in other operations expense is due primarily to a $1.4 million increase in capacity payments.

Cleco Power purchases power from other electric power generators when the price of the energy purchased is less than the cost to Cleco Power of generating such energy from its own facilities, or when Cleco Power's generating units are unable to provide electricity to satisfy its load. Approximately 39.4% of Cleco Power's energy requirements during the second quarter of 2001 were met with purchased power, compared to 27.8% for the corresponding period in 2000. The increase was caused by power purchase contracts with Williams Energy and Dynegy.

Federal and state income tax expense decreased approximately $2.3 million in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to a decrease in net

income before income taxes in the second quarter of 2001 as compared to the second quarter of 2000.

Net income applicable to member's equity and common stock decreased $4.4 million in the second quarter of 2001 as compared to the second quarter of 2000 due primarily to the $6.7

million decrease in net income from continuing operations offset by the $2.3 million decrease in federal and state taxes as discussed above.

Comparison of the Six Months Ended June 30, 2001, and 2000

	For the six months ended June 30
	2001	2000	Variance	Change
	(Thousands)
Operating revenues:
Base	$ 151,969	$ 149,585	$ 2,384	1.6 %
Fuel cost recovery	177,564	109,438	68,126	62.3 %
Affiliate revenue	1,557	7,177	(5,620)	(78.3)%
Estimated customer credits	(1,933)	(1,225)	(708)	(57.8)%
Energy marketing	13,436	10,408	3,028	29.1 %
Total operating revenues	$ 342,593	$ 275,383	$ 67,210	24.4 %
	=======	=======	=======

	For the six months ended June 30
	2001	2000	Change
	(Millions kWh)
Electric sales
Residential	1,480	1,476	0.3 %
Commercial	787	798	(1.4)%
Industrial	1,349	1,488	(9.3)%
Other retail	281	283	(0.7)%
Total retail	3,897	4,045	(3.7)%
Sales for resale	151	161	(6.2)%
Total sales to regular customers	4,048	4,206	(3.8)%
Short-term sales to other utilities	62	9	588.9 %
Sales from marketing activities	1	69	(98.6)%
Total electric sales	4,111	4,284	(4.0)%
	====	====

Base revenues during the six months ended June 30, 2001 show a slight increase over the same period in 2000. Base revenue from energy sales decreased $0.2 million. Offsetting this decrease was a increase of $1.6 million in transmission revenue and a $1.0 million increase in miscellaneous revenue.

cooling degree due to the customers ability to chose an alternative fuel source for heating such as natural gas. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree due to the customers ability to chose an alternate 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 and from the prior year for cooling/heating degree days for the six months ended June 30, 2001 and 2000.

Cooling/Heating degree days For the six months ended June 30
	2001	2000
Cooling Degree Days:
Increase/(Decrease) from Normal	10.5 %	18.7 %
Increase/(Decrease) from Prior Year	(6.5)%	(3.4)%
Heating Degree Days:
Increase/(Decrease) from Normal	(5.5)%	(38.8)%
Increase/(Decrease) from Prior Year	52.7 %	4.3 %

Short-term sales to other utilities increased significantly during the six months ended June 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 December 2000 and ends December 2001 and sales to the City of Ruston, to supply all of its power, under a three-year contract 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 $3.69 per MMBtu for the six months ended June 30, 2001 compared to $2.37 per MMBtu in the same period in 2000. The increase in the average per unit cost of fuel is primarily a result of a 67.5% increase in the per unit cost of natural gas for the six months ended June 30, 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.

Affiliate Revenues for the six months ended June 30, 2001 decreased by $5.6 million or 78.3% as compared to the same period in 2000. The decrease is due primarily to a reduction in affiliate transactions between Cleco Power and UtiliTech related to the leasing of crews as stipulated in an agreement between Cleco Power and the LPSC.

An earnings review settlement was reached with the LPSC in 1996 pursuant to which accruals for estimated customer credits are sometimes required. The Company determined that an accrual for $1.9 million was necessary for the six months ended June 30, 2001, compared to $1.2 million for the same period in 2000. The amount of credit due customers, if any, is determined by the LPSC annually based on results for the 12-month period ending September 30 of each year. For additional information see Note L. - Estimated Customer Credits in the notes to the Unaudited Financial Statements in the Report.

Energy Marketing Operations For the six months ended June 30
	2001	2000	Variance	Change
	(Thousands)
Energy trading revenue	$ 16,303	$ 9,478	$ 6,825	72.0 %
Mark-to-market	(2,867)	930	(3,797)	(408.3)%
Total	$ 13,436	$ 10,408	$ 3,028	29.1 %
	======	======	======
Energy trading expenses	$ 16,509	$ 7,893	$ 8,616	109.2 %
	======	======	======

Operating expenses increased $80.1 million or 37.0% during the six months ended June 30, 2001 compared to the same period in 2000. The increase in operating expenses is primarily the result of increased capacity charges and higher fuel costs. Energy marketing expenses increased $8.6 million for the six months ended June 30, 2001 compared to the same period in 2000 due to the same factors noted above for increases in energy marketing revenues. Fuel and purchased power for utility operations increased $68.0 million due to increased energy prices primarily driven by increases in natural gas prices as compared to the same period in 2000. The 24.7% increase for the six months ended June 30, 2001 as compared to the same period in 2000 in other operations expense is due primarily to a $5.1 million increase in capacity payments.

Approximately 39.8% of Cleco Power's energy requirements for the six months ended June 30, 2001 were met with purchased power, compared to 27.6% for the same period in 2000. The increase was caused by power purchase contracts with Williams Energy and Dynegy. Additionally, due to unscheduled outages at the Dolet Hills Power Station and Rodemacher Unit 2 for a period of two weeks in February 2001, Cleco Power purchased more power for the six months ended June 30, 2001 than it did in the same period in 2000 to meet load requirements.

Federal and state income tax expense decreased approximately $3.9 million for the six months ended June 30, 2001 as compared to the same period in 2000 due primarily to a decrease in net income before income taxes for the six months ended June 30, 2001 as compared to the same period in 2000.

Net income applicable to member's equity and common stock decreased $8.3 million for the six months ended June 30, 2001 as compared to the same period in 2000 due primarily to the $12.2 million decrease in net income from continuing operations offset by the $3.9 million decrease in federal and state taxes as discussed above.

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

NOTE A	Reclassification	Cleco Corporation and Cleco Power
NOTE B	Legal Proceeding: Fuel Supply - Lignite	Cleco Corporation and Cleco Power
NOTE C	Extraordinary Gain	Cleco Corporation
NOTE D	Disclosures About Segments	Cleco Corporation
NOTE E	Restricted Cash	Cleco Corporation
NOTE F	Equity Investment in Investee	Cleco Corporation
NOTE G	LDEQ Litigation	Cleco Corporation
NOTE H	New Accounting Standard	Cleco Corporation and Cleco Power
NOTE I	Loss on Disposal of Segment	Cleco Corporation
NOTE J	Stock Split	Cleco Corporation
NOTE K	Debt	Cleco Corporation
NOTE L	Accrual for Estimated Customer Credits	Cleco Corporation and Cleco Power
NOTE M	Subsequent Event	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. Legal Proceeding: Fuel Supply - Lignite

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

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

As a result of the counterclaims filed by DHMV in the Federal Court Suit, in August 1997, Cleco Power and SWEPCO filed the State Court Suit against the parent companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA, Inc. The State Court Suit sought to enforce a separate 1995 agreement by Jones Capital Corporation and Philipp Holzmann USA, Inc. related to the LMA. Jones Capital Corporation and Philipp Holzmann USA, Inc. asked the state court to stay that proceeding until the Federal Court Suit was resolved.

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

The civil, nonjury trial in the Federal Court Suit was to have commenced in May 2000. However, in April 2000, all parties jointly requested that the court postpone the trial date and stay of all matters before the trial court to give the parties an opportunity to attempt to reach an amicable resolution of the litigation. On April 20, 2000, Cleco Power, SWEPCO and DHMV executed a memorandum of understanding to reflect a proposal among themselves to settle the litigation. The federal court granted the motion, stayed the action at the trial court and in further proceedings postponed the trial commencement indefinitely pending settlement. The Fifth Circuit appeal of the federal court's March 1, 2000, ruling was also stayed pending settlement.

The LPSC granted preliminary approval of the rate-making effects of the proposed settlement on April 18, 2001. On May 31, 2001, all parties to the litigation executed a definitive settlement agreement and agreed to dismiss the State Court Suit, the Federal Court Suit and the appeal pending before the Fifth Circuit. The LMA among Cleco Power, SWEPCO and DHMV was canceled, as were all other operative contracts among the parties.

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

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

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

Note C. 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 interest 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.

Note D. 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 I - 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.

Segment Information
For the quarter ending June 30
(Thousands)


2001	Cleco Power	Midstream	UTS	Others	Unallocated Items, Reclassifications & Eliminations	Consolidated

Revenues
Retail electric operations	$ 171,614					$ 171,614
Energy marketing operations	13,948	$ 118,036				131,984
Other operations	-	78	$	$ 24	$ -	102
Total operating revenue	$ 185,562	$ 118,114	$	$ 24	$ -	$ 303,700
	======	======	=====	=====	======	=======

Intersegment revenue	$ 449	$ 4,553	$	$ 16,211	$ (21,213)	$ -
Segment profit from continuing operations	$ 18,798	$ 4,033	$	$ (837)	$	$ 21,994
Loss on disposal of segment	$ -	$ -	$ 1,062	$ -	$ -	$ 1,062
Segment profit (loss) ⁽¹⁾	$ 18,798	$ 4,033	$ (1,062)	$ (837)	$ -	$ 20,932
	======	======	=====	=====	======	=======
Segment assets	$1,320,226	$ 542,213	$ 1,226	$ 421,165	$ (403,959)	$ 1,880,871


	Segment profit	$ 20,932
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	7,924
	Preferred dividends	407
		$ 12,601
		=====


2000

Revenues
Retail electric operations	$ 145,719					$ 145,719
Energy marketing operations	2,722	$ 37,722				40,444
Other operations	-	450	$	$ 9	$ -	459
Total operating revenue	$ 148,441	$ 38,172	$	$ 9	$ -	$ 186,622
	======	=====	=====	======	======	======

Intersegment revenue	$ 4,624	$ 12,560	$	$ 23,782	$ (40,966)	$ -
Segment profit from continuing operations	$ 25,473	$ 3,095	$	$ (621)	$ -	$ 27,947
Loss from operations, net of income taxes	$ -	$ -	$ 1,597	$ -	$ -	$ 1,597
Extraordinary item	$ -	$ -	$ -	$ -	$ -	$ -
Segment profit (loss) ⁽¹⁾	$ 25,473	$ 3,095	$ (1,597)	$ (621)	$	$ 26,350
	======	=====	=====	======	======	======
Segment assets	$ 1,419,509	$ 350,074	$ 5,361	$ 352,735	$ (299,798)	$ 1,827,881


	Segment profit	$ 26,350
^{(1) Reconciliation of segment profit to consolidated profit}	Unallocated items
	Income taxes	9,435
	Preferred dividends	461
		$ 16,454
		======

Segment Information
For the six months ending June 30
(Thousands)


2001	Cleco Power	Midstream	UTS	Others	Unallocated Items, Reclassifications & Eliminations	Consolidated

Revenues
Retail electric operations	$ 327,600					$ 327,600
Energy marketing operations	13,436	$ 215,577				229,013
Other operations	-	149	$	$ 49	$	198
Total operating revenue	$ 341,036	$ 215,726	$	$ 49	$	$ 556,811
	======	=====	====	=====	======	=======

Intersegment revenue	$ 1,557	$ 7,625	$	$ 37,367	$ (46,550)	$ -
Segment profit from continuing operations	$ 32,071	$ 9,295	$	$ (1,148)	$	$ 40,218
Loss on disposal of segment	$ -	$ -	$ 2,468	$ -	$ -	$ 2,468
Segment profit (loss) ⁽¹⁾	$ 32,071	$ 9,295	$ (2,468)	$ (1,148)	$	$ 37,750
	======	=====	====	=====	======	=======
Segment assets	$ 1,320,226	$ 542,213	$ 1,226	$ 421,165	$ (403,959)	$ 1,880,871


	Segment profit	$ 37,750
(1) Reconciliation of segment profit to consolidated profit	Unallocated items
	Income taxes	14,048
	Preferred dividends	880
		$ 22,822


2000

Revenues
Retail electric operations	$ 257,798					$ 257,798
Energy marketing operations	10,408	$ 54,920				65,327
Other operations	-	565	$	$ 25	$	591
Total operating revenue	$ 268,206	$ 55,485	$	$ 25	$	$ 323,716
	======	======	=====	=====	======	======

Intersegment revenue	$ 7,177	$ 19,881	$	$ 48,733	$ (75,791)	$ -
Segment profit from continuing operations	$ 44,242	$ (212)	$	$ (427)	$ -	$ 43,603
Loss from operations, net of income taxes	$ -	$ -	$ 2,163	$ -	$ -	$ 2,163
Extraordinary item	$ -	$ 2,508	$ -	$ -	$ -	$ 2,508
Segment profit (loss) ⁽¹⁾	$ 44,242	$ 2,296	$ (2,163)	$ (427)	$ -	$ 43,948
	======	======	=====	=====	======	======
Segment assets	$ 1,419,509	$ 350,074	$ 5,361	$ 352,735	$ (299,798)	$ 1,827,881


	Segment profit	$ 43,948
^{(1) Reconciliation of segment profit to consolidated profit}	Unallocated items
	Income taxes	14,303
	Preferred dividends	934
		$ 28,711
		=====

Note E. 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 June 30, 2001, $27.6 million of restricted cash remains restricted under the Evangeline bond indenture until certain of its provisions are met.

Note F. Equity Investment in Investee

Equity investment in investee represents Midstream's approximately $163.2 million investment in APP, Midstream's approximate $0.5 million investment in PEP and Energy's approximate $1.1 million investment in Hudson SVD LLC. No material earnings have been recorded for these investments for the first six months of 2001.

APP is a joint venture 50% owned by Midstream and 50% owned by Calpine Corporation. APP was formed in order to construct, own and operate a natural gas-fired electric 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 June 30, 2001, was $156.2 million. The majority of the difference of $7.0 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 Corporation, 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 June 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. The difference of $0.5 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 $1.0 million, which equals the investment at Energy.

Note G. 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 electric generating plant near Eunice, Louisiana. APP-related Petitioners filed their appeals to the air and water permits in the 19^th Judicial District Court in Baton Rouge, Louisiana. APP-related Petitioners asked the court to reverse the air and water

permits issued by the LDEQ and allege that LDEQ's decision to issue the permits was arbitrary, capricious and procedurally inadequate. APP-related Petitioners have also asked the court to stay APP's power plant construction activities pending resolution of the litigation. APP has denied APP-related Petitioners' allegations and is vigorously defending the validity of the permits issued to it by the LDEQ. The permits could be upheld, reversed, or remanded in whole or in part. If the permits were to be reversed in material part by the court, APP may be required to cease its construction of the generating plant temporarily or permanently, depending on the nature and details of the reversal. If the court were to remand the permits, without reversing them, to the LDEQ for further proceedings, APP's continuation of construction of the generating plant may be jeopardized, depending upon the nature and details of the remand. Oral arguments on the appeal of these permits were held on February 5, 2001. In its 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 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. PEP is constructing and will own and operate a new electric generating plant near Perryville, Louisiana. PEP-related Petitioners filed their appeal of the air permit in the 19^th Judicial District Court in Baton Rouge, Louisiana, alleging that the issuance of the air permit 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 decision or remand the permit decision to require the LDEQ to address certain alleged deficiencies in its issuance of the permit and have also requested that the court stay the air permit. PEP denies PEP-related Petitioners' allegations and is vigorously defending the validity of the permit issued to it by the LDEQ. The permit 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 matter be remanded to the LDEQ for the purpose of receiving additional information from PEP, reopening the public comment period, and issuing a revised decision for the issuance of the permits. 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 H. New Accounting Standards

Periodically the FASB issues Statements of Financial Accounting Standards. These statements reflect accounting, reporting and disclosure requirements the Company should follow in the accumulation of financial data and in the presentation of financial statements. The FASB, a non-governmental organization, is the primary source of generally accepted accounting principles within the United States.

In 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivatives embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. This statement requires that changes in the derivative's fair value be recognized in current earnings, unless effective accounting tests are met, where changes in the fair value of the derivative would be recorded in other comprehensive income (OCI) in the equity section of the balance sheet.

In June 1999, the FASB issued SFAS No. 137, which deferred the effective start date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amended certain normal purchase and sales guidance within SFAS No. 133. The Company implemented the requirements of these accounting standards effective January 1, 2001.

In June of 1998, the FASB created the Derivatives Implementation Group (DIG) as a task force to assist the FASB in answering implementation questions relating to SFAS No. 133. The DIG conclusions remain tentative until formally voted on and cleared by the FASB. Management continues to monitor the conclusions reached by the DIG. As conclusions clarify certain technical aspects of SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, management's assessment of contracts that are subject to SFAS No. 133 and the implementation of SFAS No. 133 may change.

In June 2001, the FASB cleared DIG Issue C-15 which extends the normal purchase and normal sales exception within SFAS No. 133 for the purchase or sale of electricity. The DIG concluded that power purchase and sales agreements, including capacity contracts, qualify for the normal purchases and normal sales exception in SFAS No. 133 provided that the agreements meet several specific criteria. The effective date of the Issue is the first day of the first fiscal quarter after June 29, 2001. The affect of this Issue is expected to be immaterial to the results of operations and financial condition of the Company.

Cleco Power

Cleco Power has entered into futures, options, and forward contracts for the purchase or sale of electricity and natural gas to meet forecasted customer demand for these commodities. Generally, contracts for the future purchase of electricity and natural gas for consumption (forward contracts) are not subject to the fair market value requirements of SFAS No. 133, as these transactions are considered purchases in the normal course of business. Changes in the fair market value of these normal purchase / normal sale contracts are not recorded, but instead are recognized as revenue or expenses when fulfillment of the contract terms or the transaction has been completed.

Cleco Power does recognize, in current earnings, changes in the fair market value of futures and options contracts and certain forward contracts. Cleco Power has from inception marked-to-market the open positions under these contracts and, as such, implementation of SFAS No. 133, as amended, did not have an impact on the existing accounting procedures or financial results of Cleco Power. Changes in fair market value are influenced by various market factors, including weather and the availability of regional electric generation and transmission capacity.

Midstream

Marketing & Trading engages in activities that are considered "trading" as defined by EITF No. 98-10. All of Marketing & Trading's positions are currently being marked-to-market under the rules of EITF No. 98-10. As such, implementation of SFAS No. 133, as amended, did not have an impact on the existing accounting procedures or financial results of Marketing & Trading.

Evangeline owns and operates the Evangeline Power Station, and tolls the power generated by the facility to another unaffiliated company under an operating lease. Accordingly, the lease at Evangeline is not subject to the requirements of SFAS No. 133.

Energy engages in the wholesale marketing of natural gas and the production, gathering and transmission of natural gas. Certain forward, futures, options, and swap contracts between Energy and outside parties are designated as cash flow hedges against fluctuations in the price of natural gas. Changes in the fair market value of these open positions are recognized in OCI.

A transition adjustment relating to these contracts was recorded at January 1, 2001 in the statement of other comprehensive income, that reduced equity by approximately $4.5 million. At June 30, 2001, Energy had deferred through OCI a gain of $0.4 million. During the first three months of 2001, Energy's equity balance increased by approximately $4.4 million. Approximately $2.2 million of this increase was due to a reduction in the market price of natural gas and the recognition in earnings from contracts related to underlying transactions that were delivered. The remaining $2.2 million increase resulted from the assignment of several underlying gas purchase and sales transactions to an affiliated trading company and the subsequent termination of related swap agreements with that affiliate. The remaining equity balance relating to the transition adjustment was reclassified into earnings during the second quarter of 2001 as the hedged transactions were completed.

During the second quarter of 2001, Energy entered into additional cash-flow hedges with additional counterparties to hedge a portion of forecasted commitments through June 2004. For the three months ended June 30, 2001, Energy's gain deferred through OCI increased by approximately $0.5 million, the majority due to a reduction in the market price of natural gas relating to these new forward and hedge positions. Of the $0.4 million OCI balance recorded as equity at June 30, $0.1 million is expected to be reclassified into earnings within the next three months as the related hedged transactions are delivered and completed.

In June 2001, FASB issued SFAS No. 141, "Business Combinations". SFAS No. 141 establishes accounting and reporting standards for business combinations and supercedes APB Opinion No. 16, "Business Combinations". This new standard requires that all business combinations that fall within its scope be accounted for using the purchase method and gives guidance on applying the purchase method. The effective date of the statement is for all business combinations initiated after June 30, 2001 and for all business combinations accounted for by the purchase method for which the date of acquisition is July 1, 2001, or later. The affect of adopting this statement has not been determined.

In June 2001, FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142 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 all acquired intangible assets that fall within its scope be amortized over its useful life if it has a finite useful life, or not amortized if the intangible assets have 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 affect of adopting this statement has not been determined.

In July 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires the recognition of a liability for an assets 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 assets 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 affect of adopting this statement has not been determined.

Note I. 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 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 June 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 second quarter, it was determined that 45 days was not adequate to complete the calculations. The due date of the calculations was extended and should be completed by the end of the third 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 June 30, 2001, no amounts have been recorded for the indemnifications.

Additional information about UTS is as follows:

	For the six months ended June 30				For the three months ended June 30
	2001		2000		2001		2000
	(Thousands)				(Thousands)
Revenues	$	3,947	$	7,150	$	431	$	3,541
Loss from operations, net	$	-	$	(2,163)	$	-	$	(1,597)
Income tax benefit associated with
loss from operations	$	-	$	1,344	$	-	$	993
Loss on disposal of segment, net	$	(2,468)	$	-	$	(1,062)	$	-
Income tax benefit associated with
loss on disposal of segment	$	1,539	$	-	$	664	$	-

During the first six months of 2001, the $2.4 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 segment for the year ended December 31, 2000 and the $1.3 million loss on the auction of equipment.

Note J. 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 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 million shares of common stock outstanding. Distribution of certificates representing the split shares occurred on May 21, 2001. 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 K. 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 Banks Prime Rate in

effect on such date. This line of credit is guaranteed by Cleco Corporation. At June 30, 2001, there were no balances outstanding under this credit agreement.

Note L. Accrual for Estimated Customer Credits

Cleco Power's reported earnings for the six months ended June 30, 2001 reflect a $1.9 million accrual for estimated customer credits which may be required under terms of an earnings review settlement reached with the LPSC under order U-21496 in 1996. Of the $1.9 million,

$1.6 million relates to the 12-month-ended September 30, 2000 cycle and the remaining $0.3 million relates to an increase in the estimated refund for the 12-month-ended September 30, 2001 cycle. On July 25, 2001 the LPSC's final report requires a $1.8 million refund for the 12-month ended September 30, 2000 cycle. Cleco Power has a reserve for the 12-month ended September 30, 2000 cycle of $1.8 million that is sufficient to cover the refund amount. The refund for the 12-month ended September 30, 2000 cycle will be paid in September 2001.

Note M. Subsequent Event

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.

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 June 30, 2001, and December 31, 2000, the Company had $130.4 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. An uncommitted line of credit with a bank in the amount of $2.5 million is also available to support working capital needs. The amount of credit available to the Company under the facilities totaled $72.9 million at June 30, 2001.

At June 30, 2001, and December 31, 2000, Cleco Power, a regulated consolidated subsidiary of the Company, had $63.6 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 June 30, 2001, there were no balances outstanding under this credit agreement.

At June 30, 2001, CLE Resources, Inc., an unregulated consolidated subsidiary of the Company, had $0.6 million of cash and temporary cash investments in securities with original maturities of 90 days or less.

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 Cleco Corporation's revolving credit agreements, with a fee of 5/8 of one percent, per the terms of the credit agreements.

APP is a joint venture by Midstream and Calpine Corporation 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 at $564 million. As of June 30, 2001, Midstream had contributed $163.2 million to APP. By the end of 2001, the Company expects APP to receive interim non-recourse project financing and to reimburse the Company for a large portion of the contributions to APP.

PEP is a joint venture by Midstream and Mirant Corporation 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 at $340 million. As of June 30, 2001, Midstream had contributed $0.5 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. The interim facility is convertible to an 8-year Mini-perm term loan by July 2002.

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 levels, including Louisiana. Management expects the customer choice debate and other related issues to continue in legislative and regulatory bodies through 2001. At this time, the Company cannot predict whether any legislation or regulation will be enacted or adopted during 2001 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. However, management believes that its rates and the quality and reliability of their service place Cleco Power in a favorable competitive position in current retail markets, as Cleco Power has ranked number one in reliability among electric utility companies in Louisiana for the past two years, based upon received annual filings in the LPSC Reliability Order.

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 Regional Transmission Organization (RTO). Although participation is voluntary, the FERC has made it clear that any jurisdictional entity not participating in an RTO will be subject to further regulatory directives. 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 was urged 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. At this point, it is unclear which RTO the SPP may eventually join. As a result, 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.

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 2000 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.

NEW POWER PLANTS

APP is a joint venture by Midstream and Calpine Corporation that is in the process of constructing a new natural gas-fired power plant near Eunice, Louisiana. Construction on the plant has begun, with a projected completion date of mid-2002. Construction costs of the plant are estimated to be approximately $564.0 million. As of June 30, 2001 APP has spent $342.8 million on constructing the plant. Long-term non-recourse financing is expected to be received by the end of 2001. APP is owned 50% by Midstream and 50% by Calpine Corporation. The investment in APP is being accounted for using the equity method of accounting by the Company. As of June 30, 2001, Midstream has contributed $163.2 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.

PEP is a joint venture by 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 at $340.0 million. As of June 30, 2001, PEP has incurred $112.0 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 June 30, 2001, Midstream has contributed $0.5 million to

PEP. The reduction of Midstream's investment in PEP is a direct result of the long-term non-recourse financing that occurred during June 2001 and a subsequent distribution from PEP to Midstream.

On April 30, 2001, PEP announced the signing of a long-term power purchase agreement for the output of its 700-megawatt 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 amount 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

In June of 1998, the FASB created the DIG as a task force to assist the FASB in answering implementation questions relating to SFAS No. 133. The DIG conclusions remain tentative until formally voted on and cleared by the FASB. Management continues to monitor the conclusions reached by the DIG. As conclusions clarify certain technical aspects of SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, management's assessment of contracts that are subject to SFAS No. 133 and the implementation of SFAS No. 133 may change.

Cleco Power

Midstream

In June 2001, FASB issued SFAS No. 141, "Business Combinations." SFAS No. 141 establishes accounting and reporting standards for business combinations and supercedes APB Opinion No. 16, "Business Combinations." This new standard requires that all business combinations that fall within its scope be accounted for using the purchase method and gives guidance on applying the purchase method. The effective date of the statement is for all business combinations initiated after June 30, 2001 and for all business combinations accounted for by the purchase method for which the date of acquisition is July 1, 2001, or later. The affect of adopting this statement has not been determined.

In June 2001, FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 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 all acquired intangible assets that fall within its scope be amortized over its useful life if it has a finite useful life, or not amortized if the intangible assets have 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 affect of adopting this statement has not been determined.

In July 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the recognition of a liability for an assets 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 assets 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 affect of adopting this statement has not been determined.

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 Cleco Energy's positions are characterized as "other than trading" under EITF No. 98-10. The 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 June 30, 2001, the carrying value of the Company's consolidated short-term variable-rate debt was approximately $130.4 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 $1.3 million in the Company's pretax earnings.

As of June 30, 2001, the carrying value of Cleco Power's short-term variable-rate debt was approximately $63.5 million, which approximates the fair market value. Each 1.0% change in the average interest rates applicable to such debt would result in a change of approximately $0.6 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, 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 June 30, 2001 was a loss of $1.2 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 June 30, 2001, the net marked-to-market figure for those positions was a loss of $2.8 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.

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

	For the three months ended June 30, 2001			At
	High	Low	Average	June 30, 2001
	(Thousands)

Marketing & Trading	$ 3,502.2	$ 166.7	$ 1,461.7	$ 2,052.1
Cleco Power	$ 1,422.3	$ 12.0	$ 471.2	$ 1,047.8
Cleco Energy	$ 279.3	$ 2.3	$ 94.2	$ 141.2
Consolidated	$ 3,733.6	$ 742.1	$ 2,027.1	$ 3,241.1


	For the six months ended June 30, 2001
	High	Low	Average
	(Thousands)
Marketing & Trading	$ 4,056.8	$ 166.7	$ 1,626.3
Cleco Power	$ 1,422.3	$ 12.0	$ 308.1
Cleco Energy	$ 279.3	$ 2.3	$ 94.2
Consolidated	$ 4,199.5	$ 546.7	$ 1,981.5

PART II

ITEM 1 LEGAL PROCEEDINGS

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

For a description of legal proceedings affecting the Company and Cleco Power, please review Note B - Legal Proceeding: Fuel Supply - Lignite, in the Notes to the Unaudited Financial Statements in this report, which is incorporated herein by reference.

ITEM 2 CHANGES IN SECURITIES AND USE OF PROCEEDS

On May 7, 2001, after receiving shareholder approval, the Company amended its charter to increase the amount of authorized common stock to effect a two-for-one stock split of the Company's common stock. For additional information regarding the stock split, please review Note J. - Stock Split in the notes to the Unaudited Financial Statements in this report, which is
incorporated herein by reference.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a)	The Annual Meeting of Shareholders of the Company was held on April 27, 2001 in Alexandria, Louisiana.
(b)	Proxies for the election of directors were solicited pursuant to Regulation14A under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to management's nominees, and all nominees listed in the Proxy Statement were elected.
(c)	The following is a tabulation of the votes cast upon each of the proposals presented at the Annual Meeting of Shareholders of the Company on April 27, 2001.

	(1) Election of Directors:

Class I Directors	For	Withheld	Brokers Non-Votes
Sherian G. Cadoria	20,285,625	205,073	0
Richard B. Crowell	20,336,489	154,209	0
David M. Eppler	20,381,295	109,403	0

The term of office as a director of each of Messrs. Robert T. Ratcliff, William H. Walker, Jr., Patrick Garrett, Elton R. King, A. DeLoach Martin, Jr., and F. Ben James, Jr. continued after the meeting.

(2)

Appointment of PricewaterhouseCoopers LLP as the Company's auditors for 2001:

For	Against	Abstain	Brokers Non-Votes
20,008,863	423,088	58,747	0

(3)

Approval of Articles of Amendment to Cleco's Amended and Restated Articles of Incorporation to increase amount of authorized common stock and to effect a two-for-one split of Cleco's Common Stock:

For	Against	Abstain	Brokers Non-Votes
20,281,423	129,753	79,522	0

ITEM 5 OTHER INFORMATION

The Annual shareholders' meeting has been set for April 26, 2002.

ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits

	Cleco Corporation:

	11(a)	Computation of Net Income Per Common Share for the three months ended June 30, 2001
	11(b)	Computation of Net Income Before Extraordinary Item Per Common Share for the six months ended June 30, 2001
	11(c)	Computation of Net Income Per Common Share for the six months ended June 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, six and twelve month periods ended June 30, 2001, for Cleco Corporation

	Cleco Power:

	12(b)	Computation of Ratio of Earnings to Fixed Charges for the three, six and twelve month periods ended June 30, 2001, for Cleco Power

(b)	Reports on Form 8-K

	Cleco Corporation:
	On April 3, 2001, Cleco Corporation filed a report on Form 8-K dated as of April 2, 2001 including as an exhibit a press release announcing the sale of Utilitech. On April 30, 2001, Cleco Corporation filed a report on Form 8-K dated as of April 27, 2001 including as an exhibit a press release describing the Company's two-for-one stock split. On May 7, 2001, Cleco Corporation filed a report on Form 8-K dated as of May 7, 2001 in lieu of post-effective amendments to certain registration statements listed in an exhibit thereto.

	Cleco Power:
	On April 26, 2001, Cleco Power filed a report on Form 8-K dated as of April 26, 2001 including as exhibits a Selling Agency Agreement, Third Supplemental Indenture and Forms of Notes relating to Cleco Power's offering from time to time of its Medium Term Notes, Series C.

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: August 13, 2001

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: August 13, 2001