10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

__________________

FORM 10-Q

x  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

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 1-05663

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 by check mark whether the Registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrants were required to submit and post such files).  Yes x    No ¨
Indicate by check mark whether Cleco Corporation is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):   Large accelerated filer x           Accelerated filer ¨                  Non-accelerated filer ¨  (Do not check if a smaller reporting company)            Smaller reporting company ¨
Indicate by check mark whether Cleco Power LLC is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one): Large accelerated filer ¨           Accelerated filer ¨                  Non-accelerated filer x  (Do not check if a smaller reporting company)            Smaller reporting company ¨
Indicate by check mark whether the Registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act)  Yes¨    No x

Number of shares outstanding of each of Cleco Corporation’s classes of Common Stock, as of the latest practicable date.

Registrant	Description of Class	Shares Outstanding at October 28, 2011
Cleco Corporation	Common Stock, $1.00 Par Value		60,665,607

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

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

This Combined Quarterly Report on Form 10-Q is separately filed by Cleco Corporation and Cleco Power.  Information in this filing 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.

This report should be read in its entirety as it pertains to each respective Registrant.  The Notes to the Unaudited Condensed Consolidated Financial Statements are combined.

TABLE OF CONTENTS

			PAGE
GLOSSARY OF TERMS			3
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			5
PART I	Financial Information
ITEM 1.	Cleco Corporation — Condensed Consolidated Financial Statements	7
	Cleco Power — Condensed Consolidated Financial Statements	16
	Notes to the Unaudited Condensed Consolidated Financial Statements	23
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	64
ITEM 4.	Controls and Procedures	66
PART II	Other Information
ITEM 1.	Legal Proceedings	67
ITEM 1A.	Risk Factors	67
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
ITEM 5.	Other Information	67
ITEM 6.	Exhibits	68
	Signatures	69

2

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

GLOSSARY OF TERMS

References in this filing, including all items in Parts I and II, to “Cleco” mean Cleco Corporation and its subsidiaries, including Cleco Power, and references to “Cleco Power” mean Cleco Power LLC and its subsidiaries, unless the context clearly indicates otherwise.  Additional abbreviations or acronyms used in this filing, including all items in Parts I and II are defined below:

ABBREVIATION OR ACRONYM	DEFINITION
401(k) Plan	Cleco Power 401(k) Savings and Investment Plan
ABR	Alternate Base Rate
Acadia	Acadia Power Partners, LLC, a wholly owned subsidiary of APH.  Acadia no longer owns any materials and supply inventory, property, plant and equipment, or land as a result of the disposition of Acadia Unit 2 to Entergy Louisiana on April 29, 2011.  From February 23, 2010 to April 29, 2011, Acadia was owned 100% by Cajun and consisted of Acadia Unit 2.  Prior to February 23, 2010, Acadia was 50% owned by APH and 50% owned by Cajun and consisted of Acadia Unit 1 and Acadia Unit 2.
Acadia Unit 1	Cleco Power’s 580-MW unit, combined cycle, natural gas-fired power plant located at the Acadia Power Station near Eunice, Louisiana
Acadia Unit 2	Entergy Louisiana’s 580-MW unit, combined cycle, natural gas-fired power plant located at the Acadia Power Station near Eunice, Louisiana.  Prior to April 29, 2011, Acadia Unit 2 was owned by Acadia.
Acadiana Load Pocket	An area in south central Louisiana that has experienced transmission constraints caused by local load and lack of generation.  Transmission within the Acadiana Load Pocket is owned by several entities, including Cleco Power.
AFUDC	Allowance for Funds Used During Construction
Amended EPC Contract	Amended and Restated EPC Contract between Cleco Power and Shaw, executed on May 12, 2006, for engineering, procurement, and construction of Madison Unit 3, as amended by Amendment No. 1 thereto effective March 9, 2007, Amendment No. 2 thereto dated as of July 2, 2008, Amendment No. 3 thereto dated as of July 22, 2009, and Amendment No. 4 thereto dated October 19, 2009.
Amended Lignite Mining Agreement	Amended and restated lignite mining agreement effective December 29, 2009
AMI	Advanced Metering Infrastructure
APH	Acadia Power Holdings LLC, a wholly owned subsidiary of Midstream
Attala	Attala Transmission LLC, a wholly owned subsidiary of Cleco Corporation
Cajun	Cajun Gas Energy L.L.C., a wholly owned subsidiary of third parties.  In conjunction with the disposition of Acadia Unit 2 on April 29, 2011, APH no longer has any ownership interest in Cajun.  From February 23, 2010 to April 29, 2011, Cajun was 50% owned by APH and 50% owned by third parties.  Prior to February 23, 2010, Cajun was 100% owned by third parties.
Cleco Innovations LLC	A wholly owned subsidiary of Cleco Corporation
Cleco Katrina/Rita	Cleco Katrina/Rita Hurricane Recovery Funding LLC, a wholly owned subsidiary of Cleco Power
Coughlin	Coughlin Power Station, a combined-cycle, natural gas-fired power plant located in Evangeline Parish, Louisiana.  On June 11, 2010, Evangeline Power Station was renamed Coughlin Power Station.
DHLC	Dolet Hills Lignite Company, LLC, a wholly owned subsidiary of SWEPCO
Diversified Lands	Diversified Lands LLC, a wholly owned subsidiary of Cleco Innovations LLC
DOE	United States Department of Energy
Entergy Gulf States	Entergy Gulf States Louisiana, L.L.C., formerly Entergy Gulf States, Inc.
Entergy Louisiana	Entergy Louisiana, LLC
Entergy Mississippi	Entergy Mississippi, Inc.
Entergy Services	Entergy Services, Inc., as agent for Entergy Louisiana and Entergy Gulf States
EPA	United States Environmental Protection Agency
EPC	Engineering, Procurement, and Construction
ESPP	Cleco Corporation Employee Stock Purchase Plan
Evangeline	Cleco Evangeline LLC, a wholly owned subsidiary of Midstream, and its combined cycle, natural gas-fired power plant located in Evangeline Parish, Louisiana.  On June 11, 2010, the power plant was renamed Coughlin Power Station.
Evangeline 2010 Tolling Agreement	Capacity Sale and Tolling Agreement between Evangeline and JPMVEC, which was executed in February 2010
Evangeline Restructuring Agreement	Purchase, Sale and Restructuring Agreement entered into on February 22, 2010, by Evangeline and JPMVEC
Evangeline Tolling Agreement	Capacity Sale and Tolling Agreement between Evangeline and BE Louisiana LLC (as successor to Williams Power Company, Inc.) which was set to expire in 2020 and was terminated in February 2010.  In September 2008, BE Louisiana LLC was merged into JPMVEC.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FRP	Formula Rate Plan
GAAP	Generally Accepted Accounting Principles in the United States
GO Zone	Gulf Opportunity Zone Act of 2005 (Public Law 109-135)
ICT	Independent Coordinator of Transmission
Interconnection Agreement	One of two Interconnection Agreement and Real Estate Agreements, one between Attala and Entergy Mississippi, and the other between Perryville and Entergy Louisiana
IRP	Integrated Resource Planning
IRS	Internal Revenue Service
JPMVEC	J.P. Morgan Ventures Energy Corporation.  In September 2008, BE Louisiana LLC was merged into JPMVEC.
kWh	Kilowatt-hour(s) as applicable
LIBOR	London Inter-Bank Offer Rate
Lignite Mining Agreement	Dolet Hills Mine Lignite Mining Agreement, dated as of May 31, 2001

3

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

ABBREVIATION OR ACRONYM	DEFINITION
LPSC	Louisiana Public Service Commission
LTICP	Cleco Corporation Long-Term Incentive Compensation Plan
Madison Unit 3	A 600-MW solid-fuel generating unit at Cleco Power’s plant site in Boyce, Louisiana that commenced commercial operation on February 12, 2010.  Prior to June 11, 2010, Madison Unit 3 was known as Rodemacher Unit 3.
Midstream	Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Corporation
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service
MW	Megawatt(s) as applicable
NERC	North American Electric Reliability Corporation
OCI	Other Comprehensive Income
NOx	Nitrogen oxides
Oxbow	Oxbow Lignite Company, LLC, 50% owned by Cleco Power and 50% owned by SWEPCO
PCAOB	Public Company Accounting Oversight Board
PCB	Polychlorinated biphenyl
Perryville	Perryville Energy Partners, L.L.C., a wholly owned subsidiary of Cleco Corporation
Power Purchase Agreement	Power Purchase Agreement, dated as of January 28, 2004, between Perryville and Entergy Services
PPACA	Patient Protection and Affordable Care Act (HR 3590)
PRP	Potentially responsible party
Registrant(s)	Cleco Corporation and Cleco Power
RFP	Request for Proposal
Sale Agreement	Purchase and Sale Agreement, dated as of January 28, 2004, between Perryville and Entergy Louisiana
SEC	Securities and Exchange Commission
SERP	Cleco Corporation Supplemental Executive Retirement Plan
Shaw	Shaw Contractors, Inc., a subsidiary of The Shaw Group Inc.
SO2	Sulfur dioxide
SPP	Southwest Power Pool
Support Group	Cleco Support Group LLC, a wholly owned subsidiary of Cleco Corporation
SWEPCO	Southwestern Electric Power Company, a wholly owned subsidiary of American Electric Power Company, Inc.
Teche	Teche Electric Cooperative, Inc.
VaR	Value-at-risk
VIE	Variable Interest Entity

4

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Combined Quarterly Report on Form 10-Q includes “forward-looking statements” about future events, circumstances, and results.  All statements other than statements of historical fact included in this Combined Quarterly Report are forward-looking statements, including, without limitation, statements regarding Madison Unit 3; JPMVEC’s performance under the Evangeline 2010 Tolling Agreement; future capital expenditures; projections, including with respect to base revenue; business strategies; goals, beliefs, plans, and objectives; competitive strengths; market developments; development and operation of facilities; growth in sales volume; meeting capacity requirements, including through RFPs; expansion of service to certain customers and service to new customers; future environmental regulations and remediation liabilities; electric customer credits; and the anticipated outcome of various regulatory and legal proceedings.  Although the Registrants 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 Registrants’ 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 Registrants’ actual results to differ materially from those contemplated in any of the Registrants’ forward-looking statements:

§   Factors affecting utility operations, such as unusual weather conditions or other natural phenomena; catastrophic weather-related damage (such as hurricanes and other storms or severe drought conditions); unscheduled generation outages; unanticipated maintenance or repairs; unanticipated changes to fuel costs; fuel supply costs or availability constraints due to higher demand, shortages, transportation problems, or other developments; fuel mix of Cleco’s generation facilities; decreased customer load; environmental incidents; environmental compliance costs; and power transmission system constraints;

§   Cleco Corporation’s holding company structure and its dependence on the earnings, dividends, or distributions from its subsidiaries to meet its debt obligations and pay dividends on its common stock;

§   Cleco Power’s ability to operate and maintain, within its projected costs, any self-build projects identified in future IRP and RFP processes and its participation in any government grants;

§   Dependence of Cleco Power for energy from sources other than its facilities and the uncertainty of future sources of such additional energy;

§   Nonperformance by and creditworthiness of counterparties under tolling and power purchase agreements, or the restructuring of those agreements, including possible termination;

§   Nonperformance by and creditworthiness of the guarantor counterparty of the U.S. Bank New Markets Tax Credit Fund 2008-1 LLC;

§   Regulatory factors such as changes in rate-setting policies, recovery of investments made under traditional regulation, recovery of storm restoration costs, the frequency and timing of rate increases or decreases, the results of periodic NERC audits and fuel audits, the formation of ICTs, and the compliance with the Electric Reliability Organization reliability standards for bulk power systems by Cleco Power and Evangeline;

§   Financial or regulatory accounting principles or policies imposed by FASB, the SEC, the PCAOB, FERC, the LPSC, or similar entities with regulatory or accounting oversight;

§   Economic conditions, including the ability of customers to continue paying for utility bills, related growth and/or down-sizing of businesses in Cleco’s service area, monetary fluctuations, changes in commodity prices, and inflation rates;

§   The current global and U.S. economic environment;

§   Credit ratings of Cleco Corporation and Cleco Power;

§   Ability to remain in compliance with debt covenants;

§   Changes in market conditions and a variety of other factors associated with physical energy, financial transactions, and energy service activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rates, and warranty risks;

§   The availability and use of alternative sources of energy and technologies;

§   The imposition of energy efficiency requirements or of increased conservation efforts of customers;

§   Reliability of all Cleco Power and Midstream generating facilities, particularly Madison Unit 3;

§   Acts of terrorism or other man-made disasters;

§   Availability or cost of capital resulting from changes in Cleco’s business or financial condition, interest rates, or market perceptions of the electric utility industry and energy-related industries;

§   Uncertain tax positions;

§   Employee work force factors, including work stoppages and changes in key executives;

§   Legal, environmental, and regulatory delays and other obstacles associated with mergers, acquisitions, reorganizations, investments in joint ventures, or other capital projects, including the joint project to upgrade the Acadiana Load Pocket transmission system, and the AMI project;

§   Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters;

5

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

§   Changes in federal, state, or local laws, and changes in tax laws or rates, or regulating policies;

§   The impact of current or future environmental laws and regulations, including those related to greenhouse gases and energy efficiency, which could limit, or terminate, the operation of certain generating units, increase costs, reduce customer demand for electricity or otherwise materially adversely impact the Registrants’ financial condition or results of operations;

§   Ability of Cleco Power to recover from its customers the costs of compliance with environmental laws and regulations; and

§   Ability of the Dolet Hills lignite reserve to provide sufficient fuel to the Dolet Hills Power Station until at least 2026.

For additional discussion of these factors and other factors that could cause actual results to differ materially from those contemplated in the Registrants’ forward-looking statements, please read “Risk Factors” in the Registrants’ Combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, and the Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  All subsequent written and oral forward-looking statements attributable to the Registrants or persons acting on their behalf are expressly qualified in their entirety by the factors identified above.

The Registrants undertake no obligation to update any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

6

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

PART I — FINANCIAL INFORMATION

ITEM 1.CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cleco Corporation

These unaudited condensed consolidated financial statements should be read in conjunction with Cleco Corporation’s Consolidated Financial Statements and Notes included in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  For additional information on the basis of presentation, see “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”

7

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Income (Unaudited)

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)	2011			2010
Operating revenue
Electric operations	$	324,532		$	325,629
Tolling operations		9,133			11,153
Other operations		16,064			13,305
Affiliate revenue		-			119
Gross operating revenue		349,729			350,206
Electric customer credits		1,852			(6,314	)
Operating revenue, net		351,581			343,892
Operating expenses
Fuel used for electric generation		122,774			100,587
Power purchased for utility customers		24,739			51,678
Other operations		32,872			30,288
Maintenance		14,587			23,362
Depreciation		30,557			28,847
Taxes other than income taxes		9,845			9,123
Loss on sale of assets		27			20
Total operating expenses		235,401			243,905
Operating income		116,180			99,987
Interest income		509			128
Allowance for other funds used during construction		902			887
Equity (loss) income from investees, before tax		(1	)		2,494
Other income		2,128			2,755
Other expense		(3,360	)		(1,416	)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net		26,105			25,404
Allowance for borrowed funds used during construction		(326	)		(336	)
Total interest charges		25,779			25,068
Income before income taxes		90,579			79,767
Federal and state income tax expense		24,737			30,155
Net income		65,842			49,612
Preferred dividends requirements, net of tax		-			12
Net income applicable to common stock	$	65,842		$	49,600
Average number of basic common shares outstanding		60,467,595			60,471,183
Average number of diluted common shares outstanding		60,873,311			60,825,298
Basic earnings per share
Net income applicable to common stock	$	1.09		$	0.82
Diluted earnings per share
Net income applicable to common stock	$	1.08		$	0.82
Cash dividends paid per share of common stock	$	0.28		$	0.25
The accompanying notes are an integral part of the condensed consolidated financial statements.

8

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Net income	$	65,842		$	49,612
Other comprehensive loss, net of tax:
Amortization of post-retirement benefit net income (net of tax expense of $178 in 2011 and $6 in 2010)		269			9
Cash flow hedges:
Net derivatives loss on interest rate swap arising during the period (net of tax benefit of $145 in 2010)		-			(231	)
Reclassification of interest expense on interest rate swap (net of tax expense of $75 in 2010)		-			119
Reclassification of interest expense on treasury rate lock (net of tax benefit of $34 in 2011 and $16 in 2010)		(55	)		(25	)
Net unrealized loss on treasury rate lock (net of tax benefit of $11,529 in 2011)		(18,433	)		-
Total other comprehensive loss, net of tax		(18,219	)		(128	)
Comprehensive income, net of tax	$	47,623		$	49,484
The accompanying notes are an integral part of the condensed consolidated financial statements.

9

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Income (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)	2011			2010
Operating revenue
Electric operations	$	823,484		$	839,528
Tolling operations		16,137			23,016
Other operations		41,775			34,425
Affiliate revenue		202			1,426
Gross operating revenue		881,598			898,395
Electric customer credits		(3,405	)		(6,314	)
Operating revenue, net		878,193			892,081
Operating expenses
Fuel used for electric generation		298,009			276,727
Power purchased for utility customers		58,665			124,404
Other operations		92,206			86,786
Maintenance		59,666			58,832
Depreciation		89,641			82,899
Taxes other than income taxes		28,770			26,490
Gain on sale of assets		(468	)		(37	)
Total operating expenses		626,489			656,101
Operating income		251,704			235,980
Interest income		794			369
Allowance for other funds used during construction		3,757			11,052
Income from equity investees, before tax		62,051			39,212
Gain on toll settlement		-			148,402
Other income		3,330			3,563
Other expense		(4,969	)		(4,379	)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net		79,368			76,074
Allowance for borrowed funds used during construction		(1,357	)		(4,054	)
Total interest charges		78,011			72,020
Income before income taxes		238,656			362,179
Federal and state income tax expense		73,451			127,411
Net income		165,205			234,768
Preferred dividends requirements, net of tax		26			35
Preferred stock redemption costs, net of tax		112			-
Net income applicable to common stock	$	165,067		$	234,733
Average number of basic common shares outstanding		60,549,860			60,405,388
Average number of diluted common shares outstanding		60,830,251			60,632,138
Basic earnings per share
Net income applicable to common stock	$	2.73		$	3.89
Diluted earnings per share
Net income applicable to common stock	$	2.71		$	3.87
Cash dividends paid per share of common stock	$	0.81		$	0.725
The accompanying notes are an integral part of the condensed consolidated financial statements.

10

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Net income	$	165,205		$	234,768
Other comprehensive loss, net of tax:
Amortization of post-retirement benefit net income (loss) (net of tax (expense) benefit of $(454) in 2011 and $6 in 2010)		910			(9	)
Cash flow hedges:
Net derivatives loss on interest rate swap arising during the period (net of tax benefit of $276 in 2010)		-			(441	)
Reclassification of interest expense on interest rate swap (net of tax expense of $228 in 2010)		-			364
Reclassification of interest expense on treasury rate lock (net of tax benefit of $103 in 2011 and $48 in 2010)		(164	)		(77	)
Net unrealized loss on treasury rate lock (net of tax benefit of $11,529 in 2011)		(18,433	)		-
Total other comprehensive loss, net of tax		(17,687	)		(163	)
Comprehensive income, net of tax	$	147,518		$	234,605
The accompanying notes are an integral part of the condensed consolidated financial statements.

11

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Balance Sheets (Unaudited)

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Assets
Current assets
Cash and cash equivalents	$	158,232		$	191,128
Restricted cash		3,554			14,959
Customer accounts receivable (less allowance for doubtful accounts of $1,177 in 2011 and $1,046 in 2010)		52,299			38,820
Accounts receivable - affiliate		-			831
Other accounts receivable (less allowance for doubtful accounts of $1,985 in 2011 and $2,409 in 2010)		49,290			52,546
Taxes receivable		36,705			50,104
Unbilled revenue		33,112			44,649
Fuel inventory, at average cost		38,070			82,737
Material and supplies inventory, at average cost		52,257			48,265
Accumulated deferred federal and state income taxes, net		25,057			4,106
Accumulated deferred fuel		9,162			10,348
Cash surrender value of company-/trust-owned life insurance policies		50,628			49,789
Prepayments		5,004			6,399
Regulatory assets - other		12,869			13,508
Other current assets		4,745			661
Total current assets		530,984			608,850
Property, plant and equipment
Property, plant and equipment		3,859,621			3,810,896
Accumulated depreciation		(1,218,818	)		(1,162,456	)
Net property, plant and equipment		2,640,803			2,648,440
Construction work in progress		223,640			135,785
Total property, plant and equipment, net		2,864,443			2,784,225
Equity investment in investees		13,081			86,732
Prepayments		4,580			5,274
Restricted cash, less current portion		25,349			26,089
Regulatory assets and liabilities - deferred taxes, net		213,847			203,696
Regulatory assets - other		249,410			266,431
Net investment in direct financing lease		13,676			13,817
Intangible asset		136,393			145,374
Other deferred charges		19,778			20,922
Total assets	$	4,071,541		$	4,161,410
The accompanying notes are an integral part of the condensed consolidated financial statements.

(Continued on next page)

12

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Balance Sheets (Unaudited) (Continued)

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Liabilities and shareholders’ equity
Liabilities
Current liabilities
Short-term debt	$	-		$	150,000
Long-term debt due within one year		13,108			12,269
Accounts payable		93,186			123,042
Retainage		3,231			2,726
Accounts payable - affiliate		-			155
Customer deposits		42,181			38,934
Provision for rate refund		3,917			9,598
Interest accrued		62,377			34,462
Energy risk management liability, net		5,159			9,027
Interest rate risk management liability		29,962			-
Regulatory liabilities - other		33,272			43,562
Deferred compensation		7,562			7,751
Uncertain tax positions		42,674			31,853
Other current liabilities		14,784			14,302
Total current liabilities		351,413			477,681
Deferred credits
Accumulated deferred federal and state income taxes, net		624,429			553,211
Accumulated deferred investment tax credits		7,741			8,669
Post-retirement benefit obligations		109,865			166,387
Regulatory liabilities - other		7,026			44,313
Restricted storm reserve		24,656			25,993
Uncertain tax positions		47,715			60,395
Tax credit fund investment, net		48,494			44,514
Contingent sale obligations		29,443			4,714
Other deferred credits		44,070			57,617
Total deferred credits		943,439			965,813
Long-term debt, net		1,370,576			1,399,709
Total liabilities		2,665,428			2,843,203
Commitments and Contingencies (Note 11)
Shareholders’ equity
Preferred stock
Not subject to mandatory redemption, $100 par value, authorized 1,491,900 shares, issued 0 and 10,288 shares at September 30, 2011 and December 31, 2010, respectively		-			1,029
Common shareholders’ equity
Common stock, $1 par value, authorized 100,000,000 shares, issued 60,683,947 and 60,539,624 shares and outstanding 60,273,131 and 60,526,126 shares at September 30, 2011, and            December 31, 2010, respectively		60,684			60,540
Premium on common stock		409,040			405,313
Retained earnings		978,942			863,237
Treasury stock, at cost, 410,816 and 13,498 shares at September 30, 2011, and December 31, 2010, respectively		(13,228	)		(274	)
Accumulated other comprehensive loss		(29,325	)		(11,638	)
Total common shareholders’ equity		1,406,113			1,317,178
Total shareholders’ equity		1,406,113			1,318,207
Total liabilities and shareholders’ equity	$	4,071,541		$	4,161,410
The accompanying notes are an integral part of the condensed consolidated financial statements.

13

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Operating activities
Net income	$	165,205		$	234,768
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		114,104			124,144
Gain on forgiveness of debt		-			(129,870	)
Return on equity investment in investee		58,665			-
Income from equity investments		(62,051	)		(39,212	)
Unearned compensation expense		6,065			3,947
Allowance for other funds used during construction		(3,757	)		(11,052	)
Net deferred income taxes		45,336			40,013
Deferred fuel costs		(6,422	)		13,994
Cash surrender value of company-/trust-owned life insurance		1,055			(1,481	)
Changes in assets and liabilities:
Accounts receivable		(18,274	)		(30,329	)
Accounts and notes receivable, affiliate		1,074			894
Unbilled revenue		11,538			(23,359	)
Fuel, materials and supplies inventory		40,675			(11,979	)
Prepayments		2,089			1,047
Accounts payable		(34,986	)		(13,277	)
Accounts and notes payable, affiliate		(552	)		(2,364	)
Customer deposits		9,718			9,490
Long-term receivable		-			27,976
Post-retirement benefit obligations		(56,743	)		503
Regulatory assets and liabilities, net		(40,204	)		(77,331	)
Contingent sale obligations		10,900			4,800
Other deferred accounts		(2,184	)		7,363
Retainage payable		(2,481	)		-
Taxes accrued		12,946			51,597
Interest accrued		10,738			9,606
Energy risk management assets and liabilities, net		3,880			6,340
Other operating		(3,692	)		(3,860	)
Net cash provided by operating activities		262,642			192,368
Investing activities
Additions to property, plant and equipment		(145,669	)		(252,711	)
Allowance for other funds used during construction		3,757			11,052
Cash from reconsolidation of VIEs		3,879			812
Return of equity investment in investee		89,654			-
Equity investment in investees		-			(8,700	)
Return of investment in tax credit fund		244			-
Contributions to tax credit fund		(18,479	)		(28,837	)
Transfer of cash from restricted accounts		12,144			45,243
Other investing		373			(1,678	)
Net cash used in investing activities	$	(54,097	)	$	(234,819	)

(Continued on next page)

14

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited) (Continued)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Financing activities
Issuance of short-term debt	$	-		$	150,000
Retirement of short-term debt		(150,000	)		-
Draws on credit facility		10,000			255,000
Payments on credit facility		(25,000	)		(350,000	)
Retirement of long-term debt		(12,269	)		(46,696	)
Repurchase of common stock		(13,009	)		-
Redemption of preferred stock		(1,039	)		-
Dividends paid on preferred stock		(26	)		(35	)
Dividends paid on common stock		(49,170	)		(43,848	)
Other financing		(928	)		673
Net cash used in financing activities		(241,441	)		(34,906	)
Net decrease in cash and cash equivalents		(32,896	)		(77,357	)
Cash and cash equivalents at beginning of period		191,128			145,193
Cash and cash equivalents at end of period	$	158,232		$	67,836
Supplementary cash flow information
Interest paid (net of amount capitalized)	$	53,936		$	55,623
Income taxes paid	$	18,241		$	17,047
Supplementary non-cash investing and financing activities
Accrued additions to property, plant and equipment	$	11,491		$	5,314
Issuance of treasury stock - LTICP	$	55		$	74
Issuance of common stock - LTICP/ESPP	$	241		$	222
Non-cash additions to property, plant and equipment	$	4,074		$	152,067
Non-cash return of investment	$	-		$	152,067
Non-cash contribution to subsidiary, net of tax	$	-		$	225,732
The accompanying notes are an integral part of the condensed consolidated financial statements.

15

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

PART I — FINANCIAL INFORMATION

ITEM 1.CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cleco Power

These unaudited condensed consolidated financial statements should be read in conjunction with Cleco Power’s Consolidated Financial Statements and Notes included in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  For additional information on the basis of presentation, see “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”

16

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Statements of Income (Unaudited)

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)	2011			2010
Operating revenue
Electric operations	$	324,532		$	325,629
Other operations		15,565			12,819
Affiliate revenue		347			343
Gross operating revenue		340,444			338,791
Electric customer credits		1,852			(6,314	)
Operating revenue, net		342,296			332,477
Operating expenses
Fuel used for electric generation		122,774			100,587
Power purchased for utility customers		24,739			51,678
Other operations		31,185			28,650
Maintenance		15,768			20,272
Depreciation		28,859			27,133
Taxes other than income taxes		8,802			9,161
(Gain) loss on sale of assets		(6	)		7
Total operating expenses		232,121			237,488
Operating income		110,175			94,989
Interest income		276			117
Allowance for other funds used during construction		902			887
Other income		1,323			293
Other expense		(1,881	)		(1,339	)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net		25,632			16,380
Allowance for borrowed funds used during construction		(326	)		(336	)
Total interest charges		25,306			16,044
Income before income taxes		85,489			78,903
Federal and state income tax expense		31,656			26,568
Net income	$	53,833		$	52,335
The accompanying notes are an integral part of the condensed consolidated financial statements.

17

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Net income	$	53,833		$	52,335
Other comprehensive loss, net of tax:
Amortization of post-retirement benefit net income (loss) (net of tax (expense) benefit of $(99) in 2011 and $55 in 2010)		146			(89	)
Cash flow hedges:
Net derivatives loss on interest rate swap arising during the period (net of tax benefit of $145 in 2010)		-			(231	)
Reclassification of interest expense on interest rate swap (net of tax expense of $75 in 2010)		-			119
Reclassification of interest expense on treasury rate lock (net of tax benefit of $34 in 2011 and $16 in 2010)		(55	)		(25	)
Net unrealized loss on treasury rate lock (net of tax benefit of $11,529 in 2011)		(18,433	)		-
Total other comprehensive loss, net of tax		(18,342	)		(226	)
Comprehensive income, net of tax	$	35,491		$	52,109
The accompanying notes are an integral part of the condensed consolidated financial statements.

18

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Statements of Income (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Operating revenue
Electric operations	$	823,484		$	839,528
Other operations		40,261			32,959
Affiliate revenue		1,041			1,029
Gross operating revenue		864,786			873,516
Electric customer credits		(3,405	)		(6,314	)
Operating revenue, net		861,381			867,202
Operating expenses
Fuel used for electric generation		298,009			276,727
Power purchased for utility customers		58,665			124,404
Other operations		87,086			81,111
Maintenance		53,962			51,697
Depreciation		84,543			77,941
Taxes other than income taxes		25,585			25,110
(Gain) loss on sale of assets		(7	)		47
Total operating expenses		607,843			637,037
Operating income		253,538			230,165
Interest income		557			351
Allowance for other funds used during construction		3,757			11,052
Other income		2,168			1,038
Other expense		(4,499	)		(3,619	)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net		75,386			61,158
Allowance for borrowed funds used during construction		(1,357	)		(4,054	)
Total interest charges		74,029			57,104
Income before income taxes		181,492			181,883
Federal and state income tax expense		61,935			58,299
Net income	$	119,557		$	123,584
The accompanying notes are an integral part of the condensed consolidated financial statements.

19

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Net income	$	119,557		$	123,584
Other comprehensive loss, net of tax:
Amortization of post-retirement benefit net income (loss) (net of tax (expense) benefit of $(227) in 2011 and $172 in 2010)		519			(274	)
Cash flow hedges:
Net derivatives loss on interest rate swap arising during the period (net of tax benefit of $276 in 2010)		-			(441	)
Reclassification of interest expense on interest rate swap (net of tax expense of $228 in 2010)		-			364
Reclassification of interest expense on treasury rate lock (net of tax benefit of $103 in 2011 and $48 in 2010)		(164	)		(77	)
Net unrealized loss on treasury rate lock (net of tax benefit of $11,529 in 2011)		(18,433	)		-
Total other comprehensive loss, net of tax		(18,078	)		(428	)
Comprehensive income, net of tax	$	101,479		$	123,156
The accompanying notes are an integral part of the condensed consolidated financial statements.

20

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Balance Sheets (Unaudited)

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Assets
Utility plant and equipment
Property, plant and equipment	$	3,604,938		$	3,552,779
Accumulated depreciation		(1,142,414	)		(1,085,945	)
Net property, plant and equipment		2,462,524			2,466,834
Construction work in progress		214,071			130,396
Total utility plant, net		2,676,595			2,597,230
Current assets
Cash and cash equivalents		143,015			184,912
Restricted cash		3,554			14,959
Customer accounts receivable (less allowance for doubtful accounts of $1,177 in 2011 and $1,046 in 2010)		52,299			38,820
Accounts receivable - affiliate		2,802			2,738
Other accounts receivable (less allowance for doubtful accounts of $1,924 in 2011 and $2,349 in 2010)		29,323			47,992
Taxes receivable		-			4,123
Unbilled revenue		33,112			44,649
Fuel inventory, at average cost		38,070			82,737
Material and supplies inventory, at average cost		49,634			45,913
Accumulated deferred federal and state income taxes, net		38,248			2,811
Accumulated deferred fuel		9,162			10,348
Cash surrender value of company-owned life insurance policies		20,328			20,051
Prepayments		3,782			4,944
Regulatory assets - other		12,869			13,508
Other current assets		597			412
Total current assets		436,795			518,917
Equity investment in investee		13,073			13,073
Prepayments		4,580			5,274
Restricted cash, less current portion		25,253			25,992
Regulatory assets and liabilities - deferred taxes, net		213,847			203,696
Regulatory assets - other		249,410			266,431
Intangible asset		136,393			145,374
Other deferred charges		18,439			19,218
Total assets	$	3,774,385		$	3,795,205
Liabilities and member’s equity
Member’s equity	$	1,235,402		$	1,233,923
Long-term debt, net		1,370,576			1,384,709
Total capitalization		2,605,978			2,618,632
Current liabilities
Long-term debt due within one year		13,108			12,269
Accounts payable		85,382			112,487
Retainage		3,231			2,726
Accounts payable - affiliate		7,332			7,945
Customer deposits		42,181			38,934
Provision for rate refund		3,917			9,598
Taxes payable		17,558			-
Interest accrued		31,825			13,450
Energy risk management liability, net		5,159			9,027
Interest rate risk management liability		29,962			-
Regulatory liabilities - other		33,272			43,562
Uncertain tax positions		2,602			-
Other current liabilities		12,080			9,862
Total current liabilities		287,609			259,860
Commitments and Contingencies (Note 11)
Deferred credits
Accumulated deferred federal and state income taxes, net		680,287			601,574
Accumulated deferred investment tax credits		7,741			8,669
Post-retirement benefit obligations		72,466			130,757
Regulatory liabilities - other		7,026			44,313
Restricted storm reserve		24,656			25,993
Uncertain tax positions		45,014			54,835
Other deferred credits		43,608			50,572
Total deferred credits		880,798			916,713
Total liabilities and member’s equity	$	3,774,385		$	3,795,205
The accompanying notes are an integral part of the condensed consolidated financial statements.

21

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

CLECO POWER

Condensed Consolidated Statements of Cash Flows (Unaudited)

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Operating activities
Net income	$	119,557		$	123,584
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		95,482			88,607
Unearned compensation expense		1,768			1,303
Allowance for other funds used during construction		(3,757	)		(11,052	)
Net deferred income taxes		35,174			20,628
Deferred fuel costs		(6,422	)		13,994
Cash surrender value of company-owned life insurance		(277	)		(236	)
Changes in assets and liabilities:
Accounts receivable		(20,442	)		(31,579	)
Accounts and notes receivable, affiliate		68			(1,977	)
Unbilled revenue		11,538			(23,359	)
Fuel, materials and supplies inventory		40,946			(11,707	)
Prepayments		1,858			974
Accounts payable		(30,345	)		(12,137	)
Accounts and notes payable, affiliate		(1,386	)		(18,524	)
Customer deposits		9,718			9,490
Post-retirement benefit obligations		(58,259	)		(1,020	)
Regulatory assets and liabilities, net		(40,204	)		(77,331	)
Other deferred accounts		(6,361	)		(4,021	)
Retainage payable		(2,481	)		-
Taxes accrued		21,680			20,858
Interest accrued		11,075			9,297
Energy risk management assets and liabilities, net		3,880			6,340
Other operating		1,878			(2,444	)
Net cash provided by operating activities		184,688			99,688
Investing activities
Additions to property, plant and equipment		(131,014	)		(98,399	)
Allowance for other funds used during construction		3,757			11,052
Equity investment in investee		-			(200	)
Transfer of cash from restricted accounts		12,144			15,111
Other investing		2,257			(83	)
Net cash used in investing activities		(112,856	)		(72,519	)
Financing activities
Retirement of long-term debt		(12,269	)		(11,533	)
Distribution to parent		(100,000	)		(125,000	)
Other financing		(1,460	)		(1,365	)
Net cash used in financing activities		(113,729	)		(137,898	)
Net decrease in cash and cash equivalents		(41,897	)		(110,729	)
Cash and cash equivalents at beginning of period		184,912			138,113
Cash and cash equivalents at end of period	$	143,015		$	27,384
Supplementary cash flow information
Interest paid (net of amount capitalized)	$	52,220		$	48,155
Income taxes paid (refunded)	$	2,233		$	(5,425	)
Supplementary non-cash investing and financing activities
Accrued additions to property, plant and equipment	$	20,088		$	4,757
Non-cash additions to property, plant and equipment	$	4,074		$	304,134
Non-cash assumption of deferred tax liability	$	-		$	78,402
The accompanying notes are an integral part of the condensed consolidated financial statements.

22

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Index to Applicable Notes to the Unaudited Condensed Consolidated Financial Statements of Registrants

Note 1	Summary of Significant Accounting Policies	Cleco Corporation and Cleco Power
Note 2	Recent Authoritative Guidance	Cleco Corporation and Cleco Power
Note 3	Regulatory Assets and Liabilities	Cleco Corporation and Cleco Power
Note 4	Fair Value Accounting	Cleco Corporation and Cleco Power
Note 5	Debt	Cleco Corporation and Cleco Power
Note 6	Pension Plan and Employee Benefits	Cleco Corporation and Cleco Power
Note 7	Income Taxes	Cleco Corporation and Cleco Power
Note 8	Disclosures about Segments	Cleco Corporation
Note 9	Electric Customer Credits	Cleco Corporation and Cleco Power
Note 10	Variable Interest Entities	Cleco Corporation and Cleco Power
Note 11	Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees	Cleco Corporation and Cleco Power
Note 12	LPSC Fuel Audit	Cleco Corporation and Cleco Power
Note 13	Affiliate Transactions	Cleco Corporation and Cleco Power
Note 14	Evangeline Transactions	Cleco Corporation
Note 15	Acadia Transactions	Cleco Corporation and Cleco Power
Note 16	Subsequent Event	Cleco Corporation

Notes to the Unaudited Condensed Consolidated Financial Statements

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation

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

Prior to April 30, 2011, Cleco reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2 to Entergy Louisiana, APH received 100% ownership in Acadia in exchange for its 50% ownership interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Following the disposition, Acadia’s assets, liabilities, revenues, expenses, and cash flows are presented on the corresponding line items of Cleco’s Condensed Consolidated Financial Statements, prospectively.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.  For additional information on the operations of these entities, see Note 10 — “Variable Interest Entities.”

Basis of Presentation

The condensed consolidated financial statements of Cleco Corporation and Cleco Power have been prepared pursuant to the rules and regulations of the SEC.  Accordingly, certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted; however, Cleco believes that the disclosures are adequate to make the information presented not misleading.

The year-end condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  The unaudited financial information included in the condensed consolidated financial statements of Cleco Corporation and Cleco Power reflects all adjustments of a normal recurring nature which are, in the opinion of the management of Cleco Corporation and Cleco Power, necessary for a fair statement of the financial position and the results of operations for the interim periods.  Information for interim periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery, and other factors, and is not indicative necessarily of the results that may be expected for the full fiscal year.  For additional information on recent authoritative guidance and its effect on financial results, see Note 2 — “Recent Authoritative Guidance.”

Property, Plant and Equipment

Property, plant and equipment consist primarily of regulated utility generation and energy transmission assets.  Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction.  Jointly owned assets are reflected in property, plant and equipment at Cleco Power’s share of the cost to construct or purchase the assets.  

23

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Property, plant and equipment consist of:

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Regulated utility plants	$	3,604,938		$	3,552,054
Other		254,683			258,842
Total property, plant and equipment		3,859,621			3,810,896
Accumulated depreciation		(1,218,818	)		(1,162,456	)
Net property, plant and equipment	$	2,640,803		$	2,648,440

Restricted Cash

Various agreements to which Cleco is subject contain covenants that restrict its use of cash.  As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general corporate purposes.  Cleco’s restricted cash consisted of:  

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Power’s future storm restoration costs		24,652		25,992
Cleco Power’s renewable energy grant		600		-
Cleco Katrina/Rita’s storm recovery bonds		3,554		8,822
Cleco Power’s GO Zone bonds		-		6,137
Total restricted cash	$	28,903	$	41,048

Cleco Katrina/Rita has the right to bill and collect storm restoration costs from Cleco Power’s customers.  As cash is collected, it is restricted for payment of operating expenses, interest, and principal on storm recovery bonds.  During 2011, Cleco Katrina/Rita has collected $14.5 million net of operating expenses.  In March and September 2011, Cleco Katrina/Rita used $6.3 million and $6.0 million, respectively for scheduled storm recovery bond principal payments and $3.8 million and $3.7 million, respectively for related interest.  In 2011, Cleco Power received a renewable energy grant from the Louisiana Department of Natural Resources.  

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values.  Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance.  Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes under GAAP.  Other financial assets and liabilities, such as long-term debt, are reported at their carrying values at their date of issuance on the condensed consolidated balance sheets with their fair values disclosed without regard to the three levels.  For additional information about fair value levels, see Note 4 — “Fair Value Accounting.”

Risk Management

Market risk inherent in Cleco Power’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas on different energy exchanges.  

Commodity Market Price Risk

Cleco’s Energy Market Risk Management Policy authorizes the use of various derivative instruments, including exchange traded futures and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations in the price of power and natural gas.  Cleco applies the authoritative guidance as it relates to derivatives and hedging to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market.  Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting because Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements.  Cleco Power entered into certain financial transactions it considered economic hedges to mitigate the risk associated with a contract for fixed-price power provided to a wholesale customer through December 2010.  These transactions were marked-to-market with the resulting gain or loss recorded on the income statement as a component of operating revenue.  The contract expired on December 31, 2010 along with the economic hedges; therefore, no gain or loss related to the economic hedges was recorded during the three and nine months ended September 30, 2011.  For the three and nine months ended September 30, 2010, Cleco Power had realized losses of $0.3 million and $0.8 million and mark-to-market gains of $0.2 million for both periods recorded in other operations revenue.  

Cleco Power has entered into other positions to mitigate the volatility in customer fuel costs.  These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of energy risk management assets or liabilities.  Such gain or loss is deferred as a component of deferred fuel assets or liabilities.  When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers’ bills as a component of the fuel cost adjustment.  Based on market prices at September 30, 2011, and December 31, 2010, the net mark-to-market impact relating to these positions were losses of $5.7 million and $15.1 million, respectively.  Deferred losses relating to closed natural gas positions totaled $1.3 million and $1.6 million at September 30, 2011, and December 31, 2010, respectively.

Cleco Power maintains margin accounts with commodity brokers used to partially fund the acquisition of natural gas futures, options, and swap contracts.  These contracts/positions are used to mitigate the risks associated with the volatility in customer fuel costs noted above.  At September 30, 2011, and December 31, 2010, Cleco Power had deposited net collateral of $0.5 million and $4.3 million, respectively, to cover requirements relating to open natural gas futures, options, and swap positions.  The current and long-term portions of collateral are reported as a component of energy risk management assets or liabilities and other deferred credits, respectively.

Cleco and Cleco Power maintain a master netting agreement policy and monitor credit risk exposure through review of counterparty credit quality, counterparty credit exposure, and

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counterparty concentration levels.  Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and by requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Cleco Power has agreements in place with various counterparties that authorize the netting of financial buys and sells and contract payments to mitigate credit risk for transactions entered into for risk management purposes.  

Interest Rate Risk

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011 or the date of issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.  Management determined that the forecasted debt issuance is probable of occurring before or on November 14, 2011, and in an amount at least equal to the treasury rate lock contract’s notional amount.  When the forecasted debt issuance occurs and the treasury rate lock contract is settled, the effective portion of the settlement will be recognized in accumulated other comprehensive income and any ineffective portion will be reclassified into the income statement.  

For additional information on accounting for derivatives, see Note 4 — “Fair Value Accounting.”

Reclassifications

Certain reclassifications have been made to the 2010 financial statements to conform them to the presentation used in the 2011 financial statements.  These reclassifications had no effect on Cleco Corporation’s net income applicable to common stock or total common shareholder’s equity or Cleco Power’s net income or total member’s equity.

The Registrants determined that an error existed in the statement of cash flow methodology for determining non-cash transactions related to property, plant and equipment, specifically the dollar amount of property, plant and equipment acquisitions included in accounts payable.  This caused errors between the operating activities section and investing activities section for prior periods, including 2008, 2009, and 2010.

Cleco and Cleco Power’s Condensed Consolidated Statements of Cash Flows for the period ended September 30, 2010, have been adjusted to correct the presentation of cash flows related to accruals for property, plant and equipment.  These corrections had no impact on the Registrants’ financial condition or results of operations.  Management believes that these corrections did not have a material effect on the Registrants’ Condensed Consolidated Statements of Cash Flows. The corrections to the September 30, 2010 Condensed Consolidated Statements of Cash Flows are presented in the following table.

	CLECO						CLECO POWER
	FOR THE NINE MONTHS ENDED						FOR THE NINE MONTHS ENDED
	SEPTEMBER 30, 2010						SEPTEMBER 30, 2010
(THOUSANDS)	AS REPORTED			AS ADJUSTED			AS REPORTED			AS ADJUSTED
Accounts receivable	$	(49,329	)	$	(30,329	)	$	(50,579	)	$	(31,579	)
Accounts payable	$	(17,248	)	$	(13,277	)	$	(16,621	)	$	(12,137	)
Retainage payable	$	745		$	-		$	745		$	-
Net cash provided by operating activities	$	170,141		$	192,368		$	76,949		$	99,688
Additions to property, plant and equipment	$	(230,485	)	$	(252,711	)	$	(75,660	)	$	(98,399	)
Net cash used in investing activities	$	(212,592	)	$	(234,819	)	$	(49,780	)	$	(72,519	)
Net decrease in cash and cash equivalents	$	(77,357	)	$	(77,357	)	$	(110,729	)	$	(110,729	)
Cash and cash equivalents at the beginning of the period	$	145,193		$	145,193		$	138,113		$	138,113
Cash and cash equivalents at the end of the period	$	67,836		$	67,836		$	27,384		$	27,384
Accrued additions to property, plant and equipment	$	17,506		$	5,314		$	17,506		$	4,757

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CLECO POWER	2011 3RD QUARTER FORM 10-Q

Earnings per Average Common Share

The following table shows the calculation of basic and diluted earnings per share.

							FOR THE THREE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	65,842					$	49,612
Deduct:  non-participating stock dividends (4.5% preferred stock)		-						12
Basic net income applicable to common stock	$	65,842		60,467,595	$	1.09	$	49,600		60,471,183	$	0.82
Effect of dilutive securities
Add:  stock option grants				20,441						26,680
Add:  restricted stock (LTICP)				385,275						327,435
Diluted net income applicable to common stock	$	65,842		60,873,311	$	1.08	$	49,600		60,825,298	$	0.82

							FOR THE NINE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	165,205					$	234,768
Deduct:  non-participating stock dividends (4.5% preferred stock)		26						35
Deduct:  non-participating stock redemption costs (4.5% preferred stock)		112						-
Basic net income applicable to common stock	$	165,067		60,549,860	$	2.73	$	234,733		60,405,388	$	3.89
Effect of dilutive securities
Add:  stock option grants				20,965						29,771
Add:  restricted stock (LTICP)				259,426						196,979
Diluted net income applicable to common stock	$	165,067		60,830,251	$	2.71	$	234,733		60,632,138	$	3.87

Stock option grants are excluded from the computation of diluted earnings per share if the exercise price is higher than the average market price.  There were no stock option grants excluded from the computation of diluted earnings per share for the three and nine months ended September 30, 2011 and 2010, due to the average market price being higher than the exercise prices of the stock options.  

Preferred Stock Redemption

On June 24, 2011, Cleco Corporation redeemed all 10,288 outstanding shares of its 4.5% preferred stock.  The redemption price was $101 per share plus accrued and unpaid dividends to the redemption date, or $101.296 per share.  As of the redemption date, no shares of 4.5% preferred stock were outstanding.  Holders are no longer entitled to dividends and all rights of such holders as shareholders of Cleco Corporation by reason of their ownership of such 4.5% preferred stock have ceased.

Stock-Based Compensation

At September 30, 2011, Cleco had two stock-based compensation plans:  the ESPP and the LTICP.  Substantially all employees, excluding officers and general managers, may choose to participate in the ESPP and purchase a limited amount of common stock at a discount through a stock option agreement.  Options or restricted shares of stock, known as non-vested stock as defined by the authoritative guidance on stock-based compensation, common stock equivalents, and stock appreciation rights may be granted to certain officers, key employees, or directors of Cleco Corporation and its subsidiaries pursuant to the LTICP.  

On January 28, 2011, Cleco granted 145,002 shares of non-vested stock to certain officers, key employees, and directors of Cleco Corporation and its subsidiaries pursuant to the LTICP.  On July 5, 2011, Cleco granted an additional 40,000 shares of non-vested stock to certain officers of Cleco Corporation and its subsidiaries pursuant to the LTICP.

Cleco and Cleco Power reported pre-tax compensation expense for their share-based compensation plans as shown in the following table:

	CLECO CORPORATION				CLECO POWER				CLECO CORPORATION				CLECO POWER
			FOR THE THREE MONTHS ENDED SEPTEMBER 30,								FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010		2011		2010		2011		2010
Equity classification
Non-vested stock	$	1,095	$	573	$	225	$	150	$	3,042	$	1,703	$	748	$	418
Stock options		69		13		-		-		105		38		-		-
Total equity classification	$	1,164	$	586	$	225	$	150	$	3,147	$	1,741	$	748	$	418
Liability classification
Common stock equivalent units	$	1,024	$	1,237	$	435	$	537	$	2,583	$	1,867	$	1,020	$	885
Total pre-tax compensation expense	$	2,188	$	1,823	$	660	$	687	$	5,730	$	3,608	$	1,768	$	1,303
Tax benefit (excluding income tax gross-up)	$	842	$	702	$	254	$	264	$	2,205	$	1,388	$	680	$	501

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Note 2 — Recent Authoritative Guidance

The Registrants adopted, or will adopt, the recent authoritative guidance listed below on their respective effective dates.

In May 2010, FASB amended the authoritative guidance pertaining to compensation in order to clarify the issuance of stock options in currencies other than the ones in which employees are normally paid.  This amendment was effective for reporting periods that began on or after December 15, 2010.  The adoption of this amendment did not have an impact on the financial condition or results of operations of the Registrants.

In July 2010, FASB amended the authoritative guidance on receivables, which required companies to improve their disclosures about the credit quality of their financing receivables and the credit reserves held against them.  For public companies, the amendment was effective for interim and annual reporting periods ending on or after December 15, 2010, with specific items, such as allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010.  The adoption of this amendment did not have any effect on the financial condition or results of operations of the Registrants.

In December 2010, FASB amended the authoritative guidance on business combinations to expand supplemental pro forma disclosures and to require comparative prior period financial statement disclosures as if the combination occurred as of the beginning of the prior annual period.  The amendment was effective prospectively for business combination acquisition dates on or after the beginning of the first annual reporting period beginning on or after December 15, 2010.  The adoption of this amendment did not have any effect on the financial condition or results of operations of the Registrants.

In April 2011, FASB issued additional guidance to creditors for evaluating whether a modification or restructuring of a receivable is a troubled debt restructuring.  The implementation of this guidance was effective in the first interim or annual period beginning on or after June 15, 2011.  The adoption of this guidance did not have a material impact on the financial condition or results of operations of the Registrants.

In April 2011, FASB issued guidance to improve the accounting for repurchase agreements and other similar agreements.  Specifically, this guidance modifies the criteria for determining when these transactions would be accounted for as financings as opposed to sales or purchases with commitments to repurchase or resale.  The adoption of this guidance is effective in the first interim or annual period beginning on or after December 15, 2011.  The adoption of this guidance is not expected to have a material impact on the financial condition or results of operations of the Registrants.

In May 2011, FASB issued guidance on fair value measurements.  This guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS (International Financial Reporting Standards).  The adoption of this guidance is effective prospectively for interim and annual periods beginning after December 15, 2011.  The adoption of this guidance is not expected to have a material impact on the financial condition or results of operations of the Registrants.

In June 2011, FASB issued guidance on the presentation of comprehensive income. This guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The adoption of this guidance is effective for interim and annual periods beginning after December 15, 2011.  The adoption of this guidance will not have any impact on the financial condition or results of operations of the Registrants.

In September 2011, FASB revised the testing of goodwill for impairment.  The revision provides entities the option to first use qualitative factors to determine whether it is necessary to perform the quantitative two-step test.  The adoption of this guidance is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with some provisions for early adoption.  The adoption of this guidance will not have any impact on the financial condition or results of operations of the Registrants.

Note 3 — Regulatory Assets and Liabilities

Cleco Power follows the authoritative guidance on regulated operations, which allows utilities to capitalize or defer certain costs based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered through the ratemaking process.  The following chart summarizes Cleco Power’s regulatory assets and liabilities at September 30, 2011, and December 31, 2010:

	AT SEPTEMBER 30,			AT DECEMBER 31,
(THOUSANDS)	2011			2010
Regulatory assets – deferred taxes, net	$	213,847		$	203,696
Deferred mining costs	$	19,755		$	21,666
Deferred interest costs		6,758			7,033
Deferred asset removal costs		814			768
Deferred postretirement plan costs		113,538			117,651
Deferred tree trimming costs		9,057			11,086
Deferred training costs		7,525			7,642
Deferred storm surcredits, net		9,080			10,633
Deferred construction carrying costs		12,416			18,830
Lignite mining agreement contingency		3,781			3,781
AFUDC equity gross-up		74,496			74,859
Deferred rate case costs		1,252			1,654
Deferred Acadia Unit 1 acquisition costs		2,997			3,076
Deferred IRP/RFP costs		625			977
Deferred AMI pilot costs		185			283
Total regulatory assets – other	$	262,279		$	279,939
Deferred construction carrying costs		(40,298	)		(87,875	)
Deferred fuel and purchased power		9,162			10,348
Total regulatory assets, net	$	444,990		$	406,108

Deferred Construction Carrying Costs

In February 2006, the LPSC approved Cleco Power’s plans to build Madison Unit 3.  Terms of the approval included authorization for Cleco Power to collect from customers an amount equal to 75% of the LPSC-jurisdictional portion of the carrying costs of capital during the construction phase of the unit.  In any calendar year during the construction period, the amount collected from customers was not to exceed 6.5% of Cleco Power’s projected retail revenues.  Cleco Power began

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collection of the carrying costs and established a regulatory liability in May 2006.  In October 2009, the LPSC voted unanimously to approve Cleco Power’s retail rate plan.  The retail rate plan established that Cleco Power return $183.2 million of carrying costs to customers over a five-year period and record a regulatory asset for all carrying costs incurred by Cleco Power above the actual amount collected from customers.  On February 12, 2010, Madison Unit 3 commenced commercial operation and the new rates became effective.  At that time, Cleco Power began returning the construction carrying costs to customers and amortizing the regulatory asset over a five-year period.  In March 2010, the LPSC issued an order changing the period of return from five years to four years and established that Cleco Power return approximately $166.4 million over the four-year period.  At September 30, 2011, the regulatory liability and the related regulatory asset were $40.3 million and $12.4 million, respectively.  As of September 30, 2011, Cleco Power had returned $126.1 million to customers.  At September 30, 2011, $33.3 million was due to be returned to customers within one year.

Deferred Fuel and Purchased Power Costs

The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to its customers substantially all such charges.  For the three months ended September 30, 2011, approximately 94% of Cleco Power’s total fuel cost was regulated by the LPSC, while the remainder was regulated by FERC.  

The $1.2 million decrease in the under-recovered costs was primarily due to a $9.5 million decrease in mark-to-market losses on natural gas positions, which was primarily due to the contractual expiration of certain positions.  Partially offsetting this decrease was $8.5 million in additional deferred fuel and purchased power costs.

Note 4 — Fair Value Accounting

The amounts reflected in Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets at September 30, 2011, and December 31, 2010, for cash and cash equivalents, accounts receivable, other accounts receivable, accounts payable, and short-term debt approximate fair value because of their short-term nature.  Estimates of the fair value of Cleco and Cleco Power’s long-term debt and Cleco’s nonconvertible preferred stock are based upon the quoted market price for the same or similar issues or by a discounted present value analysis of future cash flows using current rates obtained by Cleco and Cleco Power for debt and by Cleco for preferred stock with similar maturities.  In June 2011, Cleco Corporation redeemed all of its outstanding preferred stock.  For more information on the preferred stock redemption, see Note 1 — “Summary of Significant Accounting Policies — Preferred Stock Redemption.”  The following charts summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments subject to fair value accounting.

Cleco

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	158,232	$	158,232	$	191,128	$	191,128
Restricted cash	$	28,903	$	28,903	$	41,048	$	41,048
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,403,836	$	1,462,063
Preferred stock not subject to mandatory redemption	$	-	$	-	$	1,029	$	844

Cleco Power

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	143,015	$	143,015	$	184,912	$	184,912
Restricted cash	$	28,807	$	28,807	$	40,951	$	40,951
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,388,836	$	1,447,063

At September 30, 2011, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash.  Cleco had $182.6 million ($153.7 million of cash and $28.9 million of restricted cash) in short-term investments in institutional money market funds.  If the money market funds failed to perform under the terms of the investment, Cleco would be exposed to a loss of the invested amounts.  Cleco Power had $168.3 million ($139.5 million of cash and $28.8 million of restricted cash) in short-term investments in institutional money market funds.  If the money market funds failed to perform under the terms of the investments, Cleco Power would be exposed to a loss of the invested amounts.  Collateral on these types of investments is not required by either Cleco or Cleco Power.  In order to mitigate credit risk, Cleco and Cleco Power have established guidelines for short-term investments.  Money market funds must have at least $1.0 billion in assets under management; must have been in existence for not less than two years; must have portfolios not comprised of more than 50% of securities issued by foreign entities; and must be rated in the top two ratings categories by at least one nationally recognized rating agency.  Commercial

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paper must be issued by a company with headquarters in the U.S. and rated not less than A1 by Standard & Poor’s or P1 by Moody’s.  For split-rated issuers, the second rating must not be lower than either A2 or P2; the issuer’s long-term debt must be rated not lower than A by Standard & Poor’s or A2 by Moody’s; and the issuer cannot be on negative credit watch.  Investments in commercial paper rated A2 by Standard & Poor’s or P2 by Moody’s may be made if approved by the appropriate level of management.  

Treasury Rate Lock

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011, or the date of issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  The fair market value of the treasury rate lock is based on the difference in the lock rate and the reference rate at the end of the period multiplied by the dollar value of a basis point.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.

Fair Value Measurements and Disclosures

The authoritative guidance on fair value measurements requires entities to classify assets and liabilities measured at their fair value according to three different levels depending on the inputs used in determining fair value.

The tables below disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis and within the scope of the authoritative guidance for fair value measurements and disclosures.

Cleco

	CLECO CONSOLIDATED FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		182,603		-		182,603		-		229,748		-		229,748		-
Total assets	$	182,603	$	-	$	182,603	$	-	$	229,845	$	-	$	229,845	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

Cleco Power

	CLECO POWER FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		168,307		-		168,307		-		224,451		-		224,451		-
Total assets	$	168,307	$	-	$	168,307	$	-	$	224,548	$	-	$	224,548	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

The derivative assets and liabilities are classified as either current or non-current depending on when the positions close.  All energy market derivative current assets and current liabilities are reported as a net current energy risk management asset or liability.  All energy market derivative non-current assets and non-current liabilities are reported net in other deferred charges or other deferred credits.  Net presentation is appropriate due to the right of offset included in the master netting agreements.  On the balance sheet, the net current and net non-current derivative positions are netted with the applicable margin deposits.  At September 30, 2011, a net current energy risk management liability of $5.2 million represented the current derivative positions of $5.7 million reduced by current margin deposits of $0.5 million and option premiums that were less than $0.1 million.  The institutional money market funds were reported on the Cleco Condensed

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CLECO POWER	2011 3RD QUARTER FORM 10-Q

Consolidated Balance Sheet in cash and cash equivalents, current restricted cash, and non-current restricted cash of $153.7 million, $3.6 million, and $25.3 million, respectively.  At Cleco Power, cash and cash equivalents, current restricted cash, and non-current restricted cash were $139.5 million, $3.6 million, and $25.2 million, respectively, as of September 30, 2011.  The treasury rate lock was reported on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as a current liability in the line item interest rate risk management liability as of September 30, 2011.

Cleco utilizes different valuation techniques for fair value calculations.  In order to measure the fair value for Level 1 assets and liabilities, Cleco obtains the closing price from published indices in active markets for the various instruments and multiplies this price by the appropriate number of instruments held.  Level 2 fair values for assets and liabilities are determined by obtaining the closing price from published indices in active markets for instruments that are similar to Cleco’s assets and liabilities.  The fair value obtained is then discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return.  For some options, Cleco uses the Black-Scholes model using observable and available inputs to calculate the fair value, consistent with the income approach.  These techniques have been applied consistently from fiscal period to fiscal period.  Level 3 fair values allow for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Cleco had no Level 3 assets or liabilities at September 30, 2011, or December 31, 2010.

The assets and liabilities reported at fair value are grouped into classes based on the underlying nature and risks associated with the individual asset or liability.  Level 1 of energy market derivative assets and liabilities consists of a single class that includes natural gas futures with quoted prices on a liquid, national exchange.  As the future price of natural gas is affected by market expectations, such as the supply of natural gas relative to demand, the fair value of Cleco’s natural gas futures fluctuates.

Level 2 of energy market derivative assets and liabilities consists of two classes.  The first class contains natural gas swaps which fluctuate in value as the underlying natural gas futures fair value changes, and as market interest rates change. Cleco records the natural gas swaps at the net present value.  The second class consists of natural gas options.  The fair value of natural gas options fluctuates with the volatility in the fair value of natural gas, the number of days until the options expire, the underlying natural gas futures price fluctuations, and market interest rates.  Cleco records natural gas options at the net present value.  Both of these energy market derivative classes also contain counterparty execution risk because the transactions are entered into with a direct counterparty and are not traded through an exchange.

The Level 2 institutional money market funds asset consists of a single class.  In order to capture interest income and minimize risk, cash is invested in money market funds that invest primarily in short-term securities issued by the U.S. Treasury in order to maintain liquidity and achieve the goal of a net asset value of a dollar.  The risks associated with this class are counterparty risk of the fund manager and risk of price volatility associated with the underlying securities of the fund.

The Level 2 treasury rate lock liability consisted of a single class that only contains one instrument.  The risks are changes in the reference treasury yield rate and counterparty risk.  This instrument is with a direct counterparty and not traded through an exchange.

Cleco has a policy which states that transfers between Levels 1, 2, and 3 are recognized at the end of a reporting period.  During the nine months ended September 30, 2011, and the year ended December 31, 2010, Cleco did not experience any transfers between levels.

Derivatives and Hedging

The authoritative guidance on derivatives and hedging requires entities to provide transparent disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance, and cash flows.  Cleco is required to provide qualitative disclosures about derivative fair value, gains and losses, and credit-risk-related contingent features in derivative agreements.  

The following table presents the fair values of derivative instruments and their respective line items as recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as of September 30, 2011, and December 31, 2010:

	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
	LIABILITY DERIVATIVES
(THOUSANDS) FAIR VALUE	BALANCE SHEET LINE ITEM	AT SEPTEMBER 30, 2011			DECEMBER 31, 2010
Commodity contracts
Fuel cost hedges:
Current	Energy risk management liability, net	$	(5,685	)	$	(13,497	)
Long-term	Other deferred credits		-			(1,651	)
Total		$	(5,685	)	$	(15,148	)

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CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

The following table presents the effect of derivatives not designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

		FOR THE THREE MONTHS ENDED							FOR THE NINE MONTHS ENDED
		SEPTEMBER 30, 2011			SEPTEMBER 30, 2010				SEPTEMBER 30, 2011			SEPTEMBER 30, 2010
(THOUSANDS)	GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES
Commodity contracts
Economic hedges	Other operations revenue	$	-		$	(157	) (1)	Other operations revenue	$	-		$	(648	) (2)
Fuel cost hedges(3)	Fuel used for electric generation		(5,678	)		(10,182	)	Fuel used for electric generation		(14,675	)		(32,397	)
Total		$	(5,678	)	$	(10,339	)		$	(14,675	)	$	(33,045	)
(1)For the three months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(2)For the nine months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(3)In accordance with the authoritative guidance for regulated operations, an additional $5.7 million of unrealized losses and $1.3 million of deferred losses associated with fuel cost hedges are reported in Accumulated Deferred Fuel on the balance sheet as of September 30, 2011, compared to $15.1 million of unrealized losses and $1.6 million of deferred losses associated with fuel cost hedges as of December 31, 2010. As gains and losses are realized in future periods, they will be recorded as Fuel Used for Electric Generation on the Income Statement.

At September 30, 2011, Cleco Power had 3.3 million MMBtus hedged for natural gas fuel costs, which is approximately 4% of the estimated natural gas requirements for a two-year period.  At December 31, 2010, Cleco Power had 9.4 million MMBtus hedged or approximately 11% of gas requirements for a two-year period.  

The following table presents the effect of derivatives designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(376	)	$	(194	)*
Treasury rate locks	$	(29,962	)	$	89	*	$	-		$	41	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

	FOR THE NINE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(717	)	$	(592	)*
Treasury rate locks	$	(29,962	)	$	267	*	$	-		$	125	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

At September 30, 2011, Cleco Power expected $0.5 million of the effective portion of treasury rate locks cash flow hedges to be reclassed from accumulated OCI to an increase in interest charges over the next 12 months.  

Note 5 — Debt

Short-term Debt

At September 30, 2011, Cleco had no short-term debt outstanding compared to $150.0 million outstanding at December 31, 2010. The short-term debt outstanding at December 31, 2010, was a bank term loan Cleco Corporation entered into in February 2010.  The bank term loan had an interest rate of LIBOR plus 2.75% and was set to mature in February 2011.  In January 2011, Cleco extended the bank term loan to mature August 19, 2011 and lowered the interest rate to LIBOR plus 2.50% or ABR plus 1.50%.  On April 29, 2011, Cleco repaid the $150.0 million bank term loan.  As part of the repayment, Cleco paid $0.6 million for accrued interest on the term loan.

Cleco Power had no short-term debt outstanding at September 30, 2011, or December 31, 2010.

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CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Long-term Debt

At September 30, 2011, Cleco’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.41 billion outstanding at December 31, 2010, of which $12.3 million was due within one year.  The long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco, long-term debt decreased $28.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011 and a $15.0 million decrease in credit facility draws outstanding.  

At September 30, 2011, Cleco Power’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.40 billion outstanding at December 31, 2010, of which $12.3 million was due within one year.  The long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco Power, long-term debt decreased $13.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011.  

The $32.0 million solid waste disposal facility bonds due in 2038, which were issued by the Rapides Finance Authority for the benefit of Cleco Power in October 2008, were required to be mandatorily tendered by the bondholders for purchase on October 1, 2011, pursuant to the terms of the indenture. On October 3, 2011, Cleco Power purchased all $32.0 million outstanding bonds at face value plus $1.0 million of accrued interest.  In connection with the purchase, the interest rate of the bonds was converted to a weekly mode and will reset each week based on the SIFMA (Securities Industry and Financial Markets Association) index. The initial interest rate of the bonds at October 3, 2011, was 0.16% per annum. The bonds were issued by the Rapides Finance Authority in connection with a loan agreement between the Rapides Finance Authority and Cleco Power.  The bonds remain outstanding and Cleco Power will report the bonds as a $32.0 million long-term liability and a corresponding $32.0 million long-term asset.  Interest expense will continue to be recorded with a corresponding amount recorded as interest income, excluding amortization of debt issuance costs. Cleco Power has the option to remarket the bonds for new terms and new interest rates, both to be determined by market conditions.

Credit Facilities

On October 7, 2011, Cleco Corporation amended its credit facility agreement.  Under the amended agreement, Cleco Corporation’s maximum capacity was increased from $200.0 million to $250.0 million, the maturity date was extended to October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.50%, plus facility fees of 0.25%.  At September 30, 2011, Cleco Corporation had no borrowings outstanding under its existing credit facility.

On October 7, 2011, Cleco Power amended its credit facility agreement.  Under the amended agreement, the maturity date was extended to October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.275%, plus facility fees of 0.225% and the borrowing capacity remained $300.0 million.  At September 30, 2011, Cleco Power had no borrowings outstanding under its existing credit facility.

Note 6 — Pension Plan and Employee Benefits

Pension Plan and Other Benefits Plan

Most employees hired before August 1, 2007 are covered by a non-contributory, defined benefit pension plan.  Benefits under the plan reflect an employee’s years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last 10 years of employment with Cleco Corporation.  Cleco Corporation’s policy is to base its contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the IRS’s full funding limitation.  During January 2011, Cleco made $60.0 million in discretionary contributions to the pension plan, with $40.1 million designated for the 2010 plan year and the remaining $19.9 million designated for the 2011 plan year.  Cleco Power expects to be required to make approximately $15.2 million in additional contributions to the pension plan over the next five years, none of which it expects will be required for the remainder of the 2011 or the 2012 plan year.  The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years.  The ultimate amount and timing of the contributions may be affected by changes in the discount rate, changes in the funding regulations, and actual returns on fund assets.  Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.  

Cleco Corporation’s retirees and their dependents are eligible to receive medical, dental, vision, and life insurance benefits (other benefits).  Cleco Corporation recognizes the expected cost of these other benefits during the periods in which the benefits are earned.

The components of net periodic pension and other benefit cost for the three and nine months ended September 30, 2011, and 2010, are as follows:

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	2,097		$	1,863		$	390		$	383
Interest cost		4,407			4,286			443			499
Expected return on plan assets		(6,161	)		(5,057	)		-			-
Amortizations:
Transition obligation		-			-			5			5
Prior period service cost		(18	)		(18	)		(51	)		(505	)
Net loss		1,389			789			246			250
Net periodic benefit cost	$	1,714		$	1,863		$	1,033		$	632

32

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	6,292		$	5,588		$	1,149		$	1,149
Interest cost		13,222			12,859			1,364			1,498
Expected return on plan assets		(18,484	)		(15,171	)		-			-
Amortizations:
Transition obligation		-			-			15			15
Prior period service cost		(54	)		(54	)		(154	)		(1,516	)
Net loss		4,167			2,367			758			751
Net periodic benefit cost	$	5,143		$	5,589		$	3,132		$	1,897

Since Cleco Power is the pension plan sponsor and the related trust holds the assets, the net unfunded status of the pension plan is reflected at Cleco Power.  The liability of Cleco Corporation’s other subsidiaries is transferred, with a like amount of assets, to Cleco Power monthly.  The expense of the pension plan related to Cleco Corporation’s other subsidiaries for the three and nine months ended September 30, 2011, was $0.5 million and $1.6 million, respectively, compared to $0.5 million and $1.4 million for the same periods in 2010.

Cleco Corporation is the plan sponsor for the other benefit plans.  There are no assets set aside in a trust, and the liabilities are reported on the individual subsidiaries’ financial statements.  At both September 30, 2011, and December 31, 2010, the current portion of the other benefits liability for Cleco was $3.0 million.  At both September 30, 2011, and December 31, 2010, the current portion of the other benefits liability for Cleco Power was $2.8 million.  The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, was $0.9 million and $2.7 million, respectively, compared to $0.5 million and $1.6 million for the same periods in 2010.  

In March 2010, the President signed the PPACA, a comprehensive health care law.  While the provisions of the PPACA are not effective immediately, the provisions could increase the Registrants’ retiree medical unfunded liability and related expenses before the effective date.  Management will continue to monitor this law and its possible impact on the Registrants.  

SERP

Certain Cleco executive officers are covered by the SERP.  The SERP is a non-qualified, non-contributory, defined benefit pension plan.  Benefits under the plan reflect an employee’s years of service, age at retirement, and the sum of the highest base salary paid out of the last five calendar years and the average of the three highest bonuses paid during the 60 months prior to retirement, reduced by benefits received from any other defined benefit pension plan, SERP Plan or Cleco contributions under the enhanced 401(k) Plan to the extent such contributions exceed the limits of the 401(k) Plan.  Cleco Corporation does not fund the SERP liability, but instead pays for current benefits out of the general funds available.  Cleco Power has formed a Rabbi Trust designated as the beneficiary for life insurance policies issued on the SERP participants.  Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ life insurance benefits, as well as future SERP payments.  However, since SERP is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency.  All SERP benefits are paid out of the general cash available of the respective companies from which the officer retired.  No contributions to the SERP were made during the nine months ended September 30, 2011, or 2010.  Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
Components of periodic benefit costs:
Service cost	$	392	$	453	$	1,175	$	1,148
Interest cost		526		541		1,578		1,591
Amortizations:
Prior period service cost		13		13		40		40
Net loss		235		253		705		695
Net periodic benefit cost	$	1,166	$	1,260	$	3,498	$	3,474

The SERP liabilities are reported on the individual subsidiaries’ financial statements.  At September 30, 2011, and December 31, 2010, the current portion of the SERP liability for Cleco was $1.8 million and $2.0 million, respectively.  At September 30, 2011, and December 31, 2010, the current portion of the SERP liability for Cleco Power was $0.7 million and $0.6 million, respectively.  The expense related to the SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income was $0.3 million and $0.9 million for the three and nine months ended September 30, 2011, respectively, compared to $0.4 million and $0.9 million for the same periods in 2010.  

401(k) Plan

Most employees are eligible to participate in the 401(k) Plan.  Under the 401(k) Plan, Cleco Corporation makes matching contributions and funds dividend reinvestments with cash.  Cleco’s 401(k) Plan expense for the three and nine months ended September 30, 2011, and 2010 is as follows:

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
401(k) Plan expense	$	945	$	925	$	2,998	$	2,784

Cleco Power is the plan sponsor for the 401(k) Plan.  The expense of the 401(k) Plan related to Cleco Corporation’s other subsidiaries for the three and nine months ended September 30, 2011, was $0.2 million and $0.7 million, respectively, compared to $0.2 million and $0.6 million for the same periods in 2010.  

33

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Note 7 — Income Taxes

The following table summarizes the effective income tax rates for Cleco Corporation and Cleco Power for the three- and nine-month periods ended September 30, 2011, and 2010.

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30,		FOR THE NINE MONTHS ENDED SEPTEMBER 30,
	2011	2010	2011	2010
Cleco Corporation	27.3%	37.8%	30.8%	35.2%
Cleco Power	37.0%	33.7%	34.1%	32.1%

Effective Tax Rates

For the three months ended September 30, 2011, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, and state tax expense.

For the nine months ended September 30, 2011, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, a reversal of the valuation allowance on the deferred tax asset for a capital loss carryforward due to capital gains generated in 2011, and state tax expense.

For the three months ended September 30, 2010, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, and state tax expense.

For the nine months ended September 30, 2010, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, a valuation allowance on the deferred tax asset for a capital loss carryforward, an adjustment for Medicare Part D from health care legislation enacted in the first quarter of 2010, an adjustment for the implementation of new retail rates, and state tax expense.

Valuation Allowance

During 2010, a $1.2 million valuation allowance against the $2.7 million deferred tax asset on capital loss carryforwards was reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  This $1.2 million valuation allowance was reversed in the second quarter of 2011 due to capital gains generated in 2011 by the disposition of Acadia Unit 2.

Net Operating Losses

As of September 30, 2011, Cleco generated federal net operating losses and state net operating losses of $51.7 million and $45.2 million, respectively, which will begin to expire in 2031 and 2026.  Cleco Power generated federal net operating losses and state net operating losses of $48.2 million and $41.4 million, respectively, which will begin to expire in 2031 and 2026.  Cleco and Cleco Power consider it more likely than not that these losses will be utilized to reduce future income taxes.  Cleco and Cleco Power expect to utilize the entire net operating loss carryforward in 2012.

Uncertain Tax Positions

Effective January 1, 2007, Cleco adopted the provisions of the authoritative guidance on accounting for uncertain tax positions.  With this adoption, Cleco classified all interest related to uncertain tax positions as a component of interest payable and interest expense.  The total amounts of uncertain tax positions and related interest payable and interest expense, as reflected on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets and Statements of Income, are shown in the following tables:

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Interest payable
Cleco Corporation	$	43,972	$	41,018
Cleco Power	$	16,567	$	15,211

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011		2010
Interest charges
Cleco Corporation	$	93		$	2,518		$	2,954	$	6,504
Cleco Power	$	(420	)	$	(5,091	)	$	1,356	$	(2,613	)

The total liability for unrecognized tax benefits for Cleco Corporation and Cleco Power at September 30, 2011, and December 31, 2010, are shown in the following tables:

Cleco

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	102,785
Reduction for tax positions of current period		(3,116	)
Additions for tax positions of prior periods		10,585
Reduction for tax positions of prior periods		(9,546	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	100,708

Cleco Power

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	60,975
Reduction for tax positions of current period		(3,032	)
Additions for tax positions of prior periods		3,634
Reduction for tax positions of prior periods		(8,670	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	52,907

The federal income tax years that remain subject to examination by the IRS are 2001 through 2010.  The Louisiana state income tax years that remain subject to examination by the Louisiana Department of Revenue are 2001 through 2010.  In December 2010, Cleco deposited $52.2 million with the IRS associated with the years currently under audit, of which $45.9 million reduced accrued income taxes payable and $6.3 million reduced accrued interest payable.  In February 2011, Cleco deposited an additional $8.2 million with the IRS

34

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

associated with the years currently under audit, which reduced income taxes payable.

Cleco is currently under audit by the IRS which has proposed adjustments to taxes for various issues, including but not limited to, depreciable tax lives, bonus depreciation, deductible storm costs, research and experimentation costs, domestic production activities deduction, and repair allowance deductions.  Cleco expects that the balance of unrecognized tax benefits as of September 30, 2011, will decrease by a maximum of $42.7 million for Cleco and $2.6 million for Cleco Power in the next 12 months as a result of reaching a settlement with the IRS.  This settlement will result in the payment of additional taxes, the adjustment of deferred taxes, and the recognition of tax benefits which will affect Cleco’s effective tax rate.

On October 13, 2011, Cleco settled the 2001 through 2003 audit cycle with the IRS.  For additional information on the settlement, see Note 16 — “Subsequent Event.”

Note 8 — Disclosures about Segments

Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by first-tier subsidiary.  Cleco’s reportable segments are Cleco Power and Midstream.  The reconciling items in the following tables consist of the holding company, a shared services subsidiary, two transmission interconnection facilities, and an investment subsidiary.  

Each reportable segment engages in business activities from which it earns revenue and incurs expenses.  Segment managers report periodically to Cleco’s Chief Executive Officer (the chief operating decision-maker) with discrete financial information and, at least quarterly, present discrete financial information to Cleco Corporation’s Board of Directors.  Each reportable segment prepared budgets for 2011 that were presented to and approved by Cleco Corporation’s Board of Directors.  

The financial results of Cleco’s segments are presented on an accrual basis.  Management evaluates the performance of its segments and allocates resources to them based on segment profit and the requirements to implement new strategic initiatives and projects to meet current business objectives.  Material intercompany transactions occur on a regular basis.  These intercompany transactions relate primarily to joint and common administrative support services provided by Support Group.

35

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

SEGMENT INFORMATION FOR THE THREE MONTHS ENDED SEPTEMBER 30,

	CLECO				RECONCILING
2011 (THOUSANDS)	POWER		MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	324,532	$	-	$	-		$	-		$	324,532
Tolling operations		-		9,133		-			-			9,133
Other operations		15,565		1		500			(2	)		16,064
Electric customer credits		1,852		-		-			-			1,852
Affiliate revenue		347		-		13,448			(13,795	)		-
Operating revenue	$	342,296	$	9,134	$	13,948		$	(13,797	)	$	351,581
Depreciation	$	28,859	$	1,457	$	241		$	-		$	30,557
Interest charges	$	25,306	$	752	$	(308	)	$	29		$	25,779
Interest income	$	276	$	5	$	199		$	29		$	509
Equity loss from investees, before tax	$	-	$	-	$	(1	)	$	-		$	(1	)
Federal and state income tax expense (benefit)	$	31,656	$	444	$	(7,363	)	$	-		$	24,737
Segment profit	$	53,833	$	5,946	$	6,063		$	-		$	65,842
Additions to long-lived assets	$	76,213	$	4,074	$	81		$	-		$	80,368
Equity investment in investees	$	13,073	$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385	$	234,537	$	200,854		$	(138,235	)	$	4,071,541

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	325,629		$	-	$	-		$	-		$	325,629
Tolling operations		-			11,153		-			-			11,153
Other operations		12,819			1		488			(3	)		13,305
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		343			5		11,290			(11,519	)	$	119
Operating revenue	$	332,477		$	11,159	$	11,778		$	(11,522	)	$	343,892
Depreciation	$	27,133		$	1,446	$	268		$	-		$	28,847
Interest charges	$	16,044		$	1,109	$	7,949		$	(34	)	$	25,068
Interest income	$	117		$	-	$	44		$	(33	)	$	128
Equity income from investees, before tax	$	-		$	2,494	$	-		$	-		$	2,494
Federal and state income tax expense (benefit)	$	26,568		$	2,758	$	830		$	(1	)	$	30,155
Segment profit (loss) (1)	$	52,335		$	5,156	$	(7,879	)	$	-		$	49,612
Additions to long-lived assets	$	35,308		$	454	$	441		$	-		$	36,203
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	49,612
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									12
	Net income applicable to common stock								$	49,600

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SEGMENT INFORMATION FOR THE NINE MONTHS ENDED SEPTEMBER 30,

	CLECO					RECONCILING
2011 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	823,484		$	-	$	-		$	-		$	823,484
Tolling operations		-			16,137		-			-			16,137
Other operations		40,261			8		1,511			(5	)		41,775
Electric customer credits		(3,405	)		-		-			-			(3,405	)
Affiliate revenue		1,041			45		37,544			(38,428	)		202
Operating revenue	$	861,381		$	16,190	$	39,055		$	(38,433	)	$	878,193
Depreciation	$	84,543		$	4,370	$	728		$	-		$	89,641
Interest charges	$	74,029		$	1,963	$	1,891		$	128		$	78,011
Interest income	$	557		$	6	$	103		$	128		$	794
Equity income (loss) from investees, before tax	$	-		$	62,053	$	(2	)	$	-		$	62,051
Federal and state income tax expense (benefit)	$	61,935		$	21,296	$	(9,781	)	$	1		$	73,451
Segment profit (1)	$	119,557		$	39,274	$	6,374		$	-		$	165,205
Additions to long-lived assets	$	152,082		$	5,202	$	749		$	-		$	158,033
Equity investment in investees	$	13,073		$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385		$	234,537	$	200,854		$	(138,235	)	$	4,071,541
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	165,205
	Unallocated items:
	Preferred dividends requirements, net of tax									26
	Preferred stock redemption costs, net of tax									112
	Net income applicable to common stock								$	165,067

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	839,528		$	-	$	-		$	-		$	839,528
Tolling operations		-			23,016		-			-			23,016
Other operations		32,959			2		1,470			(6	)		34,425
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		1,029			924		34,783			(35,310	)		1,426
Operating revenue	$	867,202		$	23,942	$	36,253		$	(35,316	)	$	892,081
Depreciation	$	77,941		$	4,334	$	624		$	-		$	82,899
Interest charges	$	57,104		$	5,972	$	9,575		$	(631	)	$	72,020
Interest income	$	351		$	-	$	649		$	(631	)	$	369
Equity income from investees, before tax	$	-		$	39,211	$	1		$	-		$	39,212
Gain on toll settlement	$	-		$	148,402	$	-		$	-		$	148,402
Federal and state income tax expense (benefit)	$	58,299		$	72,905	$	(3,793	)	$	-		$	127,411
Segment profit (loss) (1)	$	123,584		$	117,176	$	(5,992	)	$	-		$	234,768
Additions to long-lived assets	$	397,301		$	1,576	$	1,181		$	-		$	400,058
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	234,768
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									35
	Net income applicable to common stock								$	234,733

Note 9 — Electric Customer Credits

Beginning in 2010, the amount of Cleco Power’s yearly retail earnings is subject to the terms of a FRP established by the LPSC.  The new rates and the FRP became effective upon commencement of commercial operations at Madison Unit 3 on February 12, 2010.  The 2010 FRP establishes a target return on equity and requires all or a portion of regulated earnings for each yearly review period above the targeted regulatory rate of return on equity to be credited to Cleco Power’s customers. The 2010 FRP allows Cleco Power the opportunity to earn a target return on equity of 10.7%, including returning to retail customers 60% of retail earnings between 11.3% and 12.3% and all retail earnings over 12.3%. The amount of credits due customers, if any, is determined by Cleco Power and the LPSC annually. The 2010 FRP established that Cleco Power file monitoring reports for both the 12 months ended June 30, 2010, and September 30, 2010, on or before October 31, 2010, and January 31, 2011, respectively. Beginning in 2011, Cleco Power will file annual monitoring reports no later than October 31 for the 12-month period ending June 30.

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On October 29, 2010, Cleco Power filed its report for the 12 months ended June 30, 2010, which indicated that no refund was due for this period.  On January 28, 2011, Cleco Power filed its report for the 12 months ended September 30, 2010, which indicated that $9.0 million was due to be returned to customers.  On June 23, 2011, the LPSC Staff completed its review of this report and determined that the results presented by Cleco Power in the September 30, 2010 filing were consistent with the terms of the 2010 FRP and that no changes were necessary.  Cleco Power issued refunds for this filing on customers’ bills in the third quarter of 2011.  On October 31, 2011, Cleco Power filed its report for the 12 months ended June 30, 2011, which indicated that $3.8 million was due to be returned to customers.  The ultimate amount of any customer refund is subject to LPSC approval.

The accrual for estimated electric customer credits reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at September 30, 2011, and December 31, 2010, was $3.9 million and $9.6 million, respectively.

Note 10 — Variable Interest Entities

Cleco reports its investments in VIEs in accordance with the authoritative guidance.  Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.

Prior to April 30, 2011, Cleco Corporation also reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.

Consolidated VIEs

Acadia

In February 2009, Cleco Power announced that it had chosen the acquisition of Acadia Unit 1 as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010.  Beginning in January 2010, Acadia operated the plant and served Cleco Power under a short-term tolling agreement covering Acadia Unit 1.  In February 2010, Cleco Power acquired Acadia Unit 1 and half of Acadia Power Station’s related common facilities and the tolling agreement was terminated.  In conjunction with this transaction, Acadia became 100% owned by Cajun, which prior to April 29, 2011, was 50% owned by APH and 50% owned by third parties.  For additional information regarding the Acadia Unit 1 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 1.”

In October 2009, Acadia and Entergy Louisiana announced that definitive agreements had been executed whereby Entergy Louisiana would acquire Acadia Unit 2.  On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 to Entergy Louisiana for $298.8 million.  Following the disposition, Acadia no longer owns any materials and supply inventory, property, plant and equipment, or land.  Acadia has minimal ongoing operations relating only to settling accounts receivable and accounts payable resulting from operations prior to the closing of the transaction and servicing indemnifications which Cleco assumed in the transaction.  In conjunction with the transaction, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Cleco Power continues to operate both units at the Acadia Power Station.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

The following tables contain summarized financial information for Cajun prior to the disposition of Acadia Unit 2.

(THOUSANDS)	AT DECEMBER 31, 2010
Current assets	$	7,133
Property, plant and equipment, net		203,793
Total assets	$	210,926
Current liabilities	$	1,950
Other liabilities		9,429
Partners’ capital		199,547
Total liabilities and partners’ capital	$	210,926

(THOUSANDS)	FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
Operating revenue		$	31,883
Operating expenses			30,566
Other income			3,671
Income before taxes		$	4,988

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)		2011	*		2010
Operating revenue	$	5,227		$	46,508
Operating expenses		5,914			54,011
Gain on sale of assets		71,422			82,023
Other income		929			3,902
Income before taxes	$	71,664		$	78,422
* The 2011 income statement includes only activity prior to the April 29, 2011, reconsolidation.

Other liabilities at December 31, 2010, represented an indemnification liability related to the Cleco Power transaction.  For additional information on Acadia’s indemnification liability, see Note 11 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

Prior to the reconsolidation, income tax expenses related to Cajun were recorded on APH’s financial statements.  For the four months ended April 30, 2011, income taxes related to Cajun on APH’s financial statements were $24.0 million.  For the three and nine months ended September 30, 2010, tax expenses recorded on APH’s financial statements were $1.0 million and $14.8 million, respectively.

In connection with the Entergy Louisiana transaction, APH has agreed to indemnify the third-party owners of Cajun and their affiliates against their share of Acadia’s contingent obligations related to the transaction.  For additional information on the Entergy Louisiana indemnification, see Note 11 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

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Equity Method VIEs

Equity investment in investees at September 30, 2011, primarily represented Cleco Power’s $13.1 million investment in Oxbow.  Equity investments which are less than 100% owned by Cleco Innovations LLC represented less than $0.1 million of the total balance.

The following table presents the equity income (loss) from each investment accounted for using the equity method.   

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	-		$	2,494
Subsidiaries less than 100% owned by Cleco Innovations		(1	)		-
Total equity (loss) income	$	(1	)	$	2,494

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	62,053		$	39,211
Subsidiaries less than 100% owned by Cleco Innovations		(2	)		1
Total equity income	$	62,051		$	39,212

As a result of the disposition of Acadia Unit 2, Cleco’s 50% share of income from Cajun included $26.2 million of equity income that represents the 2007 investment impairment charge of $45.9 million, partially offset by $19.7 million of interest capitalized during the construction of Acadia.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

Oxbow

Oxbow is owned 50% by Cleco Power and 50% by SWEPCO and is accounted for as an equity method investment.  Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO.  Cleco’s current assessment of its maximum exposure to loss related to Oxbow at September 30, 2011, consisted of its equity investment of $13.1 million.  The table below presents the components of Cleco Power’s equity investment in Oxbow.

INCEPTION TO DATE (THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Purchase price	$	12,873	$	12,873
Cash contributions		200		200
Total equity investment in investee	$	13,073	$	13,073

The following table compares the carrying amount of Oxbow’s assets and liabilities with Cleco’s maximum exposure to loss related to its investment in Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Oxbow’s net assets/liabilities	$	26,146	$	26,146
Cleco Power’s 50% equity	$	13,073	$	13,073
Cleco’s maximum exposure to loss	$	13,073	$	13,073

The following tables contain summarized financial information for Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Current assets	$	685	$	583
Property, plant and equipment, net		23,422		23,597
Other assets		2,148		2,141
Total assets	$	26,255	$	26,321
Current liabilities	$	36	$	175
Other liabilities		73		-
Partners’ capital		26,146		26,146
Total liabilities and partners’ capital	$	26,255	$	26,321

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	382	$	245
Operating expenses		382		245
Income before taxes	$	-	$	-

	FOR THE NINE MONTHS ENDED SEPTEMBBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	880	$	564
Operating expenses		880		564
Income before taxes	$	-	$	-

Oxbow’s property, plant and equipment, net consists of land and lignite reserves.  The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station.  DHLC mines the lignite reserves at Oxbow through the Amended Lignite Mining Agreement.

Oxbow has no third-party agreements, guarantees, or other third-party commitments that contain obligations affecting Cleco Power’s investment in Oxbow.

Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

Devil’s Swamp

In October 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study (RI/FS) from the EPA.  The special notice requested that Cleco Corporation and Cleco Power, along with many other listed PRPs, enter into negotiations with the EPA for the performance of an RI/FS at an area known as the Devil’s Swamp Lake site just northwest of Baton Rouge, Louisiana.  The EPA has identified Cleco as one of many companies sending PCB wastes for disposal to the site.  The Devil’s Swamp Lake site has been proposed to be added to the National Priorities List (NPL) based on the release of PCBs to fisheries and wetlands located on the site.  The EPA has yet to make a final determination on whether to add Devil’s Swamp Lake site to the NPL.  The PRPs began discussing a potential proposal to the EPA in February 2008.  Negotiations among the PRPs and the EPA are ongoing in regard to the RI/FS for the Devil’s Swamp Lake site, with little progress having been made since February 2008.  Since this investigation is in the preliminary stages, management is unable to determine whether the costs associated with possible remediation of the facility site, if any, will have a material

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adverse effect on the Registrants’ financial condition, results of operations, or cash flows.

Discrimination Complaints

On December 11, 2009, a complaint was filed in the U.S. District Court for the Western District of Louisiana (the Court) on behalf of eight current employees and four former employees alleging that Cleco discriminated against each of them on the basis of race.  Each is seeking various remedies provided under applicable statutes prohibiting racial discrimination in the workplace, and together, the plaintiffs seek monetary compensation exceeding $35.0 million.  On July 29, 2010, the plaintiffs moved to add an additional current employee alleging that Cleco had discriminated on the basis of race.  The plaintiff seeks compensation of no less than $2.5 million and became the thirteenth plaintiff.  On April 13, 2011, Cleco entered into a settlement with one of the current employees which resulted in a dismissal of one of the thirteen cases with prejudice.  On September 22, 2011 the Court ruled on Cleco’s summary judgment motions that had been pending for the last year.  The judge granted and denied the motions in part, with the end result that eleven out of twelve of the remaining plaintiffs have at least one claim remaining.  The Court has severed the cases of the eleven remaining plaintiffs for further discovery and proceedings, and if necessary, trial.  None of these matters have been set for trial.  In view of the uncertainty of the claims, management is not able to predict or give a reasonable estimate of the possible range, if any, of these claims.

On September 23, 2010, the New Orleans Field Office of the U.S. Equal Employment Opportunity Commission (EEOC) issued its determination that there is reason to believe that violations of Title VII of the Civil Rights Act of 1964 had occurred at one of Cleco’s training facilities on October 5, 2007.  In its initial determination, the EEOC suggested that Cleco pay the charging party $0.1 million in satisfaction of any compensatory or punitive damages.  Under EEOC procedures, Cleco pursued conciliation efforts to resolve the charge which resulted in a complete settlement with the charging party and the EEOC.  

City of Opelousas

On March 9, 2010, a complaint was filed in the 27th Judicial District Court of St. Landry Parish, State of Louisiana, on behalf of three Cleco Power customers in Opelousas, Louisiana.  The complaint alleges that Cleco Power overcharged the plaintiffs by applying to customers in Opelousas the same retail rates as Cleco Power applies to all of its retail customers.  The plaintiffs allege that Cleco Power should have established, solely for customers in Opelousas, retail rates that are separate and distinct from the retail rates that apply to other customers of Cleco Power and that Cleco Power should not collect from customers in Opelousas the storm surcharge approved by the LPSC following Hurricanes Katrina and Rita.  Cleco Power currently operates in Opelousas pursuant to a franchise granted to Cleco Power by the City of Opelousas in 1986 and an operating and franchise agreement dated May 14, 1991, pursuant to which Cleco Power operates its own electric facilities and leases and operates electric facilities owned by the City of Opelousas.  In April 2010, Cleco Power filed a petition with the LPSC appealing to its expertise in declaring that the ratepayers of Opelousas have been properly charged the rates that are applicable to Cleco Power’s retail customers and that no overcharges have been collected.  In addition, Cleco Power removed the purported class action lawsuit filed on behalf of Opelousas electric customers from the state court to the U.S. District Court for the Western District of Louisiana in April 2010, so that it could be properly addressed under the terms of the Class Action Fairness Act.  On May 11, 2010, a second class action lawsuit was filed in the 27th Judicial District Court of St. Landry Parish, State of Louisiana, repeating the allegations of the first complaint, which was submitted on behalf of 249 Opelousas residents.  Cleco Power has responded in the same manner as with the first class action lawsuit.  On September 29, 2010, the federal court remanded both cases to the state court in which they were originally filed for further proceedings.  On January 21, 2011, the presiding judge in the state court proceeding ruled that the jurisdiction to hear the two class actions resides in the state court and not with the LPSC as argued by both Cleco and the LPSC Staff.  Both Cleco and the LPSC Staff appealed this ruling to the Third Circuit Court of Appeals for the State of Louisiana (Third Circuit).  On September 9, 2011, the Third Circuit denied both appeals.  On October 10, 2011, both Cleco and the LPSC appealed the Third Circuit’s ruling to the Louisiana Supreme Court.  On February 7, 2011, the administrative law judge in the LPSC proceeding ruled that the LPSC has jurisdiction to decide the claims raised by the class action plaintiffs.  The customers have not stated an amount of overcharges they seek to recover.  In view of the uncertainty of the claims, management is not able to predict or give a reasonable estimate of the possible range, if any, of these claims.

Madison Unit 3

In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Madison Unit 3.  Construction of Madison Unit 3 began in May 2006.  In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract, which contract has subsequently been amended by the parties.  The project achieved commercial operations on February 12, 2010, whereby Cleco Power accepted care, custody, and control of the unit.  Cleco Power and Shaw submitted various claims, relating to the Amended EPC Contract, to arbitration.  On April 30, 2010, Shaw filed a demand for arbitration asserting claims of $32.0 million including impacts due to the 2008 hurricane force majeure, alleged excess fuel moisture, intake water quality and a river embankment slope failure, and the associated recovery of schedule related liquidated damages withheld by Cleco Power.  In May 2010, Cleco Power issued to Shaw a notice of default relating to Shaw’s inability to meet certain material obligations under the Amended EPC Contract.  Furthermore, as a result of Shaw filing the demand for arbitration, certain claims exceeded a $1.0 million threshold, triggering an unwind of certain fuel-related matters included in a prior settlement between the parties, Amendment No. 4, and

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Cleco demanded an associated payment of $19.0 million.  In February 2011, Cleco drew on the Shaw letter of credit in an amount of $19.0 million for amounts relating to the unwind.  Certain of these matters were argued in arbitration hearings which concluded on June 8, 2011.  On June 24, 2011, Cleco and Shaw each submitted their proposed resolutions to all of the matters in dispute in this arbitration proceeding.  Shaw submitted that Cleco owed $32.5 million in satisfaction of all of such matters.  Cleco submitted that it owed Shaw $4.0 million.  On August 5, 2011, the arbitrator announced his decision in favor of Shaw’s claims of Cleco Power owing Shaw $32.5 million (including the return of the amounts drawn on Shaw’s letter of credit).  Cleco Power paid this amount on August 22, 2011, which was included as a cost of Madison Unit 3 and reflected as property, plant and equipment.  

Shaw has not reached project completion as defined in the Amended EPC Contract, as various performance tests, the reliability test, and specified boiler performance criteria have not been met.  Under the Amended EPC Contract, Shaw must correct the identified items, complete the performance guarantee tests, meet a 30-day reliability performance test, and correct certain warranty issues to meet final acceptance, or pay certain liquidated damages and financially settle incomplete work.  The disputed items relating to the liquidated damages for Shaw’s inability to meet performance guarantees, as well as for completion of minor or warranty work, were bifurcated from the arbitration proceedings and remain outstanding.  These matters may be resolved through a second arbitration proceeding or potentially settled.

LPSC Fuel Audit

The LPSC is currently auditing Cleco Power’s fuel expenditures for the years 2003 through 2008 which includes approximately $3.2 billion of fuel expenses.  Cleco Power has responded to several sets of data requests and the responses are currently under review.  The LPSC has not stated an amount of the fuel costs, if any, that would be disallowed and result in a refund to Cleco Power’s customers.  As such, management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to this audit.  However, if a disallowance of fuel costs is ordered resulting in a refund, any such refund could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Other

Cleco is involved in various litigation matters, including regulatory, environmental, and administrative proceedings before various courts, regulatory commissions, arbitrators, and governmental agencies regarding matters arising in the ordinary course of business.  The liability Cleco may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued.  Management regularly analyzes current information and, as of September 30, 2011, believes the range of probable and reasonably estimable liabilities based on the eventual disposition of these matters is between $2.0 million and $6.0 million.  

Off-Balance Sheet Commitments

Cleco Corporation and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Corporation’s subsidiaries and equity investees (affiliates).  Cleco Corporation and Cleco Power also have agreed to contractual terms that require them to pay third parties if certain triggering events occur.  These contractual terms generally are defined as guarantees in the authoritative guidance.  

Cleco Corporation entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations.  If Cleco Corporation had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco Corporation’s Condensed Consolidated Balance Sheets because management has determined that Cleco’s affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco will be required.  Cleco’s off-balance sheet commitments as of September 30, 2011, are summarized in the following table, and a discussion of the off-balance sheet commitments follows the table.  The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco’s financial condition.

			AT SEPTEMBER 30, 2011
	FACE				NET
(THOUSANDS)	AMOUNT		REDUCTIONS		AMOUNT
Cleco Corporation
Guarantee issued to Entergy Mississippi on behalf of Attala	$	500	$	-	$	500
Cleco Power
Obligations under standby letter of credit issued to the Louisiana Department of Labor		3,725		-		3,725
Total	$	4,225	$	-	$	4,225

In January 2006, Cleco Corporation provided a $0.5 million guarantee to Entergy Mississippi for Attala’s obligations under the Interconnection Agreement.  This guarantee will be effective through the life of the agreement.

Acadia provided limited guarantees and indemnifications to Cleco Power under the Master Reorganization and Redemption Agreement related to the acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities in February 2010.  In connection with this transaction, Acadia became 100% owned by Cajun.  Prior to April 29, 2011, Cleco Corporation reported the investment in Cajun on the equity method of accounting and therefore APH’s 50% portion of the indemnity was off-balance sheet.  On April 29, 2011, in

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conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.

Acadia and Entergy Services entered into an amended capacity sale and fuel conversion services agreement on June 30, 2010, with an effective date of October 1, 2010.  In conjunction with the agreement, Cleco Corporation provided to Entergy Louisiana a limited guarantee, in an amount not to exceed $10.0 million, for certain performance obligations by Acadia under the agreement.  On April 29, 2011, the agreement and the related guarantee terminated as a result of the Acadia Unit 2 transaction.  For additional information regarding this transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

The State of Louisiana allows employers of certain financial net worth to self-insure their workers’ compensation benefits.  Cleco Power has a certificate of self-insurance from the Louisiana Office of Workers’ Compensation and is required to post a $3.7 million letter of credit, an amount equal to 110% of the average losses over the previous three years, as surety.

Disclosures about Guarantees

Cleco Corporation provided a limited guarantee and an indemnification to Entergy Louisiana and Entergy Gulf States for Perryville’s performance, indemnity, representation, and warranty obligations under the Sale Agreement, the Power Purchase Agreement, and other ancillary agreements related to the sale of the Perryville facility in 2004.  This is a continuing guarantee and all obligations of Cleco Corporation shall continue until the guaranteed obligations have been fully performed or otherwise extinguished.  The discounted probability-weighted liability under the guarantees and indemnifications recognized on Cleco Corporation’s Condensed Consolidated Balance Sheets as of September 30, 2011, was $0.2 million.  The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million.  Currently, management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under the guarantee.

In February 2010, Cleco Power acquired Acadia Unit 1 and half of Acadia Power Station’s related common facilities. Acadia provided limited guarantees and indemnifications to Cleco Power under the Master Reorganization and Redemption Agreement.  The maximum amount of the potential payment to Cleco Power for indemnifications is $30.0 million, except for the indemnifications relating to the fundamental organizational structure of Acadia against which there is no maximum amount.  Cleco Corporation is obligated to pay a maximum of $10.0 million if Acadia is unable to pay claims to Cleco Power pursuant to the guarantee.  Acadia recorded an indemnification liability and a corresponding reduction of the gain of $13.5 million which represents the fair value of these indemnifications.  In a related agreement, APH agreed to accept 50% of Acadia’s indemnification liability that would be held by the third parties who indirectly owned 50% of Acadia in return for $6.8 million received from the third parties.  The $6.8 million was recorded as an indemnification liability by APH.  Events that would require payments to Cleco Power pursuant to the indemnity include, but are not limited to:

§   Environmental costs that were caused by events occurring before the closing of the transaction;

§   Claims against Cleco Power for liabilities retained by Acadia;

§   Certain conditions of Acadia Unit 1 that were discovered prior to September 30, 2010; and

§   Breach of fundamental representations of Acadia, such as legal existence, ownership of Acadia Unit 1, and valid authorization to dispose of Acadia Unit 1.

Acadia and APH will reduce the indemnification liabilities either through expiration of the contractual life or through a reduction in the probability of a claim arising.  The indemnification obligation is expected to have a term of approximately three years, which reflects both contractual expiration of the underlying indemnifications and management’s assumptions about the decreasing probability of a payment due to the passage of time.  After the three-year period, a residual value of less than $0.1 million will remain.  At September 30, 2011, Acadia had an indemnification liability of $7.6 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco Corporation’s Condensed Consolidated Balance Sheet.  APH recognized no income for the three months ended September 30, 2011, and $0.5 million for the nine months ended September 30, 2011, primarily due to the contractual expiration of the underlying indemnification.  During the three and nine months ended September 30, 2011, Acadia recognized income of $1.0 million and $1.1 million, respectively, primarily due to the contractual expiration of the underlying indemnification.  

On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  Acadia provided limited guarantees and indemnifications to Entergy Louisiana and recorded an indemnification liability and a corresponding reduction of the gain of $21.8 million, which represents the fair value of these indemnifications.  APH agreed to indemnify the third-party owners of Cajun and their affiliates against 50% of Acadia’s liabilities and other obligations related to the Acadia Unit 2 transaction in exchange for $10.9 million received from the third parties.  The $10.9 million was recorded as an indemnification liability by APH.  In conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Events that would require payments to Entergy Louisiana pursuant to the indemnity include, but are not limited to:

§   Environmental costs that were caused by events occurring before the closing of the transaction;

§   Claims against Entergy Louisiana for liabilities retained by Acadia;

§   Certain conditions of Acadia Unit 2 that were discovered prior to September 30, 2010; and

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§   Breach of fundamental representations of Acadia, such as legal existence, ownership of Acadia Unit 2, and valid authorization to dispose of Acadia Unit 2.

Acadia and APH will reduce the indemnification liabilities either through expiration of the contractual life or through a reduction in the probability of a claim arising.  The indemnification obligation is expected to have a term of three years, which reflects both contractual expiration of the underlying indemnifications and management’s assumptions about the decreasing probability of a payment due to the passage of time.  After the three-year period, a residual value of approximately $0.2 million will remain.  At September 30, 2011, Acadia had an indemnification liability of $21.8 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco Corporation’s Condensed Consolidated Balance Sheet.  The maximum amount of the potential payment to Entergy Louisiana for the indemnifications is the purchase price of $298.8 million, except for the liabilities retained by Acadia, for which there is no maximum amount.  Cleco Corporation is obligated to pay the same maximum amounts as Acadia if Acadia is unable to pay claims to Entergy Louisiana pursuant to the guarantee.  

As part of the Lignite Mining Agreement amended in 2009, Cleco Power and SWEPCO, joint owners of Dolet Hills, have agreed to pay the lignite miner’s loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay.  Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered.  At September 30, 2011, Cleco Power had a liability of $3.8 million related to the amended agreement.  The maximum projected payment by Cleco Power under this guarantee is estimated to be $72.5 million; however, the Amended Lignite Mining Agreement does not contain a cap.  The projection is based on the forecasted loan and lease obligations to be incurred by DHLC, primarily for purchases of equipment.  Cleco Power has the right to dispute the incurrence of loan and lease obligations through the review of the mining plan before the incurrence of such loan and lease obligations.  The Amended Lignite Mining Agreement does not terminate pursuant to its terms until 2026 and does not affect the amount the Registrants can borrow under their credit facilities.  Currently, management does not expect to be required to pay DHLC under the guarantee.

The following table summarizes the expected termination dates of the off-balance sheet commitments and on-balance sheet guarantees discussed above:

							AT SEPTEMBER 30, 2011
			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
	NET								MORE
	AMOUNT		LESS THAN						THAN
(THOUSANDS)	COMMITTED		ONE YEAR		1-3 YEARS		3-5 YEARS		5 YEARS
Off-balance sheet commitments	$	4,225	$	3,725	$	-	$	-	$	500
On-balance sheet guarantees		33,449		-		29,443		-		4,006
Total	$	37,674	$	3,725	$	29,443	$	-	$	4,506

In its bylaws, Cleco Corporation has agreed to indemnify directors, officers, agents, and employees who are made a party to a pending or completed suit, arbitration, investigation, or other proceeding whether civil, criminal, investigative or administrative, if the basis of inclusion arises as the result of acts conducted in the discharge of their official capacity.  Cleco Corporation has purchased various insurance policies to reduce the risks associated with the indemnification.  In its Operating Agreement, Cleco Power provides for the same indemnification as described above with respect to its managers, officers, agents, and employees.

Generally, neither Cleco Corporation nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations.  The one exception is the insurance contracts associated with the indemnification of directors, managers, officers, agents, and employees.  There are no assets held as collateral for third parties that either Cleco Corporation or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.

Other Commitments

Acadia Transactions

In February 2009, Cleco Power announced that it had chosen the acquisition of Acadia Unit 1 as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010.  Beginning in January 2010, Acadia operated the plant and served Cleco Power under a short-term tolling agreement covering Acadia Unit 1.  In February 2010, the transaction closed and the tolling agreement was terminated.  For additional information regarding the Cleco Power transaction, see Note 15 — “Acadia Transactions — Acadia Unit 1.”

In October 2009, Acadia and Entergy Louisiana announced that definitive agreements had been executed whereby Entergy Louisiana would acquire Acadia Unit 2.  A capacity sale and fuel conversion services agreement between Acadia and Entergy Louisiana began in June 2010.  Effective October 1, 2010, this agreement was subject to a $10.0 million guarantee by Cleco Corporation.  For additional information regarding this guarantee, please refer to “— Off-Balance Sheet Commitments” above.  On April 29, 2011, the transaction closed and the agreement terminated.  Cleco Power will continue to operate both units at the Acadia Power Station.  In connection with this transaction and in exchange for reasonable consideration, APH has indemnified the third-

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party owners of Cajun and their affiliates against their 50% of Acadia’s liabilities and other obligations related to the Entergy Louisiana transaction.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

New Markets Tax Credits

In August 2008, Cleco Corporation acquired a 99.9% membership interest in U.S. Bank New Markets Tax Credit Fund 2008-1 LLC (Fund).  The Fund was formed by U.S. Bancorp Community Development Corporation (USBCDC).  The purpose of the Fund is to invest in projects located in qualified active low-income communities that are underserved by typical debt capital markets.  These investments are designed to generate new markets tax credits and historical rehabilitation tax credits.

In July 2011, the operating agreement of the Fund was amended to facilitate investments in Section 1603 grant qualifying renewable energy projects and to adjust the guaranteed performance targets that the Fund is obligated to provide to Cleco.  U.S. Bank guarantees the cash flow and net present value of the Fund.  U.S. Bank is the parent company of the managing member of the Fund.

The tax benefits received from the Fund reduce the federal income tax obligations of Cleco Corporation.  In total, Cleco Corporation will contribute $286.3 million of equity contributions to the Fund and will receive at least $304.6 million of net tax benefits and cash from the inception of the investment in 2008 over the life of the investment, which ends in 2018.  The $18.3 million difference between equity contributions and total benefits received will be recognized over the life of the Fund as net tax benefits are delivered.  The following table reflects remaining future equity contributions.

(THOUSANDS)	CONTRIBUTION
Three months ending December 31, 2011	$	11,508
Years ending December 31,
2012		76,629
2013		36,225
2014		22,927
2015		21,904
Thereafter		20,808
Total	$	190,001

Of the $190.0 million, $69.6 million is due to be paid within the next twelve months.  Due to the right of offset, the investment and associated debt are presented on Cleco Corporation’s Condensed Consolidated Balance Sheet in the line item titled tax credit fund investment, net.  The amount of tax benefits delivered in excess of capital contributions as of September 30, 2011 was $78.0 million.  The amount of tax benefits received but not utilized as of September 30, 2011 was $63.6 million and is reflected as a deferred tax asset.

The equity contribution does not contain a stated rate of interest.  Cleco Corporation has recorded the liability and investment at its calculated fair value within the framework of the authoritative guidance.  In order to calculate the fair value, management used an imputed rate of interest assuming that Cleco Corporation obtained financing of a similar nature from a third-party.  The imputed interest rate was used in a net present value model in order to calculate the fair value of the remaining portion of the delayed equity contributions.  The table below contains the disclosures required by the authoritative guidelines for equity investments with an imputed interest rate.

(THOUSANDS)
Equity contributions, imputed interest rate 6%
Principal payment schedule above:	$	190,001
Less:  unamortized discount		22,098
Total	$	167,903

The gross investment amortization expense will be recognized over a ten-year period, with seven years remaining, using the cost method in accordance with the authoritative guidance for investments.

Risks and Uncertainties

Cleco Corporation

Cleco Corporation could be subject to possible adverse consequences if Cleco’s counterparties fail to perform their obligations or if Cleco Corporation or its affiliates are not in compliance with loan agreements or bond indentures.  

Evangeline 2010 Tolling Agreement

JPMorgan Chase & Co. guarantees JPMVEC’s obligations under the Evangeline 2010 Tolling Agreement.  For additional information regarding this tolling agreement, see Note 14 — “Evangeline Transactions.”

Other

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  After assessing the current operating performance, liquidity, and credit ratings of Cleco, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  If Cleco Corporation’s credit ratings were to be downgraded by Moody’s and Standard & Poor’s, Cleco Corporation would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.

Changes in the regulatory environment or market forces could cause Cleco to determine its assets have suffered an other-than-temporary decline in value, whereby an impairment would be required to be taken and Cleco’s financial condition could be materially adversely affected.

Cleco Power

Cleco Power supplies the majority of its customers’ electric power requirements from its own generation facilities.  In addition to power obtained from power purchase agreements, Cleco Power purchases power from other utilities and marketers to supplement its generation at times of relatively high demand or when the purchase price of power is less than its own cost of generation.  Due to its location on the transmission grid, Cleco Power relies on two main suppliers of electric

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transmission when accessing external power markets.  At times, constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory.

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  After assessing the current operating performance, liquidity, and credit ratings of Cleco Power, management believes that Cleco Power will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  Cleco Power pays fees and interest under its bank credit agreements based on the highest rating held.  If Cleco Power’s credit ratings were to be downgraded by Moody’s and Standard & Poor’s, Cleco Power would be required to pay additional fees and higher interest rates under its bank credit agreements.  Cleco Power’s collateral for derivatives is based on the lowest rating held.  If Cleco Power’s credit ratings were to be downgraded by Moody’s or Standard & Poor’s, Cleco Power would be required to pay additional collateral for derivatives.

In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Madison Unit 3.  In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract.  Under the terms of the Amended EPC Contract until final acceptance of Madison Unit 3, in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million.  In the event of further downgrade to both of its credit ratings to:  (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.

Note 12 — LPSC Fuel Audit

The LPSC Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit of fuel adjustment clause filings will be performed not less than every other year.  Cleco Power’s last fuel audit was for the years 2001 and 2002.  Cleco Power currently has fuel adjustment clause filings for 2003 through 2010 subject to audit.  In March 2009, the LPSC proceeded with the audit of fuel adjustment clause filings for the years 2003 through 2008.  The total amount of fuel expenses included in the audit is approximately $3.2 billion.  Cleco Power has responded to several data requests from the LPSC.  These responses are currently under review by the LPSC.  The LPSC has not stated an amount of the fuel costs, if any, that would be disallowed and result in a refund to the customers.  Management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to this audit.  However, if a disallowance of fuel costs is ordered resulting in a refund, any such refund could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Note 13 — Affiliate Transactions

At September 30, 2011, Cleco Corporation had no affiliate balances that were payable to or due from its non-consolidated affiliates.

Cleco Power has affiliate balances that are payable to or due from its affiliates.  At September 30, 2011, the payable to Support Group was $6.4 million, the payable to Cleco Corporation was $0.9 million, and the payable to other affiliates was less than $0.1 million.  Also, at September 30, 2011, the receivable from Support Group was $2.7 million, the receivable from Midstream was $0.1 million, and the receivable from other affiliates was less than $0.1 million.

Note 14 — Evangeline Transactions

On February 22, 2010, Evangeline and JPMVEC entered into the Evangeline Restructuring Agreement whereby the parties agreed to terminate the existing Evangeline Tolling Agreement and entered into the Evangeline 2010 Tolling Agreement, effective March 1, 2010.  The other significant terms of the Evangeline Restructuring Agreement are:

§   The tolling agreement is a market-based tolling agreement, for Coughlin Units 6 and 7, ending December 31, 2011, with an option for JPMVEC to extend the term through December 31, 2012.  The agreement also gives Evangeline the right to terminate its Coughlin Unit 6 obligations prior to the expiration of the term.  JPMVEC did not exercise the option to extend the tolling agreement;

§   $126.6 million of Evangeline’s 8.82% Senior Secured bonds due 2019, owned by JPMVEC, were transferred to Evangeline and subsequently retired; and $5.3 million of accrued interest associated with the bonds transferred to Evangeline was eliminated;

§   JPMVEC paid Evangeline $56.7 million;

§   JPMVEC returned Cleco Corporation’s $15.0 million letter of credit issued under the Evangeline Tolling Agreement and the letter of credit was cancelled; and

§   Evangeline recorded a gain of $148.4 million.

The termination of the Evangeline Tolling Agreement was considered a termination of an operating lease and a triggering event requiring an asset impairment analysis.  Management made assumptions about expected future cash flows, long-term interest rates, estimates about the probability of the occurrence of future events, and estimates of market values of assets without a readily observable market price.  An impairment charge was not recorded since the undiscounted expected future net cash flows exceeded the carrying value of Evangeline’s property, plant and equipment.  Due to the lack of a long-term agreement, the expected future net cash flows of Evangeline are subject to an increased potential for variability as compared to prior years.  Consequently, future impairment tests could occur more frequently and might result in an impairment charge.

Under the terms of the Evangeline Restructuring Agreement, Evangeline issued an irrevocable redemption notice to redeem the remaining $35.2 million of 8.82% Senior Secured

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bonds outstanding pursuant to their terms on February 25, 2010, and paid the debtholders $1.5 million of accrued interest and a $10.2 million make-whole payment.  As a result of the debt retirement, Evangeline expensed $2.1 million in unamortized debt issuance costs associated with the Evangeline bonds.  The Evangeline bonds were non-recourse to Cleco Corporation and redemption of the bonds was permitted under Cleco Corporation’s revolving credit facility.  Upon the redemption of the bonds, $30.1 million of restricted cash was released to Evangeline.  

The impacts of these transactions are reflected in the Midstream segment, which includes Evangeline.  In accordance with the authoritative guidance, effective January 1, 2010, the financial results for Evangeline are no longer presented as equity income (loss), but presented in the corresponding line items in the consolidated financials of Midstream.

Note 15 — Acadia Transactions

Acadia Unit 1

In February 2010, Cleco Power completed the acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities.  Cleco Power and the parties executed the definitive agreements in 2009, and received LPSC and FERC approvals for the transaction in January 2010 and February 2010, respectively.  The significant terms of the transaction were:

§   Cleco Power acquired Acadia Unit 1 and half of the common facilities for $304.0 million;

§   Cleco Power recognized $78.4 million of deferred taxes on the transaction;  

§   Acadia recognized a gain of $82.0 million;

§   APH received $6.8 million from third-parties in return for APH’s indemnification against the third parties’ 50% share of Acadia’s liabilities and other obligations related to the Cleco Power transaction; and

§   Cleco Power owns and operates Acadia Unit 1.  Prior to April 29, 2011, Cleco Power operated Acadia Unit 2 on behalf of Acadia.  On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 to Entergy Louisiana.  Cleco Power now operates Acadia Unit 2 on behalf of Entergy Louisiana.  

Acadia Unit 2

On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  The significant terms of the transaction were:

§   Entergy Louisiana acquired Acadia Unit 2 for $298.8 million;

§   In exchange for $10.9 million, APH indemnified the third-party owners of Cajun and their affiliates against 50% of Acadia’s liabilities and other obligations related to the Acadia Unit 2 transaction;

§   APH recognized a gain of $62.0 million, which included $26.2 million of equity income that represents the 2007 investment impairment charge of $45.9 million, partially offset by $19.7 million of capitalized interest during the construction of Acadia;

§   APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH; and

§   Cleco Power operates Acadia Unit 2 on behalf of Entergy Louisiana.

Following the transaction, ongoing operations at Acadia are minimal, relating only to the previously established accounts receivable and accounts payable and servicing of indemnities.  Therefore, Acadia does not meet the definition of a business.

Note 16 — Subsequent Event

On October 13, 2011, Cleco settled the 2001 through 2003 audit cycle with the IRS.  As a result of the settlement, Cleco made a miscellaneous other federal income tax payment in accordance with Revenue Procedure 2001-18 in the amount of $13.0 million, and no interest was assessed.  Cleco will reverse $30.9 million of previously accrued federal and state interest expense and the corresponding deferred tax benefit of $11.9 million.  Cleco expects its effective tax rate to increase approximately 4.55% for the year.

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ITEM 2.       MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in combination with the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010, and Cleco Corporation and Cleco Power’s Condensed Consolidated Financial Statements contained in this Combined Quarterly Report on Form 10-Q.  The information included therein is essential to understanding the following discussion and analysis.  Below is information concerning the consolidated results of operations of Cleco for the three and nine months ended September 30, 2011, and September 30, 2010.

RESULTS OF OPERATIONS

Overview

Cleco is a regional energy company that conducts substantially all of its business operations through its two primary subsidiaries:

§   Cleco Power, a regulated electric utility company, which owns 10 generating units with a total nameplate capacity of 2,572 MWs and serves approximately 279,000 customers in Louisiana through its retail business and 10 communities across Louisiana and Mississippi through wholesale power contracts; and

§   Midstream, a wholesale energy business, which owns Evangeline (which operates Coughlin).

Cleco Power

Many factors affect Cleco Power’s primary business of selling electricity.  These factors include the presence of a stable regulatory environment, which can impact cost recovery and return on equity, as well as the recovery of costs related to growing energy demand and rising fuel prices; the ability to increase energy sales while containing costs; and the ability to meet increasingly stringent regulatory and environmental standards.  Key initiatives that Cleco Power is currently working on include the Acadiana Load Pocket project, the AMI project and power supply options for 2012 and beyond.  These initiatives are discussed below.

Acadiana Load Pocket Project

In September 2008, Cleco Power entered into an agreement with two other utilities to upgrade and expand interconnected transmission systems in south central Louisiana in an area known as the Acadiana Load Pocket.  The project received LPSC and SPP approval in February 2009.  Cleco Power’s initial portion of the estimated cost was approximately $150.0 million, including AFUDC.  Due to lower material and labor costs than initially expected, Cleco Power’s estimated costs for its portion of the project were reduced to $125.0 million, including AFUDC.  At September 30, 2011, Cleco Power had spent $86.3 million on the project and expects to incur an additional $9.6 million during 2011, including AFUDC.  A return on and recovery of the costs associated with the completed portions of the Acadiana Load Pocket project are included in base revenue.  The project is estimated to be 81% complete with the final completion date expected in 2012.  For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Acadiana Load Pocket Project” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  For information on the impact the Acadiana Load Pocket project is expected to have on base revenue, see “— Comparison of the Three Months Ended September 30, 2011, and 2010 — Cleco Power — Base.”

AMI Project

In May 2010, Cleco Power accepted the terms of a $20.0 million grant from the DOE under the DOE’s small-grant process to implement smart-grid technology for all of Cleco Power’s retail customers.  Cleco Power estimates the project will cost $73.0 million, with the DOE grant providing $20.0 million toward the project and Cleco Power providing the remaining $53.0 million.  The grant program is a part of the American Recovery and Reinvestment Act of 2009, an economic stimulus package passed by Congress in February 2009.  Smart-grid technology includes the installation of electric meters that enable two-way communication capabilities between a home or business and a utility company.  At September 30, 2011, Cleco Power had incurred $6.9 million in project costs, of which $3.0 million has been submitted to the DOE for reimbursement.  As of September 30, 2011, Cleco Power had received $2.8 million in payments from the DOE.  The project is expected to be completed in the third quarter of 2013.  For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Other Matters — AMI Project” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Power Supply Options

Cleco Power is evaluating a range of power supply options for 2012 and beyond.  Cleco Power is continuing to update its IRP to look at future sources of supply to meet its capacity and energy requirements and to comply with new environmental standards, primarily the Cross-State Air Pollution Rule.  In August 2011, Cleco Power issued one RFP for resources to enhance reliability for January through April 2012.  In October 2011, a second RFP, seeking up to approximately 750 MWs of capacity and energy, for a three- or five-year period was issued for supply starting May 1, 2012 to meet the Cross-State Air Pollution Rule.  Cleco Power also plans to release an additional RFP in 2012 seeking long-term resources.  

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Cleco Midstream

Evangeline

In March 2010, Evangeline restructured its tolling agreement with JPMVEC and shortened the expiration of the prior long-term agreement from 2020 to December 31, 2011 (with a JPMVEC option to extend one year).  JPMVEC did not exercise the option to extend the tolling agreement and as a result, Coughlin’s capacity and energy will be available to Midstream beginning January 1, 2012.  Currently, Midstream is marketing Coughlin’s capacity for periods beginning on or after January 1, 2012, and is evaluating various options to optimize Coughlin’s value.  Evangeline was one of the successful bidders in Cleco Power’s RFP for short-term 2012 resources.  Cleco Power has filed with the LPSC an application for a certificate of public convenience and necessity for this agreement.  For additional information, see “— Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Generation RFP.”

Acadia

In October 2009, Acadia and Entergy Louisiana executed definitive agreements whereby Entergy Louisiana would purchase Acadia Unit 2.  On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 to Entergy Louisiana for $298.8 million.  APH’s portion of the proceeds from the sale were used to repay Cleco Corporation’s $150.0 million bank term loan.  For additional information on the Acadia Unit 2 transaction, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 15 — Acadia Transactions — Acadia Unit 2.”

Comparison of the Three Months Ended September 30, 2011, and 2010

Cleco Consolidated

				FOR THE THREE MONTHS ENDED SEPTEMBER 30,
						FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010		VARIANCE			CHANGE
Operating revenue, net	$	351,581		$	343,892	$	7,689			2.2	%
Operating expenses		235,401			243,905		8,504			3.5	%
Operating income	$	116,180		$	99,987	$	16,193			16.2	%
Equity (loss) income from investees, before tax	$	(1	)	$	2,494	$	(2,495	)		(100.0	)%
Other expense	$	3,360		$	1,416	$	(1,944	)		(137.3	)%
Interest charges	$	25,779		$	25,068	$	(711	)		(2.8	)%
Federal and state income taxes	$	24,737		$	30,155	$	5,418			18.0	%
Net income applicable to common stock	$	65,842		$	49,600	$	16,242			32.7	%
* Not meaningful

Consolidated net income applicable to common stock increased $16.2 million, or 32.7%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to higher corporate earnings. Also contributing to the increase were higher earnings at Midstream and Cleco Power.

Operating revenue, net increased $7.7 million, or 2.2%, in the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of lower electric customer credits and higher other operations revenue at Cleco Power.

Operating expenses decreased $8.5 million, or 3.5%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to lower maintenance expenses at Cleco Power and Evangeline.

Equity income from investees decreased $2.5 million, or 100.0%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to the absence in the third quarter of 2011 of equity earnings at APH resulting from the disposition of Acadia Unit 2 and the subsequent consolidation of Acadia effective April 29, 2011.  

Other expense increased $1.9 million, or 137.3%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to decreases in the cash surrender value of life insurance policies at Cleco Corporation.

Interest charges increased $0.7 million, or 2.8%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to higher interest charges at Cleco Power.  Partially offsetting this increase were lower corporate interest charges related to uncertain tax positions and the repayment of a bank term loan in April 2011.  

Federal and state income taxes decreased $5.4 million, or 18.0%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to $7.8 million for tax benefits taken on the prior year income tax return and $3.0 million to record tax expense at the consolidated projected annual effective tax rate.  These decreases were partially offset by $4.2 million for the change in pre-tax income excluding AFUDC, and $1.2 million for miscellaneous items.

Results of operations for Cleco Power and Midstream are more fully described below.

Cleco Power

				FOR THE THREE MONTHS ENDED SEPTEMBER 30,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010			VARIANCE			CHANGE
Operating revenue
Base	$	178,159		$	176,584		$	1,575			0.9	%
Fuel cost recovery		146,373			149,045			(2,672	)		(1.8	)%
Electric customer credits		1,852			(6,314	)		8,166			129.3	%
Other operations		15,565			12,819			2,746			21.4	%
Affiliate revenue		347			343			4			1.2	%
Operating revenue, net		342,296			332,477			9,819			3.0	%
Operating expenses
Fuel used for electric generation – recoverable		121,739			97,870			(23,869	)		(24.4	)%
Power purchased for utility customers – recoverable		24,627			51,218			26,591			51.9	%
Non-recoverable fuel and power purchased		1,147			3,177			2,030			63.9	%
Other operations		31,185			28,650			(2,535	)		(8.8	)%
Maintenance		15,768			20,272			4,504			22.2	%
Depreciation		28,859			27,133			(1,726	)		(6.4	)%
Taxes other than income taxes		8,802			9,161			359			3.9	%
(Gain) loss on sale of assets		(6	)		7			13			185.7	%
Total operating expenses		232,121			237,488			5,367			2.3	%
Operating income	$	110,175		$	94,989		$	15,186			16.0	%
Other income	$	1,323		$	293		$	1,030			351.5	%
Interest charges	$	25,306		$	16,044		$	(9,262	)		(57.7	)%
Federal and state income taxes	$	31,656		$	26,568		$	(5,088	)		(19.2	)%
Net income	$	53,833		$	52,335		$	1,498			2.9	%

48

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Cleco Power’s net income in the third quarter of 2011 increased $1.5 million, or 2.9%, compared to the third quarter of 2010.  Contributing factors include:

§   lower electric customer credits,

§   lower maintenance expense,

§   higher other operations revenue,

§   lower non-recoverable fuel and power purchased,

§   higher base revenue, and

§   higher other income.

These were partially offset by:

§   higher interest charges,

§   higher other operations expense,

§   higher depreciation, and

§   higher effective income tax rate.

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(MILLION kWh)	2011	2010	FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	1,274	1,263	0.9 %
Commercial	796	771	3.2 %
Industrial	619	592	4.6 %
Other retail	36	37	(2.7)%
Total retail	2,725	2,663	2.3 %
Sales for resale	652	639	2.0 %
Unbilled	(129)	(125)	(3.2)%
Total retail and wholesale customer sales	3,248	3,177	2.2 %

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$	99,144		$	100,301			(1.2	)%
Commercial		48,732			48,193			1.1	%
Industrial		22,468			22,563			(0.4	)%
Other retail		2,600			2,721			(4.4	)%
Surcharge		2,983			1,350			121.0	%
Other		(1,578	)		(1,704	)		7.4	%
Total retail		174,349			173,424			0.5	%
Sales for resale		11,455			14,745			(22.3	)%
Unbilled		(7,645	)		(11,585	)		34.0	%
Total retail and wholesale customer sales	$	178,159		$	176,584			0.9	%

Cleco Power’s residential customers’ demand for electricity largely is affected by weather.  Weather generally is measured in cooling-degree days and heating-degree days.  A cooling-degree day is an indication of the likelihood that a consumer will use air conditioning, while a heating-degree day is an indication of the likelihood that a consumer will use heating.  An increase in heating-degree days does not produce the same increase in revenue as an increase in cooling-degree days, because alternative heating sources are more available and because winter energy is priced below the rate charged for energy used in the summer.  Normal heating-degree days and cooling-degree days are calculated for a month by separately calculating the average actual heating- and cooling-degree days for that month over a period of 30 years.

The following chart shows how cooling-degree days varied from normal conditions and from the prior period.  Cleco Power uses weather data provided by the National Oceanic and Atmospheric Administration to determine degree days.

			FOR THE THREE MONTHS ENDED SEPTEMBER 30,
				2011 CHANGE
	2011	2010	NORMAL	PRIOR YEAR	NORMAL
Cooling-degree days	1,671	1,728	1,489	(3.3)%	12.2%

Base

Base revenue increased $1.6 million, or 0.9%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to higher electric sales, generally resulting from favorable weather.  Although cooling degree days for the quarter were slightly down, Cleco Power experienced warmer weather in August 2011 as compared to the same period last year.  Cleco Power anticipates incremental base revenue over the remainder of 2011 of $1.8 million and an additional $6.8 million for 2012 associated with the completed portions of the Acadiana Load Pocket transmission project.  

Cleco Power expects new industrial load to be added during the remainder of 2011, 2012, and 2013, principally driven by expected development of Haynesville shale gas recently discovered in Northwestern Louisiana and the construction of a new gas storage facility.  In addition, Cleco Power also expects to begin providing service to expansions of current customers’ operations, as well as service to a new customer.  These expansions of service to current customers and service to a new customer are expected to contribute base revenue of $2.2 million during the remainder of 2011, an additional $2.9 million in 2012, and an additional $0.4 million in 2013.  For information on the effects of future energy sales on Cleco Power’s financial condition, results of operations, and cash flows, see “Risk Factors — Future Electricity Sales” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Fuel Cost Recovery

Fuel cost recovery revenue billed to customers decreased $2.7 million, or 1.8%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to decreases in the per-unit cost of fuel used for electric generation and power purchased for utility customers.  Also contributing to the decrease were lower volumes of power purchased for utility customers.  Partially offsetting the decrease were higher volumes of fuel used for electric generation.  Changes in fuel costs historically have not significantly affected Cleco Power’s net income.  Generally, fuel and purchased power expenses are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to its customers substantially all such charges.  Approximately 94% of Cleco Power’s total fuel cost during the third quarter of 2011 was regulated by the LPSC, while the remainder was regulated by FERC.  Recovery of fuel adjustment clause costs is subject to refund until approval is received from the LPSC.  For information on Cleco Power’s current LPSC fuel audit, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 12 — LPSC Fuel Audit.”

49

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Electric Customer Credits

Electric customer credits decreased $8.2 million, or 129.3%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to lower accruals for customer credits.  For additional information on the accrual for electric customer credits, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 9 — Electric Customer Credits.”

Other Operations

Other operations revenue increased $2.7 million, or 21.4%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to $1.6 million of higher mineral lease payments and $1.1 million related to the gain on sales of Cleco Power’s fuel oil supply.

Operating Expenses

Operating expenses decreased $5.4 million, or 2.3%, in the third quarter of 2011 compared to the third quarter of 2010.  Fuel used for electric generation (recoverable) increased $23.9 million, or 24.4%, primarily due to higher volumes of fuel used for electric generation. Partially offsetting this increase were lower per unit costs of fuel used for electric generation as compared to the third quarter of 2010.  Power purchased for utility customers (recoverable) decreased $26.6 million, or 51.9%, largely due to lower volumes and lower per unit costs of purchased power.  Fuel used for electric generation and power purchased for utility customers generally are influenced by natural gas prices, as well as availability of transmission.  However, other factors such as scheduled and/or unscheduled outages, unusual maintenance or repairs, or other developments may affect fuel used for electric generation and power purchased for utility customers.  Non-recoverable fuel and power purchased decreased $2.0 million, or 63.9%, primarily due to the absence of non-recoverable expenses related to fixed-price power that was provided to a wholesale customer in the third quarter of 2010.  Other operations expense increased $2.5 million, or 8.8%, primarily due to higher transmission and generating station expenses, and higher employee benefit costs and administrative expenses.  Maintenance expense decreased $4.5 million, or 22.2%, primarily due to lower generating station and distribution maintenance work performed during the third quarter of 2011.  Depreciation expense increased $1.7 million, or 6.4%, primarily due to higher amortization expense as a result of a change in rates and the Teche Unit 4 Blackstart Project being placed in service in 2011.

Other Income

Other income increased $1.0 million, or 351.5%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to higher revenue from mutual assistance to other utilities for restoration efforts and higher royalty payments.

Interest Charges

Interest charges increased $9.3 million, or 57.7%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to $7.3 million related to uncertain tax positions and $3.8 million related to the November 2010 issuance of $250.0 million of senior notes.  Partially offsetting this increase was a $1.8 million decrease related to other miscellaneous interest charges and the repayment of insured quarterly notes and a bank term loan in October 2010 and November 2010, respectively.  

Income Taxes

Federal and state income taxes increased $5.1 million, or 19.2%, during the third quarter of 2011 compared to the third quarter of 2010.  The increase is primarily due to a $2.5 million change in pre-tax income excluding AFUDC equity, $1.9 million for miscellaneous items, and $1.5 million to record tax expense at the projected annual effective tax rate.  These increases were partially offset by $0.7 million for tax benefits taken on the prior year income tax return and $0.1 million to record tax expense at the projected annual effective tax rate.

Midstream

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
						FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010		VARIANCE			CHANGE
Operating revenue
Tolling operations	$	9,133		$	11,153	$	(2,020	)		(18.1	)%
Other operations		1			1		-			-
Affiliate revenue		-			5		(5	)		(100.0	)%
Operating revenue		9,134			11,159		(2,025	)		(18.1	)%
Operating expenses
Other operations		2,121			1,944		(177	)		(9.1	)%
Maintenance		(1,131	)		2,987		4,118			137.9	%
Depreciation		1,457			1,446		(11	)		(0.8	)%
Taxes other than income taxes		620			76		(544	)		(715.8	)%
(Gain) loss on sale of assets		(62	)		6		68			*
Total operating expenses		3,005			6,459		3,454			53.5	%
Operating income	$	6,129		$	4,700	$	1,429			30.4	%
Equity income from investees, before tax	$	-		$	2,494	$	(2,494	)		(100.0	)%
Other income	$	1,012		$	1,836	$	(824	)		(44.9	)%
Federal and state income tax expenses	$	444		$	2,758	$	2,314			83.9	%
Net income	$	5,946		$	5,156	$	790			15.3	%
* Not meaningful

Factors affecting Midstream during the third quarter of 2011 are described below.

Operating Revenue

Operating revenue decreased $2.0 million, or 18.1%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to lower tolling revenue at Evangeline resulting from lower plant run time.

50

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Operating Expenses

Operating expenses decreased $3.5 million, or 53.5%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to lower maintenance expenses at Evangeline and $2.4 million of insurance recovery related to outage expenses incurred during the second quarter of 2011.

Equity Income from Investees

Equity income from investees decreased $2.5 million, or 100.0%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to the absence in the third quarter of 2011 of equity earnings at APH resulting from the disposition of Acadia Unit 2 and the subsequent consolidation of Acadia effective April 29, 2011.  For additional information on the disposition of Acadia Unit 2, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 10 — Variable Interest Entities and Note 15 — Acadia Transactions — Acadia Unit 2.”

Other Income

Other income decreased $0.8 million, or 44.9%, in the third quarter of 2011 compared to the third quarter of 2010 largely as a result of lower contractual expirations of underlying indemnifications related to Acadia Unit 1.

Income Taxes

Federal and state income taxes decreased $2.3 million, or 83.9%, during the third quarter of 2011 compared to the third quarter of 2010 primarily due to tax benefits taken in the prior year income tax return and a decrease in pre-tax income.  The effective income tax rate is different than the federal statutory rate due to state tax expense.

Comparison of the Nine Months Ended September 30, 2011, and 2010

Cleco Consolidated

			FOR THE NINE MONTHS ENDED SEPTEMBER 30,
					FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011		2010		VARIANCE			CHANGE
Operating revenue, net	$	878,193	$	892,081	$	(13,888	)		(1.6	)%
Operating expenses		626,489		656,101		29,612			4.5	%
Operating income	$	251,704	$	235,980	$	15,724			6.7	%
Allowance for other funds used during construction	$	3,757	$	11,052	$	(7,295	)		(66.0	)%
Equity income from investees, before tax	$	62,051	$	39,212	$	22,839			58.2	%
Gain on toll settlement	$	-	$	148,402	$	(148,402	)		(100.0	)%
Interest charges	$	78,011	$	72,020	$	(5,991	)		(8.3	)%
Federal and state income taxes	$	73,451	$	127,411	$	53,960			42.4	%
Net income applicable to common stock	$	165,067	$	234,733	$	(69,666	)		(29.7	)%

Consolidated net income applicable to common stock decreased $69.7 million, or 29.7%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to the absence of 2010 gains at Midstream related to the termination of the Evangeline Tolling Agreement and Acadia Unit 1 transaction, partially offset by the 2011 gain from the Acadia Unit 2 transaction.  Also contributing to the decrease were lower Cleco Power earnings.  Partially offsetting these decreases were higher corporate earnings.

Operating revenue, net decreased $13.9 million, or 1.6%, in the first nine months of 2011 compared to the first nine months of 2010 largely as a result of lower fuel cost recovery revenue at Cleco Power due to lower per unit costs of fuel used for electric generation and lower per unit costs and volumes of power purchased for utility customers.

Operating expenses decreased $29.6 million, or 4.5%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to lower per unit costs and volumes of power purchased for utility customers.

Allowance for other funds used during construction decreased $7.3 million, or 66.0%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to the cessation of AFUDC accruals related to the completion of construction activity at Madison Unit 3.  

Equity income from investees increased $22.8 million, or 58.2%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to increased equity earnings at APH primarily from the recognition of a $62.0 million gain from the disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  Partially offsetting this increase was the absence of the gain from Cleco Power’s acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities during 2010.  For additional information on the Acadia Unit 1 and 2 transactions, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 10 — Variable Interest Entities and Note 15 — Acadia Transactions.”

Gain on toll settlement was $148.4 million in the first nine months of 2010 due to transactions related to the termination of the existing Evangeline Tolling Agreement and the execution of the Evangeline 2010 Tolling Agreement.  For additional information, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14 — Evangeline Transactions.”  

Interest charges increased $6.0 million, or 8.3%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to higher interest charges at Cleco Power.  Partially offsetting this increase were lower corporate interest charges related to uncertain tax positions and the repayment of a bank term loan in April 2011.  

Federal and state income taxes decreased $54.0 million, or 42.4%, during the first nine months of 2011 compared to the first nine months of 2010.  Decreases include $44.7 million for the change in pre-tax income excluding AFUDC equity, $2.4 million for the tax impact of a valuation allowance for capital loss carryforwards recorded in 2010 and reversed in 2011 due to capital gains generated in 2011, $1.9 million for a Medicare D adjustment resulting from new legislation enacted in 2010, $7.8 million for tax benefits taken on the prior year income tax return, and $0.2 million to record tax expense at the consolidated annual projected effective tax rate.  These decreases were partially offset by $3.0 million for the adjustment in 2010 related to the implementation of the new rates approved by the LPSC.

51

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

Results of operations for Cleco Power and Midstream are more fully described below.

Cleco Power

				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010			VARIANCE			CHANGE
Operating revenue
Base	$	470,166		$	448,589		$	21,577			4.8	%
Fuel cost recovery		353,318			390,939			(37,621	)		(9.6	)%
Electric customer credits		(3,405	)		(6,314	)		2,909			46.1	%
Other operations		40,261			32,959			7,302			22.2	%
Affiliate revenue		1,041			1,029			12			1.2	%
Operating revenue, net		861,381			867,202			(5,821	)		(0.7	)%
Operating expenses
Fuel used for electric generation – recoverable		295,160			270,165			(24,995	)		(9.3	)%
Power purchased for utility customers – recoverable		58,145			120,812			62,667			51.9	%
Non-recoverable fuel and power purchased		3,369			10,154			6,785			66.8	%
Other operations		87,086			81,111			(5,975	)		(7.4	)%
Maintenance		53,962			51,697			(2,265	)		(4.4	)%
Depreciation		84,543			77,941			(6,602	)		(8.5	)%
Taxes other than income taxes		25,585			25,110			(475	)		(1.9	)%
(Gain) loss on sale of assets		(7	)		47			54			114.9	%
Total operating expenses		607,843			637,037			29,194			4.6	%
Operating income	$	253,538		$	230,165		$	23,373			10.2	%
Allowance for other funds used during construction	$	3,757		$	11,052		$	(7,295	)		(66.0	)%
Other income	$	2,168		$	1,038		$	1,130			108.9	%
Other expense	$	4,499		$	3,619		$	(880	)		(24.3	)%
Interest charges	$	74,029		$	57,104		$	(16,925	)		(29.6	)%
Federal and state income taxes	$	61,935		$	58,299		$	(3,636	)		(6.2	)%
Net income	$	119,557		$	123,584		$	(4,027	)		(3.3	)%

Cleco Power’s net income in the first nine months of 2011 decreased $4.0 million, or 3.3%, compared to the first nine months of 2010.  Contributing factors include:

§   higher interest charges,

§   higher other operations and maintenance expenses,

§   lower allowance for other funds used during construction,

§   higher depreciation expense, and

§   higher effective income tax rate.

These were partially offset by:

§   higher base revenue,

§   higher other operations revenue,

§   lower non-recoverable fuel and power purchased expenses, and

§   lower electric customer credits.

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(MILLION kWh)	2011	2010	FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	3,105	3,156	(1.6)%
Commercial	2,037	1,990	2.4 %
Industrial	1,770	1,679	5.4 %
Other retail	103	106	(2.8)%
Total retail	7,015	6,931	1.2 %
Sales for resale	1,495	1,541	(3.0)%
Unbilled	(90)	2	*
Total retail and wholesale customer sales	8,420	8,474	(0.6)%
* Not meaningful

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$	235,672		$	208,811			12.9	%
Commercial		137,133			116,897			17.3	%
Industrial		64,323			55,774			15.3	%
Other retail		7,484			6,727			11.3	%
Surcharge		7,534			7,205			4.6	%
Other		(4,875	)		(4,383	)		(11.2	)%
Total retail		447,271			391,031			14.4	%
Sales for resale		34,433			34,199			0.7	%
Unbilled		(11,538	)		23,359			(149.4	)%
Total retail and wholesale customer sales	$	470,166		$	448,589			4.8	%

The following chart shows how cooling- and heating–degree days varied from normal conditions and from the prior period.  Cleco Power uses weather data provided by the National Oceanic and Atmospheric Administration to determine degree days.

			FOR THE NINE MONTHS ENDED SEPTEMBER 30,
				2011 CHANGE
	2011	2010	NORMAL	PRIOR YEAR	NORMAL
Heating-degree days	937	1,317	999	(28.9)%	(6.2)%
Cooling-degree days	3,016	2,903	2,453	3.9 %	23.0 %

Base

Base revenue increased $21.6 million, or 4.8%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to the base rate increase that became effective in February 2010, which included Madison Unit 3 and the investment in Acadia Unit 1.  Also included in base revenue were amounts related to the completed portions of the Acadiana Load Pocket transmission project.  Partially offsetting these increases were lower kWh electric sales, primarily related to milder winter weather in the first quarter of 2011.  For information on the anticipated effects of changes in base revenue in future periods, see “— Comparison of the Three Months Ended September 30, 2011, and 2010 — Cleco Power — Base.”  For information on the effects of future energy sales on Cleco Power’s financial condition, results of operations, and cash flows, see “Risk Factors — Future Electricity Sales” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Fuel Cost Recovery

Fuel cost recovery revenue billed to customers decreased $37.6 million, or 9.6%, during the first nine months of 2011

52

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

compared to the first nine months in 2010 primarily due to decreases in the per-unit cost of fuel used for electric generation, power purchased for utility customers, and lower volumes of power purchased for utility customers.  Partially offsetting the decrease were higher volumes of fuel used for electric generation.  Lower volumes of power purchased were primarily due to Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1 during 2010.  For information on Cleco Power’s ability to recover fuel and purchase power costs, see “— Comparison of the Three Months Ended September 30, 2011, and 2010 — Cleco Power — Fuel Cost Recovery.”

Electric Customer Credits

Electric customer credits decreased $2.9 million, or 46.1%, during the first nine months of 2011 compared to the first nine months of 2010 as a result of a lower estimated accrual for a rate refund.  For additional information on the accrual of electric customer credits, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 9 — Electric Customer Credits.”

Other Operations

Other operations revenue increased $7.3 million, or 22.2%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to a $3.8 million gain on sale of Cleco Power’s fuel oil supply, $2.7 million of higher mineral lease payments, $0.6 million related to the absence of net unfavorable results relating to economic hedge transactions associated with fixed-price power that was provided to a wholesale customer, and $0.3 million of higher customer fees.

Operating Expenses

Operating expenses decreased $29.2 million, or 4.6%, in the first nine months of 2011 compared to the first nine months of 2010.  Fuel used for electric generation (recoverable) increased $25.0 million, or 9.3%, primarily due to higher volumes of fuel used as compared to the first nine months of 2010.  Partially offsetting this increase were lower per unit costs of fuel used for electric generation.  Power purchased for utility customers (recoverable) decreased $62.7 million, or 51.9%, largely due to lower volumes and lower per-unit costs of purchased power.  Lower volumes of power purchased were primarily due to Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1.  Fuel used for electric generation and power purchased for utility customers generally are influenced by natural gas prices, as well as availability of transmission.  However, other factors such as scheduled and/or unscheduled outages, unusual maintenance or repairs, or other developments may affect fuel used for electric generation and power purchased for utility customers.  Non-recoverable fuel and purchased power decreased $6.8 million, or 66.8%, primarily due to the absence of non-recoverable expenses related to fixed-price power that was provided to a wholesale customer during 2010 and lower capacity payments made during the first nine months of 2011 primarily due to the commencement of commercial operations of Madison Unit 3 and the acquisition of Acadia Unit 1.  Other operations expense increased $6.0 million, or 7.4%, primarily due to higher generating station and distribution expenses, higher employee benefit costs and administrative expenses and higher customer service expenses.  Partially offsetting these increases were lower professional fees.  Maintenance expense increased $2.3 million, or 4.4%, primarily due to higher generating station, distribution, and transmission maintenance work performed during the first nine months of 2011.  Other operations and maintenance expenses were impacted during the first nine months of 2011 as a result of Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1.  Depreciation expense increased $6.6 million, or 8.5%, largely due to Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1.  

Allowance for Other Funds Used During Construction

Allowance for other funds used during construction decreased $7.3 million, or 66.0%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to the cessation of AFUDC accruals related to the completion of construction activity at Madison Unit 3.  

Other Income

Other income increased $1.1 million, or 108.9%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to higher royalty payments and higher revenue from mutual assistance to other utilities for restoration efforts.

Other Expense

Other expense increased $0.9 million, or 24.3%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to higher amortization of the plant acquisition adjustment related to Cleco Power’s acquisition of Acadia Unit 1 and higher expenses from mutual assistance to other utilities for restoration efforts.

Interest Charges

Interest charges increased $16.9 million, or 29.6%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to $11.3 million related to the November 2010 issuance of $250.0 million of senior notes, $7.6 million related to uncertain tax positions, and $2.7 million of lower interest charges capitalized in 2011 compared to 2010 associated with Madison Unit 3.  Partially offsetting this increase was $2.9 million from the repayment of insured quarterly notes and a bank term loan in October 2010 and November 2010, respectively, and $1.8 million of other miscellaneous interest charges.

Income Taxes

Federal and state income taxes increased $3.6 million, or 6.2%, during the first nine months of 2011 compared to the first nine months of 2010.  The increase includes $2.6 million for the change in pre-tax income excluding AFUDC equity, $3.0 million for the adjustment in 2010 related to the

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implementation of new rates approved by the LPSC, $1.7 million for miscellaneous items, and $0.9 million to record tax expense at the projected annual effective tax rate.  These increases were partially offset by $2.4 million for the tax impact of a valuation allowance for capital loss carryforwards recorded in 2010 and reversed in 2011 due to capital gains generated in 2011, $1.5 million for a Medicare D adjustment resulting from new legislation enacted in 2010, and $0.7 million for tax benefits taken in the prior year income tax return.

Midstream

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
						FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010		VARIANCE			CHANGE
Operating revenue
Tolling operations	$	16,137		$	23,016	$	(6,879	)		(29.9	)%
Other operations		8			2		6			300.0	%
Affiliate revenue		45			924		(879	)		(95.1	)%
Operating revenue		16,190			23,942		(7,752	)		(32.4	)%
Operating expenses
Other operations		5,999			5,962		(37	)		(0.6	)%
Maintenance		5,535			6,902		1,367			19.8	%
Depreciation		4,370			4,334		(36	)		(0.8	)%
Taxes other than income taxes		1,880			261		(1,619	)		(620.3	)%
(Gain) loss on sale of assets		(556	)		12		568			*
Total operating expenses		17,228			17,471		243			1.4	%
Operating (loss) income	$	(1,038	)	$	6,471	$	(7,509	)		(116.0	)%
Equity income from investees, before tax	$	62,053		$	39,211	$	22,842			58.3	%
Gain on toll settlement	$	-		$	148,402	$	(148,402	)		(100.0	)%
Interest charges	$	1,963		$	5,972	$	4,009			67.1	%
Federal and state income tax expense	$	21,296		$	72,905	$	51,609			70.8	%
Net income	$	39,274		$	117,176	$	(77,902	)		(66.5	)%
* Not meaningful

Factors affecting Midstream during the first nine months of 2011 are described below.

Operating Revenue

Operating revenue decreased $7.8 million, or 32.4%, during the first nine months of 2011 compared to the first nine months of 2010, largely as a result of lower tolling revenue resulting from the Evangeline restructuring and pricing of the Evangeline 2010 Tolling Agreement.  Affiliate revenue decreased $0.9 million, or 95.1%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to a decrease in services provided by Generation Services employees who were transferred to Cleco Power during 2010 as a result of Cleco Power’s acquisition of Acadia Unit 1.

Operating Expenses

Maintenance expenses decreased $1.4 million, or 19.8%, during the first nine months of 2011 compared to the first nine months of 2010, largely as a result of lower turbine maintenance expenses at Evangeline.  Taxes other than income taxes increased $1.6 million, or 620.3%, primarily due to higher property taxes at Evangeline as a result of the expiration of a 10-year property tax exemption.  Gain on sale of assets increased $0.6 million primarily due to insurance recovery related to outage expenses at Evangeline.

Equity Income from Investees

Equity income from investees increased $22.8 million, or 58.3%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to increased equity earnings at APH primarily from the recognition of a $62.0 million gain from the disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  Partially offsetting this increase was the absence of the gain from Cleco Power’s acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities during the first half of 2010.  For additional information on the Acadia Unit 1 and 2 transactions, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 10 — Variable Interest Entities and Note 15 — Acadia Transactions.”

Gain on Toll Settlement

Gain on toll settlement was $148.4 million in the first nine months of 2010 due to transactions related to the termination of the Evangeline Tolling Agreement and the execution of the Evangeline 2010 Tolling Agreement.  For additional information, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14 — Evangeline Transactions.”  

Interest Charges

Interest charges decreased $4.0 million, or 67.1%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to the retirement of Evangeline’s debt in 2010 and lower interest charges related to uncertain tax positions.  For additional information, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14 — Evangeline Transactions.”

Income Taxes

Federal and state income taxes decreased $51.6 million, or 70.8%, during the first nine months of 2011 compared to the first nine months of 2010 primarily due to a decrease in pre-tax income and tax benefits taken in the prior year income tax return.  The effective income tax rate is different than the federal statutory rate due to state tax expense.

FINANCIAL CONDITION

Liquidity and Capital Resources

General Considerations and Credit-Related Risks

Credit Ratings and Counterparties

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short- and long-term financing.  The inability to raise capital on favorable terms could negatively affect Cleco’s or Cleco Power’s ability to maintain or expand its businesses.  Access

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to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, Cleco Corporation’s and Cleco Power’s credit ratings, the cash flows from routine operations, and the credit ratings of project counterparties.  After assessing the current operating performance, liquidity, and credit ratings of Cleco and Cleco Power, management believes that Cleco and Cleco Power will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  The following table presents the credit ratings of Cleco Corporation and Cleco Power at September 30, 2011:

	SENIOR UNSECURED DEBT
	MOODY’S	STANDARD & POOR’S
Cleco Corporation	Baa3	BBB-
Cleco Power	Baa2	BBB

Cleco notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.  Each rating should be evaluated independently of any other rating.

For the nine-month period ended September 30, 2011, there were no changes to Cleco or Cleco Power’s credit ratings or rating agency’s outlooks.  At September 30, 2011, Moody’s and Standard & Poor’s outlooks for both Cleco Corporation and Cleco Power were stable.  Cleco Corporation and Cleco Power pay fees and interest under their bank credit agreements based on the highest rating held.  If Cleco Corporation or Cleco Power’s credit rating were to be downgraded by Moody’s and Standard & Poor’s, Cleco Corporation and/or Cleco Power would be required to post additional fees and incur higher interest rates under their bank credit agreements.  Cleco Power’s collateral for derivatives is based on the lowest rating held.  If Cleco Power’s credit ratings were to be downgraded by Standard & Poor’s or Moody’s, Cleco Power would be required to post additional collateral for derivatives.  

In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Madison Unit 3.  In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract.  Under the terms of the Amended EPC Contract, until the final acceptance of Madison Unit 3, in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million.  In the event of further downgrade to both of its credit ratings to: (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.

With respect to any open power or natural gas trading positions that Cleco may initiate in the future, Cleco may be required to provide credit support or pay liquidated damages.  The amount of credit support that Cleco may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price of power and natural gas, the changes in open power and gas positions, and changes in the amount counterparties owe Cleco.  Changes in any of these factors could cause the amount of requested credit support to increase or decrease.  

Global and U.S. Economic Environment

The current economic environment and uncertainty may have an impact on Cleco’s business and financial condition.  Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  Market conditions during the past few years have limited the availability and have increased the costs of capital for many companies.  Although the Registrants have not experienced restrictions in the financial markets, their ability to access the capital markets may be restricted at a time when the Registrants would like, or need, to do so.  Any restrictions could have a material impact on the Registrants’ ability to fund capital expenditures or debt service, or on their flexibility to react to changing economic and business conditions. Credit constraints could have a material negative impact on the Registrants’ lenders or customers, causing them to fail to meet their obligations to the Registrants or to delay payment of such obligations.  The lower interest rates that the Registrants have been exposed to have been beneficial to recent debt issuances; however, these rates have negatively affected interest income for the Registrants’ short-term investments.  

Fair Value Measurements

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values.  Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance.  Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes under GAAP.  Other financial assets and liabilities, such as long-term debt, are reported at their carrying values at their date of issuance on the consolidated balance sheets with their fair values disclosed without regard to the three levels.  For additional information about fair value levels, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 4 — Fair Value Accounting.”

Debt

At September 30, 2011, Cleco Corporation and Cleco Power were in compliance with the covenants in their credit facilities.  If Cleco Corporation were to default under the covenants in its credit facility or other debt agreements, it would be unable to borrow additional funds under the facility, and the lenders could accelerate all principal and interest outstanding.  Further, if Cleco Power were to default under its credit facility or other debt agreements, Cleco Corporation would be considered in default under its credit facility.  

On October 7, 2011, Cleco Corporation amended its credit facility agreement. Under the amended agreement, Cleco Corporation’s maximum capacity was increased from $200.0 million to $250.0 million, the maturity date was extended to

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October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.50%, plus facility fees of 0.25%.  At September 30, 2011, Cleco Corporation had no borrowings outstanding under its original credit facility.  If Cleco Corporation’s credit ratings were to be downgraded one level, Cleco Corporation would be required to pay fees and interest at a rate of 0.25% higher than the level for its current amended $250.0 million credit facility.

On October 7, 2011, Cleco Power amended its credit facility agreement. Under the amended agreement, the maturity date was extended to October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.275%, plus facility fees of 0.225%. At September 30, 2011, Cleco Power had no borrowings outstanding under its original credit facility.  If Cleco Power’s credit ratings were to be downgraded one level, Cleco Power would be required to pay fees and interest at a rate of 0.25% higher than the level on its current amended $300.0 million credit facility.

Cleco Consolidated

Cleco had no short-term debt outstanding at September 30, 2011, compared to $150.0 million outstanding at December 31, 2010.  The short-term debt outstanding at December 31, 2010, was a bank term loan Cleco Corporation entered into in February 2010.  The bank term loan had an interest rate of LIBOR plus 2.75% and was set to mature in February 2011.  In January 2011, Cleco extended the bank term loan to mature August 19, 2011, and lowered the interest rate to LIBOR plus 2.50% or ABR plus 1.50%.  In April 2011, Cleco repaid the $150.0 million bank term loan.  As part of the repayment, Cleco paid $0.6 million for accrued interest on the term loan.

At September 30, 2011, Cleco’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.41 billion outstanding at December 31, 2010, which included $12.3 million due within one year.  The long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco, long-term debt decreased $28.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011, a $15.0 million decrease in credit facility draws outstanding, and $1.3 million of capital lease payments.  These decreases were partially offset by debt premium amortizations of $0.3 million.

Cash and cash equivalents available at September 30, 2011, were $158.2 million combined with $500.0 million facility capacity ($200.0 million from Cleco Corporation and $300.0 million from Cleco Power) for total liquidity of $658.2 million.  Cash and cash equivalents available at September 30, 2011, decreased $32.9 million when compared to cash and cash equivalents available at December 31, 2010.  This decrease is primarily due to the repayment of debt, a contribution to the pension plan, additions to property, plant and equipment, routine working capital fluctuations, and the payment of common dividends.

At September 30, 2011, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents.  In order to mitigate potential credit risk, Cleco and Cleco Power have established guidelines for short-term investments.  For additional information on the concentration of credit risk through short-term investments classified as cash equivalents, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 4 — Fair Value Accounting.”

At September 30, 2011, and December 31, 2010, Cleco had a working capital surplus of $179.6 million and $131.2 million, respectively.  The $48.4 million increase in working capital is primarily due to:

§   $150.0 million repayment of a bank term loan in April 2011,

§   $20.4 million net decrease related to changes in the recognition of current taxes and uncertain tax positions and related interest charges expected to be settled in the next 12 months, and

§   $10.3 million reduction in the deferred construction carrying costs owed to customers in the next 12 months.

These increases in working capital were partially offset by:

§   $44.7 million reduction of fuel inventories,

§   $32.9 million decrease in cash and cash equivalents as discussed above,

§   $30.0 million of mark-to-market losses on the treasury rate lock outstanding at September 30, 2011, and

§   $11.4 million net reduction of restricted cash used for GO Zone projects and Cleco Katrina/Rita debt service payments.

Cleco Corporation (Holding Company Level)

Cleco Corporation had no short-term debt outstanding at September 30, 2011, compared to $150.0 million outstanding at December 31, 2010.  The short-term debt outstanding at December 31, 2010, was a bank term loan entered into in February 2010.  The bank term loan had an interest rate of LIBOR plus 2.75% and was set to mature in February 2011.  In January 2011, Cleco extended the bank term loan to mature August 19, 2011, and lowered the interest rate to LIBOR plus 2.50% or ABR plus 1.50%.  In April 2011, Cleco repaid the $150.0 million bank term loan.  As part of the repayment, Cleco paid $0.6 million for accrued interest on the term loan.

At September 30, 2011, Cleco Corporation had no draws outstanding under its $200.0 million credit facility compared to $15.0 million outstanding at December 31, 2010.  This facility provides for working capital and other needs.  Cleco Corporation and Cleco Power have uncommitted lines of credit with a bank that allow up to $10.0 million each in short term borrowings, but no more than $10.0 million in aggregate, to support their working capital needs.

Cash and cash equivalents available at September 30, 2011, were $11.9 million.  Cash and cash equivalents available at September 30, 2011, increased $6.6 million when compared to cash and cash equivalents available at

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December 31, 2010, primarily due to routine working capital fluctuations.  

Cleco Power

There was no short-term debt outstanding at Cleco Power at September 30, 2011, or December 31, 2010.  At September 30, 2011, Cleco Power’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.40 billion at December 31, 2010, of which $12.3 million was due within one year.  The $13.1 million of long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco Power, long-term debt decreased $13.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011, and $1.3 million of capital lease payments.  These decreases were partially offset by debt premium amortizations of $0.3 million.  

At September 30, 2011, no borrowings were outstanding under Cleco Power’s $300.0 million credit facility.  This facility provides for working capital and other needs.  Cleco Corporation and Cleco Power have uncommitted lines of credit with a bank that allow up to $10.0 million each in short term borrowings, but no more than $10.0 million in aggregate, to support their working capital needs.

Cash and cash equivalents available at September 30, 2011, were $143.0 million, combined with $300.0 million facility capacity for total liquidity of $443.0 million.  Cash and cash equivalents decreased $41.9 million, when compared to cash and cash equivalents at December 31, 2010, primarily due to the repayment of debt, a contribution to the pension plan, and additions to property, plant and equipment.

At September 30, 2011, and December 31, 2010, Cleco Power had a working capital surplus of $149.2 million and $259.1 million, respectively.  The $109.9 million decrease in working capital is primarily due to:

§   $44.7 million reduction of fuel inventories,

§   $41.9 million decrease in cash and cash equivalents as discussed above,

§   $30.0 million of mark-to-market losses on the treasury rate lock outstanding at September 30, 2011, and

§   $11.4 million net reduction of restricted cash used for GO Zone projects and Cleco Katrina/Rita debt service payments.

These decreases in working capital were partially offset by:

§   $10.3 million reduction in the deferred construction carrying costs owed to customers in the next 12 months, and

§   $3.9 million net increase related to changes in the recognition of current taxes and uncertain tax positions and related interest charges expected to be settled in the next 12 months.

The $32.0 million solid waste disposal facility bonds due in 2038, which were issued by the Rapides Finance Authority for the benefit of Cleco Power in October 2008, were required to be mandatorily tendered by the bondholders for purchase on October 1, 2011, pursuant to the terms of the indenture.  On October 3, 2011, Cleco Power purchased all $32.0 million outstanding bonds at face value plus $1.0 million of accrued interest.  In connection with the purchase, the interest rate of the bonds was converted to a weekly mode and will reset each week based on the SIFMA (Securities Industry and Financial Markets Association) index. The initial interest rate of the bonds at October 3, 2011, was 0.16% per annum. The bonds were issued by the Rapides Finance Authority in connection with a loan agreement between the Rapides Finance Authority and Cleco Power.  The bonds remain outstanding and Cleco Power will report the bonds as a $32.0 million long-term liability and a corresponding $32.0 million long-term asset.  Interest expense will continue to be recorded with a corresponding amount recorded as interest income, excluding amortization of debt issuance costs. Cleco Power has the option to remarket the bonds for new terms and new interest rates, both to be determined by market conditions.

The $100.0 million GO Zone bonds due in 2038, which were issued by the Louisiana Public Facilities Authority for the benefit of Cleco Power, are required to be mandatorily tendered by the holders for purchase on December 1, 2011, pursuant to the terms of the indenture governing the bonds, at which time Cleco Power will have the option to either repay all $100.0 million of Cleco Power’s obligations under the loan agreement relating to the bonds and hold the bonds or cause the bonds to be retired, or cause the bonds to be remarketed. Cleco Power has the option to cause the bonds to be remarketed for new terms at new interest rates, both to be determined by market conditions.

Cash Generation and Cash Requirements

Restricted Cash

Various agreements to which Cleco is subject contain covenants that restrict its use of cash.  As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general corporate purposes.  Cleco’s restricted cash consisted of:  

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Power’s future storm restoration costs		24,652		25,992
Cleco Power’s renewable energy grant		600		-
Cleco Katrina/Rita’s storm recovery bonds		3,554		8,822
Cleco Power’s GO Zone bonds		-		6,137
Total restricted cash	$	28,903	$	41,048

Cleco Katrina/Rita has the right to bill and collect storm restoration costs from Cleco Power’s customers.  As cash is collected, it is restricted for payment of operating expenses, interest, and principal on storm recovery bonds.  During 2011, Cleco Katrina/Rita has collected $14.5 million net of operating

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expenses.  In March and September 2011, Cleco Katrina/Rita used $6.3 million and $6.0 million, respectively for scheduled storm recovery bond principal payments and $3.8 million and $3.7 million, respectively for related interest.  In 2011, Cleco Power received a renewable energy grant from the Louisiana Department of Natural Resources.  

Cleco Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities was $262.6 million during the first nine months of 2011, compared to $192.4 million during the first nine months of 2010.  Cash provided by operating activities during the first nine months of 2011 increased $70.2 million from the first nine months of 2010, primarily due to the following items:

§   return on equity investment in Acadia of $58.7 million,

§   higher collection of receivables of $47.0 million,

§   sales of fuel oil inventory of $35.2 million,

§   absence of 2010 Madison Unit 3 construction carrying costs, Acadia Unit 1 acquisition costs, rate case costs, and IRP/FRP costs of $30.3 million, and

§   lower petroleum coke inventory purchases of $26.2 million due to the build-up of inventory in 2010.

These were partially offset by:

§   higher pension plan contributions of $55.0 million,

§   absence of the 2010 collection of a $28.0 million receivable related to the Evangeline transactions,

§   higher vendor payments of $21.7 million, and

§   absence of the 2010 cash portion of the gain related to the Evangeline Restructuring Agreement for $18.5 million.

Net Investing Cash Flow

Net cash used in investing activities was $54.1 million during the first nine months of 2011, compared to $234.8 million during the first nine months of 2010.  Net cash used in investing activities during the first nine months of 2011 was lower than the first nine months of 2010 primarily due to lower additions to property, plant and equipment, the return of equity investment in Acadia, and lower contributions to the tax credit fund, partially offset by lower transfers of cash from restricted accounts.

During the first nine months of 2011, Cleco had additions to property, plant and equipment, net of AFUDC, of $141.9 million and an $18.5 million investment in New Markets Tax Credits.  This was partially offset by an $89.7 million return of equity investment in Acadia and the transfer of $12.1 million of cash from restricted accounts, primarily related to GO Zone bonds and cash restricted for storm costs.

During the first nine months of 2010, Cleco had additions to property, plant and equipment, net of AFUDC of $241.7 million, a $28.8 million investment in New Markets Tax Credits, an $8.5 million investment in Acadia, and a $0.2 million investment in Oxbow.  This was partially offset by the transfer of $45.2 million of cash from restricted accounts, primarily related to Evangeline, GO Zone bonds, and cash restricted for storm costs.

Net Financing Cash Flow

Net cash used in financing activities was $241.4 million during the first nine months of 2011, compared to $34.9 million during the first nine months of 2010.  Net cash used in financing activities during the first nine months of 2011 was higher than the first nine months of 2010 primarily due to lower draws on the revolving credit facility, higher repayments of short-term debt, the absence of short-term debt issuances, repurchase of common stock, and higher dividends paid on common stock.  This was partially offset by lower payments on the credit facility and lower retirements of long-term debt.

During the first nine months of 2011, Cleco repaid a $150.0 million bank term loan and $37.3 million of long-term debt, consisting of $25.0 million of credit facility draws and $12.3 million of long-term bonds.  Cleco also used $49.2 million for the payment of common stock dividends and $13.0 million for the repurchase of common stock.  This was partially offset by $10.0 million in credit facility draws.

During the first nine months of 2010, Cleco retired $396.7 million of long-term debt, consisting of $350.0 million of credit facility draws, $35.2 million of Evangeline debt, and $11.5 million of long-term bonds.  Cleco also used $43.8 million for the payment of common stock dividends.  This was partially offset by $255.0 million of credit facility draws and the issuance of a $150.0 million bank term loan, which was used to facilitate the acquisition of Acadia Unit 1.

Cleco Power Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities was $184.7 million during the first nine months of 2011, compared to $99.7 million during the first nine months of 2010.

Cash provided by operating activities during the first nine months of 2011 increased $85.0 million from the first nine months of 2010 primarily due to the following items:

§   higher collection of receivables of $46.0 million,

§   sales of fuel oil inventory of $35.2 million,

§   absence of 2010 Madison 3 construction carrying costs, Acadia Unit 1 acquisition costs, rate case costs, and IRP/FRP costs of $30.3 million,

§   lower petroleum coke inventory purchases of $26.2 million due to the build-up of inventory in 2010,

§   lower payments to affiliates of $17.1 million, and

§   lower income taxes paid of $7.7 million.

These were partially offset by:

§   higher pension plan contributions of $55.0 million, and

§   higher vendor payments of $18.2 million.

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Net Investing Cash Flow

Net cash used in investing activities was $112.9 million during the first nine months of 2011, compared to $72.5 million during the first nine months of 2010.  Net cash used in investing activities during the first nine months of 2011 was higher than the first nine months of 2010 primarily due to higher additions to property, plant and equipment.

During the first nine months of 2011, Cleco Power had additions to property, plant and equipment, net of AFUDC of $127.3 million.  This was partially offset by the transfer of $12.1 million of cash from restricted accounts, primarily related to GO Zone bonds and cash restricted for storm costs.

During the first nine months of 2010, Cleco Power had additions to property, plant and equipment, net of AFUDC of $87.3 million.  This was partially offset by the transfer of $15.1 million of cash from restricted accounts, primarily related to solid waste disposal and GO Zone bonds.

Net Financing Cash Flow

Net cash used in financing activities was $113.7 million during the first nine months of 2011, compared to $137.9 million during the first nine months of 2010.  Net cash used in financing activities during the first nine months of 2011 was lower than the first nine months of 2010 primarily due to $25.0 million of lower distributions made to Cleco Corporation.

Common Stock Repurchase Program

In January 2011, Cleco Corporation’s Board of Directors approved the implementation of a new common stock repurchase program authorizing management, on behalf of Cleco Corporation, to repurchase, from time to time, shares of common stock so that Cleco Corporation’s diluted average shares of common stock outstanding remain approximately equal to its diluted average shares of common stock outstanding for 2010.  Purchases may be made on a discretionary basis at times and in amounts as determined by management, subject to market conditions, legal requirements, and other factors.  The purchases will not be announced in advance and may be made in the open market or through privately negotiated transactions.  In August 2011, 400,000 shares of Cleco Corporation’s common stock were repurchased under this program.  For additional information, see “Part II — Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds — Common Stock Repurchases.”

Contractual Obligations and Other Commitments

Cleco, in the normal course of business activities, enters into a variety of contractual obligations.  Some of these result in direct obligations that are reflected in the Condensed Consolidated Balance Sheets while other commitments, some firm and some based on uncertainties, are not reflected in the consolidated financial statements.  

For additional information regarding Cleco’s Contractual Obligations and Other Commitments, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Cash Generation and Cash Requirements — Contractual Obligations and Other Commitments” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Off-Balance Sheet Commitments and Disclosures about Guarantees

Cleco Corporation and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Corporation’s subsidiaries and equity investees (affiliates).  Cleco Corporation and Cleco Power have also agreed to contractual terms that require them to pay third parties if certain triggering events occur.  These contractual terms generally are defined as guarantees in the authoritative guidance.  For additional information on off-balance sheet commitments, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments” and “— Disclosures about Guarantees.”

Regulatory Matters

Wholesale Rates of Cleco

For information on the wholesale rates of Cleco, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Wholesale Rates of Cleco” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Retail Rates of Cleco Power

For information concerning amounts accrued and refunded by Cleco Power as a result of the FRP and information on the LPSC Staff’s FRP reviews, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 9 — Electric Customer Credits.”

For information on certain other regulatory aspects of retail rates concerning Cleco Power, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Retail Rates of Cleco Power” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Wholesale Electric Markets

Electric Reliability Organization

In February 2010, the SPP Regional Entity notified Cleco that an audit would be conducted to determine Cleco’s compliance with the NERC Reliability Standard Requirements.  The audit began in April 2010.  Cleco has submitted mitigation plans and evidence of remedial efforts in connection with the SPP’s findings from the April 2010 audit.  Cleco and SPP have agreed to a financial settlement totaling less than $0.1 million, which has been approved by NERC.  Cleco’s next scheduled audit will begin in 2013.  For more information on regulatory

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aspects of wholesale electric markets affecting Cleco, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Market Restructuring — Wholesale Electric Markets” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Retail Electric Markets

For a discussion of the regulatory aspects of retail electric markets affecting Cleco Power, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Retail Electric Markets” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Generation RFP

Renewable Energy Pilot Program

In November 2010, the LPSC established a two-part renewable energy pilot program implementation plan consisting of a research component and an RFP component.  Cleco Power is meeting the requirements of the research component with research into solar projects, a wind project, and various other renewable projects.  The RFP component of the program requires utilities, collectively, to issue RFPs for 350 MW of renewable energy, with Cleco Power’s share being 43 MW.  However, because Madison Unit 3 is designed to burn biomass fuel, with minor modifications, in addition to its primary fuel, Cleco Power has been given an exception allowing it to conduct an RFP for biomass fuel along with identifying the costs to co-fire biomass fuel in Madison Unit 3.  As part of this process, during October 2011, Cleco Power performed a biomass test burn at Madison Unit 3.  To date, results of the test burn are incomplete.  Cleco Power plans to initiate another test burn in the fourth quarter of 2011.  In October 2011, Cleco Power received LPSC approval for recovery of the test burn costs.  Cleco Power’s final RFP for biomass fuel along with its written report to the LPSC regarding the cost of co-firing biomass fuel in Madison Unit 3 is expected to be completed in 2012.  After the LPSC reviews the results of Cleco Power’s RFP, the LPSC may authorize Cleco Power to pursue co-firing biomass fuel in Madison Unit 3 or require Cleco Power to conduct an additional RFP for 43 MW of renewable energy as discussed above.  For additional information on Cleco’s renewable energy pilot program, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Generation RFP” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

RFP for Short-Term 2012 Resources

In August 2011, Cleco Power issued an RFP for short-term 2012 resources to enhance reliability for the period January through April 2012.  Cleco Power selected and negotiated two agreements from the RFP, a power purchase agreement with NRG Power Marketing LLC, and a tolling agreement with Evangeline.  In September 2011, Cleco Power filed with the LPSC an application for a certificate of public convenience and necessity for the two agreements.  Because Evangeline is a subsidiary of Cleco, Cleco Power also filed an application with the FERC for authorization to make power sales between affiliates pursuant to Section 205 of the Federal Power Act.

RFP for Contractual Resources to Meet the Cross-State Air Pollution Rule Beginning in May 2012

In September 2011, Cleco Power issued a draft RFP for resources to meet the Cross-State Air Pollution Rule.  A bidders conference was conducted on October 13, 2011, and the final RFP was published on October 21, 2011.  Cleco Power is seeking up to approximately 750 MW of capacity and energy for a three- or five-year term.  An additional RFP is expected to be issued by Cleco Power in 2012 seeking long-term access to resources.  That RFP shall be closely coordinated with the RFP for resources to meet the Cross-State Air Pollution Rule.

Madison Unit 3

In May 2006, Cleco Power began construction of Madison Unit 3, a 600-MW solid fuel power plant.  The unit commenced commercial operations on February 12, 2010, whereby Cleco Power accepted care, custody, and control of the unit.  The Madison Unit 3 budget including AFUDC, Amended EPC Contract costs, and other development expenses remains within 1.6% of its estimated projection of $1.0 billion.  Madison Unit 3 is capable of burning various solid fuels, but initially began operation with consumption of petroleum coke produced by several refineries throughout the Gulf Coast region.  Due to operational and economic reasons, Cleco Power purchased various amounts of Illinois basin coal from several suppliers and blended such fuels with petroleum coke throughout 2011 and is anticipated to continue consumption of a blended fuel throughout the year 2012.

In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract to construct the unit, which contract has subsequently been amended by the parties.  Under the amended contract as of September 30, 2011, the lump-sum price for construction of Madison Unit 3 by Shaw was $805.9 million.  In support of Shaw’s performance obligations, Cleco Power, as of December 31, 2010, retained a letter of credit in the amount of $58.9 million, as well as a $200.0 million payment and performance bond in favor of Cleco Power as specified under the Amended EPC Contract.  On April 30, 2010, Shaw filed a demand for arbitration asserting claims of $32.0 million including impacts due to the 2008 hurricane force majeure, alleged excess fuel moisture, intake water quality and a river embankment slope failure, and the associated recovery of schedule related liquidated damages withheld by Cleco Power.  In February 2011, Cleco drew on Shaw’s letter of credit in an amount of $19.0 million due to Shaw’s voidance of a fuel related amendment.  Certain of these matters were argued in arbitration hearings which concluded on June 8, 2011.  On August 5, 2011, the arbitrator announced his decision in favor of Shaw’s claims of Cleco Power owing Shaw

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$32.5 million (including the return of the amounts drawn on Shaw’s letter of credit).  Cleco Power paid this amount on August 22, 2011, which was included as a cost of Madison Unit 3 and reflected as property, plant and equipment.  

Shaw has not reached project completion as defined in the Amended EPC Contract, as various performance tests, the reliability test, and specified boiler performance criteria have not been met.  Under the Amended EPC Contract, Shaw must correct the identified items, complete the performance guarantee tests, meet a 30-day reliability performance test, and correct certain warranty issues to meet final acceptance, or pay certain liquidated damages and financially settle incomplete work.  The disputed items relating to the liquidated damages for Shaw’s inability to meet performance guarantees, as well as for completion of minor or warranty work, were bifurcated from the arbitration proceedings and remains outstanding.  These matters may be resolved through a second arbitration proceeding or potentially settled.

Lignite Deferral

At September 30, 2011, and December 31, 2010, Cleco Power had $19.8 million and $21.7 million, respectively, in deferred lignite mining costs remaining uncollected.  

For additional information on Cleco Power’s deferred lignite mining expenditures, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Other Matters — Lignite Deferral” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Acadiana Load Pocket Project

In September 2008, Cleco Power entered into an agreement with two other utilities to upgrade and expand interconnected transmission systems in south central Louisiana in an area known as the Acadiana Load Pocket.  The project received LPSC and SPP approval in February 2009.  Cleco Power’s initial portion of the estimated cost was approximately $150.0 million, including AFUDC.  Due to lower material and labor costs than initially expected, Cleco Power’s estimated costs for its portion of the project were reduced to $125.0 million, including AFUDC.  At September 30, 2011, Cleco Power had spent $86.3 million on the project and expects to incur an additional $9.6 million during 2011, including AFUDC.  The costs associated with the completed portions of the Acadiana Load Pocket project are included in base revenue.  The project is estimated to be 81% complete with the final completion date expected in 2012.  For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Regulatory Matters — Acadiana Load Pocket Project” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.  For information on the impact the Acadiana Load Pocket project is expected to have on base revenue, see “Results of Operations — Comparison of the Three Months Ended September 30, 2011, and 2010 — Cleco Power — Base.”

AMI Project

In May 2010, Cleco Power accepted the terms of a $20.0 million grant from the DOE under the DOE’s small-grant process to implement smart-grid technology for all of Cleco Power’s retail customers.  Cleco Power estimates the project will cost $73.0 million, with the DOE grant providing $20.0 million toward the project and Cleco Power providing the remaining $53.0 million.  The grant program is a part of the American Recovery and Reinvestment Act of 2009, an economic stimulus package passed by Congress in February 2009.  Smart-grid technology includes the installation of electric meters that enable two-way communication capabilities between a home or business and a utility company.  At September 30, 2011, Cleco Power had incurred $6.9 million in project costs, of which $3.0 million has been submitted to the DOE for reimbursement.  As of September 30, 2011, Cleco Power had received $2.8 million in payments from the DOE.  The project is expected to be completed in the third quarter of 2013.  For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Other Matters — AMI Project” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Teche Unit 4 Blackstart Project

In April 2011, Cleco Power completed work on its project to improve its “blackstart” process (the return of its generation system to service in the event of a total shutdown).  The project was considered complete when a 33-MW gas turbine at Teche Power Station, which has been designated Teche Unit 4, was placed into commercial operation.  At September 30, 2011, Cleco Power had spent $29.5 million on the project and expects to incur less than $0.1 million during the remainder of 2011.  For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Other Matters — Teche Unit 4 Blackstart Project” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Franchises

In 2009, the City of Opelousas conducted a RFP from other power companies to potentially replace Cleco Power’s franchise, which was set to expire on August 11, 2011.  The process did not result in successful bids, and subsequently the Mayor formed a citizens committee to determine if the City of Opelousas should operate its own electricity distribution system or continue the operating and franchise agreement with Cleco Power.  In December 2009, the City of Opelousas requested an extension under the operating and franchise agreement to perform the review.  Cleco Power granted extensions until July 15, 2011 and continued to provide service based on the terms of the existing operating and franchise

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agreement.  On July 14, 2011, the City of Opelousas approved the renewal of its franchise agreement with Cleco Power.  The renewal extends the agreement for 10 years until August 11, 2021.  Approximately 10,000 Cleco Power customers are located in Opelousas.

On July 12, 2011, the Town of Colfax voted to accept the early renewal of its franchise agreement with Cleco Power.  The agreement was set to expire in February 2013.  The renewal extends the agreement for 30 years until July 2043.  Approximately 800 Cleco Power customers are located in Colfax.

Other Franchise Matters

On March 9, 2010, a complaint was filed in the 27th Judicial District Court of St. Landry Parish, State of Louisiana on behalf of three Cleco Power customers in Opelousas, Louisiana.  The complaint alleges that Cleco Power overcharged the plaintiffs by applying to customers in Opelousas the same retail rates as Cleco Power applies to all of its retail customers.  In addition, on May 11, 2010, a second complaint repeating the allegations of the first was filed on behalf of a number of Opelousas residents.  For additional information regarding these complaints, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — City of Opelousas.”

For additional information on Cleco Power’s electric service franchises, please read “Business — Regulatory Matters, Industry Developments, and Franchises — Franchises” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Environmental Matters

Cleco is subject to extensive environmental regulation by federal, state, and local authorities and is required to comply with numerous environmental laws and regulations, and to obtain and comply with numerous governmental permits, in operating its facilities.  In addition, existing environmental laws, regulations, and permits could be revised or reinterpreted; new laws and regulations could be adopted or become applicable to Cleco or its facilities; and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions.  Cleco may incur significant additional costs to comply with these revisions, reinterpretations, and requirements.  Cleco Power would then seek recovery of additional environmental compliance costs as riders through the LPSC’s environmental adjustment clause or its FRP, or as a base rate adjustment as appropriate.  If Cleco fails to comply with these revisions, reinterpretations, and requirements, it could be subject to civil or criminal liabilities and fines.  

In January 2010, the EPA published a proposed rule to reconsider the 2008 national ambient air quality standards (NAAQS) for ozone.  The EPA had proposed to significantly lower the primary ozone standard of 75 parts per billion (ppb) and establish a cumulative, seasonal secondary standard.  This proposed rule was widely criticized by industry which cited flaws in the scientific data used by the EPA to justify a reconsideration of the 2008 NAAQS.  On September 2, 2011, the EPA withdrew its proposed rule to reconsider the 2008 NAAQS for ozone.  Now that the EPA has withdrawn its proposed reconsideration, the 2008 NAAQS of 75 ppb is reinstated and the EPA is moving ahead with states, including Louisiana, to implement the 2008 standard.  The EPA now expects to finalize initial area designations for the 2008 ozone NAAQS by mid-2012 using the most up-to-date monitoring data and then will require states to submit formal implementation plans to them, likely by 2015.  This could result in more stringent NOx controls imposed on power plants located in or near these newly designated non-attainment areas.  Since NOx emissions are a precursor to ozone formation, existing fossil fuel-fired units located in or near ozone non-attainment areas could be targeted for installation of additional NOx emission controls.  Cleco cannot determine the potential impact of this rule on its generating units until Louisiana finalizes its attainment designations and develops a state implementation plan for this rule.

On October 6, 2011, the EPA proposed technical adjustments to the final Cross-State Air Pollution Rule (CSAPR).  The proposal addresses discrepancies affecting state budgets in Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin.  The proposal would also amend the effective date of the assurance penalty by delaying the 3-for-1 penalty provisions from 2012 to 2014.  For Louisiana, the EPA has proposed to increase the state ozone season NOx allowance budget from 13,432 to 17,663 allowances.  The EPA cites as the basis for the proposed rule that it had not accounted for twelve (12) generating units in Louisiana that require significant non-economic dispatch.  As a result, if finalized as proposed, Cleco will receive 464 additional allowances which represent a nearly 30% increase from the current rule.  Even with the proposed additional allowances, Cleco must still consider other compliance options such as the installation of additional emission controls, the purchase of allowances, alternate dispatch schedules for generating units, and the acquisition of alternate generation resources to meet the NOx allocation required for Cleco’s units.  If Cleco cannot obtain sufficient ozone season allowances to cover its ozone season emissions, then Cleco could face significant fines and penalties and/or it may not be able to meet its customer’s demand.

For a discussion of other Cleco environmental matters, please read “Business — Environmental Matters” in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Recent Authoritative Guidance

For a discussion of recent authoritative guidance, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 2 — Recent Authoritative Guidance” of this Combined Quarterly Report on Form 10-Q, which discussion is incorporated herein by reference.

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CRITICAL ACCOUNTING POLICIES

Cleco’s critical accounting policies include those accounting policies that are both important to Cleco’s financial condition and results of operations and those that require management to make difficult, subjective, or complex judgments about future events, which could result in a material impact to the financial statements of Cleco Corporation’s segments or to Cleco as a consolidated entity.  The financial statements contained in this report are prepared in accordance with accounting principles generally accepted in the United States of America, which require Cleco to make estimates and assumptions.  Estimates and assumptions about future events and their effects cannot be made with certainty.  Management bases its current estimates and assumptions on historical experience and on various other factors that are believed to be reasonable under the circumstances.  On an ongoing basis, these estimates and assumptions are evaluated and, if necessary, adjustments are made when warranted by new or updated information or by a change in circumstances or environment.  Actual results may differ significantly from these estimates under different assumptions or conditions. 

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011, or the date of issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.  At September 30, 2011, this derivative qualified as a cash flow hedge because management determined that the interest payments related to the forecasted debt instrument were probable of occurring and the hedge was highly effective.  Events could occur subsequent to September 30, 2011, that could cause the interest payments related to the forecasted debt issuance not to occur, the debt issuance to occur for an amount less than $150.0 million, or to result in ineffectiveness in the hedging relationship.  If the interest payments related to the forecasted debt issuance do not occur, the debt issuance occurs for an amount less than $150.0 million, or results in ineffectiveness, then all, or a portion of the then current mark-to-market loss, or gain, is required to be reclassified from accumulated other comprehensive income to earnings.  For more information about the treasury rate lock contract, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 1 — Summary of Significant Accounting Policies” and “Note 4 — Fair Value Accounting — Treasury Rate Lock.”

For an additional discussion of Cleco’s critical accounting policies, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” in the Registrant’s Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

CLECO POWER — NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

Set forth below is information concerning the results of operations of Cleco Power for the three and nine months ended September 30, 2011, and September 30, 2010.  The following narrative analysis should be read in combination with Cleco Power’s Unaudited Condensed Consolidated Financial Statements and the Notes contained in this Combined Quarterly Report on Form 10-Q.

Cleco Power meets the conditions specified in General Instructions H(1)(a) and (b) to Form 10-Q and is therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies.  Accordingly, Cleco Power has omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures about Market Risk) of Part I of Form 10-Q and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds) and Item 3 (Defaults upon Senior Securities).  Pursuant to the General Instructions, Cleco Power has included an explanation of the reasons for material changes in the amount of revenue and expense items of Cleco Power between the first nine months of 2011 and the first nine months of 2010.  Reference is made to Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

For an explanation of material changes in the amount of revenue and expense items of Cleco Power between the third quarter of 2011 and the third quarter of 2010, see “— Results of Operations — Comparison of the Three Months Ended September 30, 2011, and 2010 — Cleco Power” of this Combined Quarterly Report on Form 10-Q, which discussion is incorporated herein by reference.

For an explanation of material changes in the amount of revenue and expense items of Cleco Power between the first nine months of 2011 and the first nine months of 2010, see “— Results of Operations — Comparison of the Nine Months Ended September 30, 2011, and 2010 — Cleco Power” of this Combined Quarterly Report on Form 10-Q, which discussion is incorporated herein by reference.

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ITEM 3.       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Overview

Market risk inherent in Cleco’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas in the industry on different energy exchanges.  Cleco also is subject to market risk associated with its tolling agreement counterparty.  For additional information concerning Cleco’s market risk associated with its counterparty, see Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — General Considerations and Credit-Related Risks.”

Cleco applies the authoritative guidance as it relates to derivatives and hedging to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market.  Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting since Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements.  

Cleco’s exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of power 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.

Cleco monitors credit risk exposure through reviews of counterparty credit quality, aggregate counterparty credit exposure, and aggregate counterparty concentration levels.  Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Cleco Power has agreements in place with various counterparties that authorize the netting of financial transactions and contract payments to mitigate credit risk for transactions entered into for risk management purposes.

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  Market conditions during the past few years have limited the availability and have increased the costs of capital for many companies.  The inability to raise capital on favorable terms could negatively affect Cleco’s ability to maintain and expand its businesses.  After assessing the current operating performance, liquidity, and credit ratings of Cleco, management believes that it will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  Cleco Corporation and Cleco Power pay fees and interest under their respective credit facilities based on the highest rating held.  If Cleco Corporation or Cleco Power’s credit ratings were to be downgraded by Moody’s and Standard & Poor’s, Cleco Corporation or Cleco Power, as the case may be, would be required to pay additional fees and higher interest rates under their respective credit facilities.  Cleco Power’s collateral for derivatives is based on the lowest rating held.  If Cleco Power’s credit ratings were to be downgraded by Standard & Poor’s or Moody’s, Cleco Power would be required to pay additional collateral for derivatives.

Interest Rate Risks

Cleco monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix, for example, refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt.  For details, see Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 5 — Debt.”  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.

At September 30, 2011, Cleco had no short- or long-term variable rate debt outstanding.  

The $100.0 million GO Zone bonds due in 2038, which were issued by the Louisiana Public Facilities Authority for the benefit of Cleco Power, are required to be mandatorily tendered by the holders for purchase on December 1, 2011, pursuant to the terms of the indenture governing the bonds, at which time Cleco Power will have the option to either repay all $100.0 million of Cleco Power’s obligations under the loan agreement relating to the bonds and hold the bonds or cause the bonds to be retired, or cause the bonds to be remarketed. Cleco Power has the option to cause the bonds to be remarketed for new terms at new interest rates, both to be determined by market conditions. Each 1% increase in the interest rate applicable to such debt would result in a $1.0 million decrease in pre-tax earnings.

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011, or the date issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on

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Cleco and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.  For every one basis point change in the reference rate, the value of the treasury rate lock changes by approximately $0.3 million.  

Commodity Price Risks

Management believes Cleco has controls in place to minimize the risks involved in its financial and energy commodity activities.  Independent controls over energy commodity functions consist of a middle office (risk management), a back office (accounting), and regulatory compliance staff, as well as monitoring by a risk management committee comprised of officers and the General Manager – Internal Audit, who are approved by Cleco Corporation’s Board of Directors.  Risk limits are recommended by the Risk Management Committee and monitored through a daily risk report that identifies the current VaR, current market conditions, and concentration of energy market positions.

Cleco Power provides fuel for generation and purchases power to meet the power demands of customers.  Cleco Power has entered into positions to mitigate the volatility in customer fuel costs, as encouraged by an LPSC order.  Cleco Power’s fuel stabilization policy targets higher levels of minimum hedging percentages and mitigates the volatility in customer fuel costs.  The change in positions could result in increased volatility in the marked-to-market amounts for the financial positions.  These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability and a component of the energy risk management assets or liabilities.  When these positions close, actual gains or losses are deferred and included in the fuel adjustment clause in the month the physical contract settles.  Based on market prices at September 30, 2011, the net mark-to-market impact related to open natural gas positions at September 30, 2011, was a loss of $5.7 million.  All of these natural gas positions will close over the next twelve months.  Deferred losses relating to closed natural gas positions at September 30, 2011, and December 31, 2010, totaled $1.3 million and $1.6 million, respectively.  

Cleco utilizes a VaR model to assess the market risk of its hedging portfolios, including derivative financial instruments.  VaR represents the potential loss in fair value for an instrument from adverse changes in market factors over a defined period of time with a specified confidence level.  VaR is calculated daily, using the variance/covariance method with delta approximation, assuming a holding period of one day, and a 95% confidence level for natural gas and power positions.  Volatility is calculated daily from historical forward prices using the exponentially weighted moving average method.

Based on these assumptions, the VaR relating to Cleco Power’s hedge transactions for the three and nine months ended September 30, 2011, as well as the VaR at December 31, 2010, is summarized below.

	FOR THE THREE MONTHS  ENDED SEPTEMBER 30, 2011
(THOUSANDS)	HIGH		LOW		AVERAGE
Fuel cost hedges	$	820.4	$	379.4	$	580.2

	FOR THE NINE MONTHS  ENDED SEPTEMBER 30, 2011						AT SEPTEMBER 30,		AT DECEMBER 31,
(THOUSANDS)	HIGH		LOW		AVERAGE		2011		2010
Fuel cost hedges	$	1,458.3	$	379.4	$	946.3	$	379.4	$	1,346.0

Cleco Power

Please refer to “— Risk Overview” above for a discussion of market risk inherent in Cleco Power’s market risk-sensitive instruments.

Cleco Power has entered into various fixed- and variable-rate debt obligations.  Please refer to “— Interest Rate Risks” above for a discussion of how Cleco Power monitors its mix of fixed- and variable-rate debt obligations and the manner of calculating changes in fair market value and interest expense of its debt obligations.  

Cleco Power had no short- or long-term variable-rate debt as of September 30, 2011.

Please refer to “— Commodity Price Risks” above for a discussion of controls, transactions, VaR, and market value maturities associated with Cleco Power’s energy commodity activities.  

65

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

ITEM 4.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2011, evaluations were performed under the supervision and with the participation of Cleco Corporation and Cleco Power LLC (individually, “Registrant” and collectively, the “Registrants”) management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO).  The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures.  Based on the evaluations, the CEO and CFO have concluded that the Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrants’ disclosure controls and procedures are also effective in ensuring that such information is accumulated and communicated to the Registrants’ management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls over Financial Reporting

Under the supervision and with the participation of the Registrants’ management, including the CEO and CFO, the Registrants evaluated changes in internal control over financial reporting that occurred during the quarter ended September 30, 2011, and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

66

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

PART II — OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

CLECO

For information on legal proceedings affecting Cleco, see Part I, Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation.”

CLECO POWER

For information on legal proceedings affecting Cleco Power, see Part I, Item 1, “Notes to the Unaudited Condensed Consolidated Financial Statements — Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation.”

ITEM 1A.      RISK FACTORS

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the Registrants’ Combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 (the “Second Quarter 2011 Form 10-Q”) and Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Annual Report on Form 10-K”).  For risks that could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Registrants, see the risk factors disclosed under “Risk Factors” in Item 1A of the Second Quarter 2011 Form 10-Q and the 2010 Annual Report on Form 10-K.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Common Stock Repurchases

In January 2011, Cleco Corporation’s Board of Directors approved the implementation of a new common stock repurchase program.  This program authorizes management to repurchase, from time to time, shares of common stock so that Cleco’s diluted average shares of common stock outstanding remain approximately equal to its diluted average shares of common stock outstanding for 2010.  Under this program, purchases may be made on a discretionary basis at times and in amounts as determined by management, subject to market conditions, legal requirements and other factors.  Purchases under the program will not be announced in advance and may be made in the open market or through privately negotiated transactions.

The following table summarizes the common stock repurchases by Cleco Corporation during the quarter ended September 30, 2011:

PERIOD	TOTAL NUMBER OF  SHARES PURCHASED		AVERAGE PRICE PAID PER SHARE		TOTAL NUMBER OF SHARES  PURCHASED AS PART OF PUBLICLY  ANNOUNCED PLANS OR PROGRAMS		MAXIMUM NUMBER OF SHARES THAT MAY YET BE PURCHASED UNDER THE PLANS OR PROGRAMS
July 2011		-	$	-		-		400,000
August 2011		400,000	$	32.49		400,000		-	*
September 2011		-	$	-		-		-
*Management does not anticipate repurchasing any shares of common stock during the fourth quarter of 2011. Pursuant to the objectives of the program, repurchases under the program should resume in 2012.

ITEM 5.       OTHER INFORMATION

On October 28, 2011, the Board of Directors (Board) of Cleco Corporation adopted the Cleco Corporation Executive Severance Plan (Executive Plan) to be effective as of such date.  As an alternative to benefits previously provided by employment agreements, the Executive Plan provides severance and change in control benefits to senior officers, officers, and general managers in the event of a change in control, provided that a qualifying termination has occurred and certain additional conditions are satisfied.  Since Cleco Corporation’s general managers currently are covered by the Cleco Corporation Severance Pay Plan, which was adopted by Cleco Corporation in 2009, a conforming amendment to that plan removing general managers as covered employees also was approved by the Board on October 28, 2011, effective as of that date.   

In addition, the Board adopted amendments to the SERP, the LTICP, and the Cleco Corporation Deferred Compensation Plan (Deferred Compensation Plan) effective October 28, 2011.  These amendments eliminate the business transaction benefit in the SERP and LTICP.  The SERP amendment also prospectively reduces the eligibility period during which change in control benefits can be triggered to conform to the period in the Executive Plan and eliminates the requirement that a participant also be a party to an employment agreement to receive change in control benefits.  The Deferred Compensation Plan amendment adds a definition of business transaction which previously was included only by reference to the LTICP.

67

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

ITEM 6.EXHIBITS

CLECO CORPORATION
3.1	Bylaws of Cleco Corporation, revised effective October 29, 2011
10.1	Cleco Corporation Executive Severance Plan, effective October 28, 2011
10.2	Cleco Corporation Supplemental Executive Retirement Plan Amendment, effective October 28, 2011
10.3	Summary of Director Compensation, Benefits and Policies, Last Revised on July 29, 2011
10.4	Cleco Corporation 2010 Long-Term Incentive Compensation Plan Amendment, effective October 28, 2011
10.5	Cleco Corporation Deferred Compensation Plan Amendment, effective October 28, 2011
10.6	First Amendment dated as of October 7, 2011 to the Credit Agreement dated as of November 23, 2010 among Cleco Corporation, various financial institutions, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of Cleco Corporation Form 8-K (file no. 001-15759), filed with the SEC on October 14, 2011)
12(a)	Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the three-, nine-, and twelve-month periods ended September 30, 2011, for Cleco Corporation
31.1	CEO Certification in accordance with section 302 of the Sarbanes-Oxley Act of 2002
31.2	CFO Certification in accordance with section 302 of the Sarbanes-Oxley Act of 2002
32.1	CEO Certification pursuant to section 906 of the Sarbanes-Oxley Act of 2002
32.2	CFO Certification pursuant to section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase
CLECO POWER
10.7	First Amendment dated as of October 7, 2011 to the Credit Agreement dated as of November 23, 2010 among Cleco Power LLC, various financial institutions, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 of Cleco Power LLC Form 8-K (file no. 001-05663), filed with the SEC on October 14, 2011)
12(b)	Computation of Ratios of Earnings to Fixed Charges for the three-, nine-, and twelve-month periods ended September 30, 2011, for Cleco Power
31.3	CEO Certification in accordance with section 302 of the Sarbanes-Oxley Act of 2002
31.4	CFO Certification in accordance with section 302 of the Sarbanes-Oxley Act of 2002
32.3	CEO Certification pursuant to section 906 of the Sarbanes-Oxley Act of 2002
32.4	CFO Certification pursuant to section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase
*XBRL information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.

68

CLECO CORPORATION
CLECO POWER	2011 3RD QUARTER FORM 10-Q

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the 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 - Investor Relations & Chief Accounting Officer

Date:  November 2, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, the 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 - Investor Relations & Chief Accounting Officer

Date:  November 2, 2011

69

EX-3.1

EXHIBIT 3.1

BYLAWS

OF

CLECO CORPORATION

(Revised effective October 29, 2011)

ARTICLE I	Registered Office; Registered Agents; Corporate Seal	1
Section 1.	Registered Office and Registered Agent(s)	1
Section 2.	Corporate Seal	1
ARTICLE II	Shareholders	1
Section 1.	Place of Holding Meetings	1
Section 2.	Quorum; Adjournment of Meetings	1
(a)	General Rule	1
(b)	Special Rule	1
(c)	Adjournments	2
Section 3.	Annual Meeting	2
Section 4.	Special Meeting	2
Section 5.	Conduct of Meetings	3
Section 6.	Voting	4
Section 7.	Notice	5
Section 8.	Amendment of Articles of Incorporation	8
(a)	Shareholders Proposals	8
(b)	Effectiveness	8
Section 9.	Effectiveness of Other Amendments to Articles of Incorporation	9
Section 10.	General	10
ARTICLE III	Directors	10
Section 1.	Certain General Provisions	10
(a)	Number	10
(b)	Classifications	10
(c)	Nominations	10
(d)	Qualifications; Declaration of Vacancy	12
(e)	Removal	13
(f)	Powers	14
(g)	Change in Number of Directors	15
(h)	Rights of Preferred Shareholders, etc.	15
Section 2.	Filling of Vacancies	15
Section 3.	Annual and Regular Meetings	15
Section 4.	Special Meetings	16
Section 5.	Place of Meetings; Telephone Meetings	16
Section 6.	Quorum	16
Section 7.	Compensation	16
Section 8.	Committees	16
ARTICLE IV	Indemnification	17
Section 1.	Right to Indemnification – General	17

Section 2.	Certain Provisions Respecting Indemnification for and Advancement of Expenses	17
Section 3.	Procedure for Determination of Entitlement to Indemnification	18
Section 4.	Presumptions and Effect of Certain Proceedings	19
Section 5.	Right of Claimant to Bring Suit	19
Section 6.	Non-Exclusivity and Survival of Rights	20
Section 7.	Definitions	21
ARTICLE V	Executive Committee	22
Section 1.	Election and Tenure	22
Section 2.	Executive Committee	22
Section 3.	Meetings	22
Section 4.	Compensation	22
ARTICLE VI	Audit Committee	22
Section 1.	Election and Tenure	22
Section 2.	Audit Committee	22
Section 3.	Meetings	23
Section 4.	Compensation	23
ARTICLE VII	Compensation Committee	23
Section 1.	Election and Tenure	23
Section 2.	Compensation Committee	23
Section 3.	Meetings	23
Section 4.	Compensation	23
ARTICLE VII.A.	Nominating/Governance Committee	24
Section 1.	Election and Tenure	24
Section 2.	Nominating/Governance Committee	24
Section 3.	Meetings	24
Section 4.	Compensation	24
ARTICLE VIII	Officers	24
Section 1.	Election, Tenure, and Compensation	24
Section 2.	Powers and Duties of Chairman of Board of Directors	25
Section 3.	Powers and Duties of President	25
Section 4.	Powers and Duties of Vice President	25
Section 5.	Powers and Duties of Secretary	25
Section 6.	Powers and Duties of Treasurer	25
Section 7.	Delegation of Duties	26

ii

ARTICLE IX	Capital Stock	26
Section 1.	Stock Certificates	26
Section 2.	Lost or Destroyed Certificates	26
Section 3.	Transfer of Shares	26
Section 4.	Dividends	27
Section 5.	Closing Transfer Books; Fixing Record Date	27
ARTICLE X	Fair-Price Provisions	27
Section 1.	Definitions	27
Section 2.	Vote Required in Business Combinations	30
Section 3.	When Voting Requirements Not Applicable	31
(a)	Definitions	31
(b)	Conditions	31
(c)	Other Provisions	34
ARTICLE XI	Notices	34
Section 1.	Manner of Giving Notice	34
Section 2.	Waiver of Notice	34
ARTICLE XII	Miscellaneous	35
Section 1.	Fiscal Year	35
Section 2.	Checks and Drafts	35
Section 3.	Books and Records	35
Section 4.	Separability	35
ARTICLE XIII	Amendment of Bylaws	35
Section 1.	Voting	35
Section 2.	Shareholder Proposals	35
Section 3.	Effective Date	36
ARTICLE XIV	Other Amendments to Bylaws	36
Section 1.	Effective Date	36
ARTICLE XV	Control Share Acquisition Statute	37
Section 1.		37

iii

BYLAWS

OF

CLECO CORPORATION

ARTICLE I

Registered Office; Registered Agents; Corporate Seal

Section 1.                      Registered Office and Registered Agent(s).  The registered office of the Corporation is 2030 Donahue Ferry Road, Pineville, Louisiana 71360-5226, and its registered agents are the president and chief executive officer of the Corporation, the general counsel, and the manager of insurance and claims of the Corporation, post office address 2030 Donahue Ferry Road, Pineville, Louisiana 71360-5226.  The Corporation may also have offices at such other places as the board of directors, the chief executive officer or the president may from time to time designate.

Section 2.                      Corporate Seal.  The corporate seal of the Corporation shall be circular in form and have inscribed on its periphery the words “Cleco Corporation 1999” and in its center the words “Corporate”, “Seal” and “Louisiana.”

ARTICLE II

Shareholders

Section 1.                       Place of Holding Meetings.  All meetings of the shareholders shall be held at the principal office of the Corporation in the City of Pineville, State of Louisiana, except in cases in which the notices thereof designate some other place, which may be within or without the State of Louisiana.

Section 2.                       Quorum; Adjournment of Meetings.

(a)           General Rule.  Except as otherwise provided in these bylaws, the presence in person or by proxy at a meeting of shareholders of the holders of record of a number of the shares of the capital stock of the Corporation issued and outstanding and entitled to vote thereat that represents a majority of the votes entitled to be cast thereat shall constitute a quorum at such meeting.

(b)           Special Rule.  At a meeting of shareholders at least one purpose of which is to amend or repeal a provision of or to supplement these bylaws or the articles of incorporation of the Corporation or to act on a merger, consolidation, reclassification, repurchase, or exchange of securities, transfer of all or substantially all of the assets of the Corporation, dissolution, “business combination” as defined in article X of these bylaws, or similar transaction, a quorum shall for all purposes consist of the presence in person or by proxy at such meeting of the holders of the number of the shares of the capital stock of the Corporation issued and outstanding and entitled to

1

vote thereat that represents 80% of the votes entitled to be cast thereat. At a meeting described in the preceding sentence, the quorum for any class of shares entitled to vote as a class shall be the holders of the number of shares of such class that represents 80% of the votes entitled to be cast by all holders of all shares of such class. Notwithstanding the foregoing, if the change in the articles of incorporation or bylaws, merger, consolidation, reclassification, repurchase, or exchange of securities, transfer of all or substantially all of the assets of the Corporation,  dissolution, “business combination” as defined in article X of these bylaws, or similar transaction in question shall have been approved, before submission of a proposal relating thereto to a vote of shareholders, by at least 80% of the “continuing directors” (hereinafter defined) of the Corporation, then, instead of subsection (b), subsection (a) of this section 2 shall determine the quorum at the meeting of shareholders at which such proposal is considered by shareholders.  For purposes of the preceding, a “continuing director” shall mean a director elected pursuant to a solicitation of proxies by the board of directors of the Corporation at an annual meeting of shareholders held at least 90 days before the date of determination and who has served continuously since such election, or a director elected by continuing directors to fill a vacancy.

(c)           Adjournments.  A meeting may, whether or not a quorum shall be in attendance at the time for which such meeting shall have been called and without any notice other than by announcement at such meeting, be adjourned from time to time by the chairman of the board of directors or the vote of the shareholders present in person or by proxy representing a majority of the votes so present, for a period not exceeding one month at any one time; provided, however, that a meeting at which a director or directors are to be elected shall be adjourned only from day to day until such director or directors have been elected.  At an adjourned meeting at which a quorum shall attend, any business may be transacted which might have been transacted if such meeting had been held as originally called.

Section 3.                      Annual Meeting.  Except as otherwise provided by resolution of the board of directors, the annual meeting of shareholders for the election of directors shall be held on the third Friday after the first Monday in April of each year.  At each annual meeting, the shareholders shall elect directors to succeed those whose terms have expired as of the date of such annual meeting.  Such other matters as may properly come before a meeting may be acted upon at an annual meeting.

Section 4.                      Special Meeting.

(a)           Special meetings of the shareholders for any purpose or purposes may be called by the chief executive officer or president, by a majority of the board of directors, or by a majority of the executive committee, if any, of the board of directors; provided, however, that if and whenever dividends payable on any series of the Corporation’s preferred stock shall be in default in an amount equal to the aggregate dividends payable in any period of 12 consecutive calendar months, a special meeting shall be called on the demand in writing of the holders of record of a majority of the outstanding shares of preferred stock; and, provided further, that a special meeting of shareholders may be called by a shareholder or shareholders as provided in the Corporation’s articles of incorporation, these bylaws, or otherwise by law.

(b)           Any shareholder requesting that a special meeting of shareholders be called (the

2

“Requesting Person”) shall, at the time of making the request, be a shareholder and submit written evidence, reasonably satisfactory to the secretary of the Corporation, that the Requesting Person is a shareholder of the Corporation and shall identify in writing (i) all information required to be included in a shareholder’s notice to bring business before a meeting of shareholders, as set forth in section 7(b)(3) of article II of these bylaws, and (ii) the reason or reasons for which the special meeting is to be called.  Within 15 days after the Requesting Person has submitted the aforesaid items to the secretary of the Corporation, the secretary of the Corporation shall determine whether the evidence of the Requesting Person’s status as a shareholder submitted by the Requesting Person is reasonably satisfactory and shall notify the Requesting Person in writing of his determination.  If the Requesting Person fails to submit the requisite information in the form or at the time indicated, or if the secretary of the Corporation fails to find such evidence of shareholder status reasonably satisfactory, then the request to call a special meeting of shareholders shall be deemed invalid (by reason of failure to comply with these bylaws) and no special meeting of shareholders shall be held pursuant to such request.  Nothing in this subsection (b) shall affect the rights of the Corporation’s shareholders as provided in section 3(b) of article 6 of the Corporation’s articles of incorporation or as provided in subsection (a) immediately preceding with respect to the rights of the Corporation’s preferred shareholders.

Section 5.                      Conduct of Meetings.  Meetings of shareholders shall be presided over by the chief executive officer or president of the Corporation or, if the chief executive officer or president is not present at a meeting, by such other person as the board of directors shall designate or, if no such person is designated by the board of directors, the most senior officer of the Corporation present at the meeting.  The secretary of the Corporation, if present, shall act as secretary of each meeting of shareholders; if he is not present at a meeting, then such person as may be designated by the presiding officer shall act as secretary of the meeting.  Meetings of shareholders shall follow reasonable and fair procedure.  Subject to the foregoing, the conduct of any meeting of shareholders and the determination of procedure and rules shall be within the absolute discretion of the presiding officer (the “Chairman of the Meeting”), and there shall be no appeal from any ruling of the Chairman of the Meeting with respect to procedure or rules.  Accordingly, in any meeting of shareholders or part thereof, the Chairman of the Meeting shall have the sole power to determine appropriate rules or to dispense with theretofore prevailing rules.  Without limiting the foregoing, the following rules shall apply:

(a)           The Chairman of the Meeting may ask or require that anyone not a bona fide shareholder or proxy leave the meeting.

(b)           A resolution or motion shall be considered for vote only if proposed by a shareholder or duly authorized proxy, and seconded by an individual, who is a shareholder or a duly authorized proxy, other than the individual who proposed the resolution or motion, subject to compliance with any other requirements concerning such a proposed resolution or motion contained in these bylaws.  The Chairman of the Meeting may propose any motion for vote.  The order of business at all meetings of shareholders shall be determined by the Chairman of the Meeting.

(c)           The Chairman of the Meeting may impose any reasonable limits with respect to participation in the meeting by shareholders, including, but not limited to, limits on the amount of

3

time at the meeting taken up by the remarks or questions of any shareholder, limits on the numbers of questions per shareholder, and limits as to the subject matter and timing of questions and remarks by shareholders.

(d)           Before any meetings of shareholders, the board of directors may appoint any persons other than nominees for office to act as inspectors of election at the meeting or its adjournment.  If no inspectors of election are so appointed, the Chairman of the Meeting may, and on the request of any shareholder or a shareholder’s proxy shall, appoint inspectors of election at the meeting of shareholders.  The number of inspectors shall be three.  If any person appointed as inspector fails to appear or fails or refuses to act, the Chairman of the Meeting may, and upon the request of any shareholder or a shareholder’s proxy shall, appoint a person to fill such vacancy.

The duties of these inspectors shall be as follows:

(1)           Determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, and the authenticity, validity and effect of proxies;

(2)           Receive votes or ballots;

(3)           Hear and determine all challenges and questions in any way arising in connection with the right to vote;

(4)           Count and tabulate all votes;

(5)           Report to the board of directors the results based on the information assembled by the inspectors; and

(6)Do any other acts that may be proper to conduct the election or vote with fairness to all shareholders.

Notwithstanding the foregoing, the final certification of the results of any election or other matter acted upon at a meeting of shareholders shall be made by the board of directors.

Section 6.                      Voting.  Except as otherwise provided by the articles of incorporation, each holder of shares of capital stock of the Corporation shall be entitled, at each meeting of shareholders, to one vote for each share of such stock standing in his name on the books of the corporation on the date of such meeting or, if the board of directors, pursuant to section 5 of article IX of these bylaws, shall have fixed a record date for the purpose of such meeting or shall have fixed a date as of which the books of the Corporation shall be temporarily closed against transfers of shares, then as of such date; except that in the election of directors of the Corporation, each holder of shares of common stock of the Corporation shall have the right to multiply the number of votes to which he may be entitled by the number of directors to be elected, and he may cast all such votes for one candidate or he may distribute them among any two or more candidates.  A shareholder may vote either in person or by proxy appointed by an instrument in writing, subscribed by such shareholder or by his duly authorized attorney.  Except as otherwise provided by law, the articles of incorporation, or these bylaws, all elections shall be had and all questions

4

shall be decided by a majority of the votes cast at a duly constituted meeting at which a quorum is present.

Section 7.                      Notice.

(a)           Unless otherwise provided by the articles of incorporation, written or printed notice, stating the place, day, and hour of each meeting of shareholders, and, in the case of a special meeting, the business proposed to be transacted thereat, shall be given in the manner provided in article XI of these bylaws to each shareholder entitled to vote at such meeting, at least 15 days before an annual meeting and at least five days before a special meeting.

(b)

(1)           Except as provided in subsection (c) of this section, to be properly brought before any meeting of the shareholders, business must be either (i) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the board of directors pursuant to subsection (a) of this section 7, (ii) otherwise properly brought before the meeting by or at the direction of the board of directors, or (iii) otherwise properly brought before the meeting by a shareholder who (A) is a shareholder at the time of the giving of such shareholder’s notice provided for in this section 7, (B) shall be a holder of record entitled to vote at the meeting and (C) complies with the requirements of this section 7.  Clause (iii) of the immediately preceding sentence shall be the exclusive means for a shareholder to submit business or proposals (other than matters properly brought under Rule 14a-8 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and included in the notice relating to the meeting (or any supplement thereto) given in accordance with subsection (a) of this section 7) before any meeting of shareholders.

(2)           In addition to any other applicable requirements, for business to be properly brought before any meeting by a shareholder, the shareholder must have given timely notice thereof in writing to the secretary of the Corporation.  To be timely, a shareholder’s notice must be delivered to or mailed and received at the principal executive offices of the Corporation at least 120 days prior to the meeting; provided, however, that in the event that less than 135 days’ notice or prior public disclosure of the date of any meeting of shareholders is given or made to shareholders by the Corporation, notice by the shareholder to be timely must be so received not later than the close of business of the 15th day following the day on which such notice of the date of the meeting was mailed or such public disclosure was made, whichever first occurs.  In no event shall any adjournment, postponement or deferral of a meeting of shareholders or the announcement thereof commence a new time period for the giving of a shareholder’s notice as described above.

(3)           Any such shareholder’s notice to the secretary of the Corporation shall set forth in writing as to each matter the shareholder proposes to bring before any meeting of the shareholders (i) a brief description of the business desired to be brought before the meeting and the reasons for conducting such business at the meeting, (ii) as to the shareholder proposing such business and the beneficial owner, if any, on whose behalf the proposal is made, (A) the name and record address of the shareholder proposing such business, as they appear on the Corporation’s books, and of the beneficial owner, if any,

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(B) the name and address of all other persons known by such shareholder and beneficial owner, if any, to be supporting such business (“Supporting Person”), (C) the class or series and number of shares of the Corporation which are, directly or indirectly, owned beneficially and of record by each of the shareholder, beneficial owner and Supporting Person, (D) any option, warrant, convertible security, stock appreciation right or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any class or series of shares of capital stock of the Corporation or with a value derived in whole or in part from the price, value or volatility of any class or series of shares of capital stock of the Corporation or any derivative or synthetic arrangement having characteristics of a long position in any class or series of shares of capital stock of the Corporation, whether or not such instrument or right shall be subject to settlement in the underlying class or series of capital stock of the Corporation or otherwise (a “Derivative Instrument”) directly or indirectly owned beneficially by such shareholder and by such beneficial owner and any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of shares of capital stock of the Corporation, (E) any proxy, contract, arrangement, understanding or relationship the effect or intent of which is to increase or decrease the voting power of such shareholder or beneficial owner with respect to any shares or any security of the Corporation, (F) any pledge by such shareholder or beneficial owner of any security of the Corporation or any short interest of such shareholder or beneficial owner in any security of the Corporation (a person shall be deemed to have a short interest in a security if such person directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has the opportunity to profit or share in any profit derived from any decrease in the value of the subject security), (G) any rights to dividends on the shares of capital stock of the Corporation owned beneficially by such shareholder and by such beneficial owner that are separated or separable from the underlying shares of capital stock of the Corporation, (H) any proportionate interest in shares of capital stock of the Corporation or Derivative Instruments held, directly or indirectly, by a general or limited partnership in which such shareholder or beneficial owner is a general partner or, directly or indirectly, beneficially owns an interest in a general partner, (I) any performance-related fees (other than an asset-based fee) that such shareholder or beneficial owner is entitled to based on any increase or decrease in the value of shares of capital stock of the Corporation or Derivative Instruments, if any, as of the date of such notice, including, without limitation, any such interests held by members of such shareholder’s or beneficial owner’s immediate family sharing the same household, (J) a representation regarding whether such shareholder or beneficial owner intends to solicit proxies with respect to the business desired to be brought before the meeting and (K) a representation regarding whether such shareholder or beneficial owner intends to appear in person or by proxy at the meeting, (iii) any other information relating to such shareholder and beneficial owner, if any, that would be required to be disclosed in solicitations of proxies for the proposal, or would otherwise be required, in each case pursuant to section 14 of the Exchange Act and the rules and regulations promulgated thereunder; (iv) any material interest of such shareholder, any such beneficial owner and any Supporting Person in such business or proposal and (v) a description of all agreements, arrangements and understandings between such shareholder and beneficial owner, if any, and any other person or persons (including their names) in connection with such business or proposal by such shareholder.  Beneficial ownership shall

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be determined in accordance with section 1 of article X of these bylaws.

(4)           A shareholder providing notice of business proposed to be brought before a meeting of shareholders shall further update and supplement such notice, if necessary, so that the information provided or required to be provided in such notice pursuant to subsection (b) of this section 7 shall be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting, including any adjournment or postponement thereof, and such update and supplement shall be delivered to, or mailed and received by, the secretary of the Corporation not later than five business days after the record date for the meeting (in the case of the update and supplement required to be made as of the record date), and not later than eight business days prior to the date for the meeting, if practicable (or, if not practicable, on the first practicable date prior to), including any adjournment or postponement thereof (in the case of the update and supplement required to be made as of ten business days prior to the meeting or any adjournment or postponement thereof).  In addition, a shareholder providing notice of business proposed to be brought before an annual meeting shall update and supplementsuch notice, and deliver such update and supplement to the principal executive offices of the Corporation, promptly following the occurrence of any event that materially changes the information provided or required to be provided in such notice pursuant to subsection (b) of this section 7.

(5)           Except as provided in subsection (c) of this section 7, notwithstanding anything in these bylaws to the contrary, no business shall be conducted at any meeting of the shareholders except in accordance with the procedures set forth in this section 7 of article II, provided, however, that nothing in this section 7 of article II shall be deemed to preclude discussion by any shareholder as to any business properly brought before any meeting of the shareholders.  In addition to the foregoing provisions of this section 7, a shareholder of the Corporation shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this section 7. Nothing in this section 7 shall be deemed to affect any rights of shareholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

(6)           The Chairman of the Meeting shall, if the facts warrant, determine and declare at any meeting of the shareholders that business was not properly brought before the meeting of shareholders in accordance with the provisions of this section 7 of article II, and if he should so determine, he shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted.  A determination whether a matter is or is not properly before the meeting shall not depend on whether such proposal has been or will be included in any proxy statement delivered or to be delivered to the Corporation’s shareholders.

(7)           Nothing in this subsection (b) shall affect the rights of holders of the Corporation’s preferred stock as provided in section 3(b) of article 6 of the Corporation’s articles of incorporation or as provided in subsection (a) of section 4 of article II of these bylaws with respect to the rights of the Corporation’s preferred shareholders.

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(c)           Nothing in subsection (b)(2) or (b)(6) of this section 7 shall apply to the following provisions of these bylaws or any proposal by a shareholder or shareholders with respect to any matter governed by and inconsistent with any of the following provisions:

Article II, section 8(a);

Article III, section 1(c);

Article III, section 1(e); and

Article XIII, section 2.

Section 8.                      Amendment of Articles of Incorporation.

(a)           Shareholder Proposals.  No proposal by a shareholder to amend or supplement the articles of incorporation of the Corporation shall be voted upon at a meeting of shareholders unless, at least 180 days before such meeting of shareholders, such shareholder shall have delivered in writing to the secretary of the Corporation (i) notice of such proposal, including all information required by section 7(b)(3) of article II of these bylaws, (ii) the text of such amendment or supplement and (iii) an opinion of counsel, which counsel and the form and substance of which opinion shall be reasonably satisfactory to the board of directors of the Corporation, to the effect that the articles of incorporation of the Corporation, as proposed to be so amended or supplemented, would not be in conflict with the laws of the State of Louisiana.  In no event shall any adjournment, postponement or deferral of a meeting of shareholders or the announcement thereof commence a new time period for the giving of a shareholder’s notice as described above.  Within 30 days after such shareholder shall have delivered the aforesaid items to the secretary of the Corporation, the secretary and the board of directors of the Corporation shall respectively determine whether the items to be ruled upon by them are reasonably satisfactory and shall notify such shareholder in writing of their respective determinations.  If such shareholder fails to submit a required item in the form or within the time indicated, or if the secretary or the board of directors of the Corporation determines that the items to be ruled upon by them are not reasonably satisfactory, then such proposal by such shareholder may not be voted upon by the shareholders of the Corporation at such meeting of shareholders.

(b)           Effectiveness.  No provision amending or supplementing, or purporting to amend or supplement, the articles of incorporation of the Corporation that would have an effect, direct or indirect, on any of the following items may be included in articles of amendment signed by any officer, agent or representative of the Corporation on behalf of the Corporation or delivered to the Secretary of State of Louisiana for filing of record until the later of (i) one year following the adoption by the shareholders of such amendment or supplement or (ii) 10 days after the adjournment sine die of the annual meeting of shareholders next succeeding the adoption by the shareholders of the Corporation of such amendment or supplement:

(1)           quorum at a regular or special meeting of shareholders;

(2)           procedures for amendment of the articles of incorporation or bylaws of the Corporation upon a proposal by a shareholder of the Corporation;

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(3)           the effective date of an amendment to the articles of incorporation or bylaws of the Corporation, or the time at which steps may be taken to effect an amendment to the articles of incorporation or bylaws of the Corporation; or

(4)           votes of shareholders of the Corporation required to approve (i) an amendment or supplement to or repeal of the bylaws of the Corporation, (ii) an amendment or supplement to the articles of incorporation of the Corporation, or (iii) a merger, consolidation, share exchange, reclassification of securities, repurchase of shares, transfer of all or substantially all of the assets of the Corporation, dissolution, “business combination” as defined in article X of these bylaws, or similar transaction.

Section 9.                      Effectiveness of Other Amendments to Articles of Incorporation.  No provision amending or supplementing, or purporting to amend or supplement, the articles of incorporation of the Corporation that would have an effect, direct or indirect, on any of the following items may be included in articles of amendment signed by any officer, agent or representative of the Corporation on behalf of the Corporation or delivered to the Secretary of State of Louisiana for filing of record until the later of (i) one year following the adoption by the shareholders of such amendment or supplement or (ii) 10 days after the adjournment sine die of the annual meeting of the shareholders next succeeding the adoption by the shareholders of the Corporation of such amendment or supplement:

(1)           the number of directors of the Corporation;

(2)           the classification of the board of directors of the Corporation into three classes of as nearly as possible equal size;

(3)           the procedures for nomination by a shareholder of persons to be elected as directors of the Corporation;

(4)           qualifications of directors of the Corporation or the declaration by the board of directors of a vacancy in the office of director;

(5)           removal of directors or officer of the Corporation;

(6)           power of directors of the Corporation;

(7)           the filling of vacancies on the board of directors of the Corporation and the election of directors to fill newly created directorships;

(8)           powers of committees of the board of directors of the Corporation;

(9)           the calling of special meetings of shareholders;

(10)           determinations of the presiding person at a meeting of shareholders;

or

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(11)           votes of shareholders of the Corporation required to approve the removal of a director.

Section 10.                    General.  As used in these bylaws, the term “shareholder” shall have the meaning given such term in Section 1 of the Louisiana Business Corporation Law.  As used in these bylaws, the terms “shares entitled to vote” and “votes entitled to be cast” shall mean (i) if a record date has been fixed for such meeting of shareholders, shares (or the votes related to such shares) of capital stock of the Corporation, which class or series of capital stock have the right to vote on such matter pursuant to the provisions of the articles of incorporation of the Corporation, outstanding as of the record date, or (ii) if a record date has not been fixed for such meeting of shareholders, shares (or the votes related to such shares) of capital stock of the Corporation, which class or series of capital stock have the right to vote on such matter pursuant to the provisions of the articles of incorporation of the Corporation, outstanding on the date of such meeting.

ARTICLE III

Directors

Section 1.                      Certain General Provisions.

(a)           Number.  The corporate powers of the Corporation shall be vested in and exercised, and the business and affairs of the Corporation shall be managed, by a board of directors which shall consist of ten (10) directors.

(b)           Classification.  The board of directors of the Corporation shall be divided into three classes of as nearly as possible equal size, with the term of office of directors of one class expiring each year.  At the 2000 annual meeting of shareholders, the Class III directors shall be elected to hold office for a term expiring at the third succeeding annual meeting.  At the 2001 annual meeting of shareholders, the Class I directors shall be elected to hold office for a term expiring at the third succeeding annual meeting.  At the 2002 annual meeting of shareholders, the Class II directors shall be elected to hold office for a term expiring at the third succeeding annual meeting.  Thereafter, at each annual meeting of shareholders, the successors to the class of directors whose terms shall have expired at such meeting shall be elected to hold office for a term expiring at the third annual meeting succeeding such meeting.

(c)           Nominations.  Nominations for election of members of the board of directors may be made by the board of directors or by a shareholder.  The name of a person to be nominated by a shareholder (a “Nominator”) as a member of the board of directors of the Corporation must be submitted in writing to the secretary of the Corporation not fewer than 180 days before the date of the meeting of shareholders at which such person is proposed to be nominated.  The Nominator shall also submit written evidence, reasonably satisfactory to the secretary of the Corporation, that the Nominator is a shareholder and shall identify in writing the information required by section 7(b)(3) of article II of these bylaws, except that all information required to be provided with respect to any shareholder or beneficial owner shall also be provided with respect to each proposed nominee.  At such time, the Nominator shall also submit in writing (1) to the extent not provided in the information submitted pursuant to this subsection (c), (x) description of all direct and indirect

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compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among the shareholder giving the notice and the beneficial owner, if any, on whose behalf the nomination is made, and their respective affiliates and associates, or others Acting in Concert (as defined below) therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others Acting in Concert therewith, on the other hand, including, without limitation, all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if such shareholder and such beneficial owner, or any affiliate or associate thereof or person Acting in Concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant, (y) the name, age, business address and residence address, business experience or other qualifications of each such proposed nominee, (z) the principal occupation or employment of each such proposed nominee and (2) a notarized affidavit executed by each such proposed nominee to the effect (x) that, if elected as a member of the board of directors, he will serve, (y) that he has reviewed the provisions of section 1 of this article III of these bylaws, and (z) that he is eligible for election as a member of the board of directors.  In no event shall any adjournment, postponement or deferral of a meeting of shareholders or the announcement thereof commence a new time period for the giving of a shareholder’s notice as described above.  Within 30 days after the Nominator has submitted the aforesaid items to the secretary of the Corporation, the secretary of the Corporation shall determine whether the evidence of the Nominator’s status as a shareholder submitted by the Nominator is reasonably satisfactory and shall notify the Nominator in writing of his determination with respect thereto. The failure of the secretary of the Corporation to find such evidence reasonably satisfactory, or the failure of the Nominator to submit the requisite information in the form or within the time indicated, shall make the person to be nominated ineligible for nomination at the meeting of shareholders at which such person is proposed to be nominated. Beneficial ownership shall be determined in accordance with section 1 of article X of these bylaws.

To be eligible to be a nominee for election or reelection as a director of the Corporation, a person must deliver (in accordance with the time periods prescribed for delivery of notice set forth above) to the secretary of the Corporation at the principal executive offices of the Corporation a written questionnaire with respect to the background and qualification of such person and the background of any other person or entity on whose behalf the nomination is being made (which questionnaire shall be in the form provided by the secretary upon written request) and a written representation and agreement (in the form provided by the secretary upon written request) that such person (A) is not and will not become a party to (1) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a director of the Corporation, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to the Corporation or (2) any Voting Commitment that could limit or interfere with such person’s ability to comply, if elected as a director of the Corporation, with such person’s fiduciary duties under applicable law, (B) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than the Corporation with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed therein, and (C) in such person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director of the Corporation, and will comply with all applicable publicly disclosed corporate

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governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines of the Corporation.

           A person shall be deemed to be “Acting in Concert” with another person for purposes of these bylaws if such person knowingly acts (whether or not pursuant to an express agreement, arrangement or understanding) in concert with, or towards a common goal relating to the management, governance or control of the Corporation in parallel with, such other person where (A) each person is conscious of the other person’s conduct or intent and this awareness is an element in their decision-making processes and (B) at least one additional factor suggests that such persons intend to act in concert or in parallel, which such additional factors may include, without limitation,exchanging information (whether publicly or privately), attending meetings, conducting discussions, or making or soliciting invitations to act in concert or in parallel; provided, that a person shall not be deemed to be Acting in Concert with any other person solely as a result of the solicitation or receipt of revocable proxies or consents from such other person in response to a solicitation made pursuant to, and in accordance with, Section 14(a) of the Exchange Act by way of a proxy or consent solicitation statement filed on Schedule 14A.  A person Acting in Concert with another person shall be deemed to be Acting in Concert with any third party who is also Acting in Concert with such other person.

(d)           Qualifications; Declaration of Vacancy.

(1)           No person shall be eligible for election or reelection as a director after attaining age 72, and no person who is or shall have been a full-time officer or employee of the Corporation or any subsidiary thereof shall be eligible for election or reelection as a director after attaining age 65 or (even if under 65) after such director’s employment by the Corporation has terminated.

(2)           Upon attaining the age of 72 or 65, as specified in paragraph (1) immediately preceding, a director may continue to serve as a director of the Corporation until no later than the next succeeding annual meeting of shareholders, at which time, unless he has previously ceased to be a member of the board of directors of the Corporation, his position as a director shall cease.  Notwithstanding the foregoing, with regard to a director of the Corporation who is also an officer or employee of the Corporation or any subsidiary thereof, such director’s position as a director shall cease immediately upon termination of such director's employment by the Corporation.

(3)           No person shall be eligible for election or reelection or to continue to serve as a member of the board of directors who is an officer, director, agent, representative, partner, employee, or nominee of, or otherwise acting at the direction of, or Acting in Concert with, (y) a “public utility company” (other than one that is an “affiliate” of the Corporation) or “holding company” (other than one that is an “affiliate” of the Corporation) as such terms are defined in the Public Utility Holding Company Act of 1935, as amended, or “public utility” (other than one that is an “affiliate” (as defined in 18 C.F.R. §161.2) of the Corporation) as such term is defined in Section 201(e) of the Federal Power Act of 1920, as amended, or (z) an “affiliate” (as defined in 17 C.F.R. § 230.405) under the Securities Act of 1933, as amended) of any of the persons or entities specified in clause (y)

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immediately preceding.

(4)           Upon the occurrence of any of the events described in paragraph (2) of this subsection (d), the affected director shall cease to be a director of the Corporation at the time specified in such paragraph.  Determination of the eligibility of a person for election, reelection, or continued service on the board of directors under other provisions of this subsection (d) or otherwise as provided by applicable law including, but not limited to, occurrence of an event specified in Section 81.C(2) of the Louisiana Business Corporation Law, shall, subject to the provisions of paragraph (6) below, be made by vote of a majority of the members of the board of directors.  If the board of directors, pursuant to such a determination, determines that a person is ineligible for election, reelection, or continued service on the board of directors, such ineligibility shall be effective immediately upon such determination, and, if the affected person is a director of the Corporation at the time of such determination, his position as a director shall cease at such time.

Within 30 days after a Nominator has submitted the name of a person to be nominated as a member of the board of directors, the board of directors shall determine whether the proposed nominee is eligible for election under this subsection (d) and shall notify the Nominator in writing of its determination.  If the board of directors shall determine that such proposed nominee is not eligible for election, such person shall be ineligible to be nominated at the meeting of shareholders for which his nomination was proposed.

(5)           If a director of the Corporation ceases to be a director (x) at the annual meeting of shareholders next succeeding the day upon which he attained the age of 72 or 65, as specified in paragraphs (1), (2), and (4) of this subsection (d), and if there is time remaining in the regularly scheduled term of office of such director, (y) because of termination of employment, as provided in paragraphs (1), (2), and (4) of this subsection (d), or (z) upon the determination of the board of directors of the Corporation pursuant to paragraph (4) of this subsection (d) that a director of the Corporation is no longer qualified to continue serving as a director of the Corporation, the board of directors shall declare the office held by such director vacant and may fill such vacancy as provided in section 2 of this article III of these bylaws.

(6)           Without limiting the ability of the board of directors as provided by applicable law to declare vacant the position of a director on the board of directors, if a member of the board of directors has been adjudged by a court of competent jurisdiction to be guilty of fraud, criminal conduct (other than minor traffic violations), gross abuse of office amounting to a breach of trust, or similar misconduct, and no appeal (or further appeal) therefrom is permitted under applicable law, the other directors then in office, by unanimous vote, may declare the position occupied by such director vacant, and such other directors may fill such vacancy as provided in section 2 of this article III of these bylaws.

(e)           Removal.  In this subsection (e), the terms “remove” and “removal” and their related grammatical forms shall refer only to the process of dismissal provided for in this subsection, and shall not be deemed to refer to disqualification of a director, cessation of a director

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to be such, or declaration of a vacancy in the office of director as provided for in subsection (d) of this section 1 or otherwise as permitted by law.

A member of the board of directors may be removed by the shareholders of the Corporation only for cause.  Any such removal for cause shall be at a special meeting of shareholders called for such purpose.  The vote of the holders of shares conferring 80% of the total votes of all shares of capital stock of the Corporation voting as a single class shall be necessary to remove a director; provided, however, that if a director has been elected by the exercise of the privilege of cumulative voting, such director may not be removed if the votes cast against his removal would be sufficient to elect him if then cumulatively voted at an election of the class of directors of which he is a part.  For purposes of this subsection (e), cause for removal shall exist only if a director shall have been adjudged by a court of competent jurisdiction to be guilty of fraud, criminal conduct (other than minor traffic violations), gross abuse of office amounting to a breach of trust, or similar misconduct, and no appeal (or further appeal) therefrom shall be permitted under applicable law.

No proposal by a shareholder to remove a director of the Corporation shall be voted upon at a meeting of shareholders unless, at least 180 days before such meeting, such shareholder shall have delivered in writing to the secretary of the Corporation (1) notice of such proposal, including all information required by section 7(b)(3) of article II of these bylaws, (2) a statement of the grounds on which such director is proposed to be removed and (3) an opinion of counsel, which counsel and the form and substance of which opinion shall be reasonably satisfactory to the board of directors of the Corporation (excluding the director proposed to be removed), to the effect that, if adopted at a duly called special meeting of the shareholders of the Corporation by the vote of the holders of shares conferring 80% of the total votes of all shares of the capital stock of the Corporation voting as single class, such removal would not be in conflict with the laws of the State of Louisiana, the articles of incorporation of the Corporation, or these bylaws.  In no event shall any adjournment, postponement or deferral of a special meeting of shareholders or the announcement thereof commence a new time period for the giving of a shareholder’s notice as described above.  Within 30 days after such shareholder shall have delivered the aforesaid items to the secretary of the Corporation, the secretary and the board of directors of the Corporation shall respectively determine whether the items to be ruled upon by them are reasonably satisfactory and shall notify such shareholder in writing of their respective determinations.  If such shareholder fails to submit a required item in the form or within the time indicated, or if the secretary or the board of directors of the Corporation determines that the items to be ruled upon by them, respectively, as provided above are not reasonably satisfactory, then such proposal by such shareholder may not be voted upon by the shareholders of the Corporation at such meeting of shareholders.

(f)           Powers.  Subject to the provisions of the laws of the State of Louisiana, the articles of incorporation of the Corporation, and these bylaws, the board of directors shall have and exercise, in addition to such powers as are set forth in the articles of incorporation, all of the powers which may be exercised by the Corporation, including, but without thereby limiting the generality of the above, the power to create and to delegate, with power to subdelegate, any of its powers to any committee, officer, or agent; provided, however, that the board of directors shall not have the power to delegate its authority to:

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(1)           amend, repeal, or supplement the bylaws of the Corporation;

(2)           take definitive action on a merger, consolidation, reclassification or exchange of securities, repurchase by the Corporation of any of its equity securities, transfer of all or substantially all of the assets of the Corporation, dissolution, "business combination" as defined in article X of these bylaws, or similar action;

(3)           elect or remove a director or officer of the Corporation;

(4)           submit a proposal to shareholders for action by shareholders;

(5)           appoint a director to or remove a director from a committee of the board of directors; or

(6)           declare a dividend on the capital stock of the Corporation.

(g)           Change in Number of Directors. No amendment or supplement to or repeal of subsection (a) of section 1 of article III of these bylaws that would have the effect of increasing the number of authorized directors of the Corporation by more than two during any 12-month period shall be permitted unless at least 80% of the “continuing directors” then in office (as defined in subsection (b) of section 2 of article II of these bylaws) shall authorize such action.  If the number of directorships is changed for any reason, any increase or decrease in the number of directorships shall be apportioned among the classes so as to make all classes as nearly equal in number as possible.

(h)           Rights of Preferred Shareholders, etc.  Nothing in this section 1 of this article III of these bylaws shall affect the rights of the Corporation's shareholders as provided in section 3(b) of article 6 of the Corporation's articles of incorporation.

Section 2.                      Filling of Vacancies.  Except to the extent required by law or section 3(b) of article 6 of the articles of incorporation of the Corporation, newly created directorships resulting from any increase in the authorized number of directors and any vacancies in the board of directors resulting from the attainment by a director of the age of 72 or 65, as specified in paragraphs (1), (2), (4), and (5) of subsection (d) of section 1 of this article III, or from death, resignation, disqualification or removal of a director, or from failure of the shareholders to elect the full number of authorized directors, or from any other cause shall be filled by the affirmative vote of at least a majority of the remaining directors (or director) then in office, even though less than a quorum of the whole board.  Any director elected in accordance with the preceding sentence shall hold office for the remainder of the full term of the class of directors in which the new directorship was created or the vacancy occurred.  Except to the extent required by law or section 3(b) of article 6 of the articles of incorporation of the Corporation, the shareholders shall have no right to fill any vacancies in the board of directors.

Section 3.                      Annual and Regular Meetings.  Within 45 days after each annual meeting of shareholders, and if possible on the date of each annual meeting of shareholders immediately

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following each such meeting, the board of directors shall hold an annual meeting for the purpose of electing officers and transacting other corporate business.  Such meeting shall be called in the manner for calling regular or special meetings of the board of directors.

Except as otherwise provided by resolution of the board of directors, other regular meetings of the board of directors shall be held on the last Friday in January, July and October at such places as the chief executive officer or president may direct in the notices of such meetings. At least five days’ notice by mail or written telecommunication shall be given to each director of the time and place of holding each regular meeting of the board of directors.

Section 4.                      Special Meetings.  A special meeting of the board of directors may be called by the chief executive officer or president, to be held at such place as he may direct in the notice of such meeting, on four days’ notice by mail or three days’ notice by written telecommunication, to each director.  A special meeting shall be called by the chief executive officer or president in like manner on the written request of at least 50% of the members of the board.

Section 5.                      Place of Meetings; Telephone Meetings. A meeting of the board of directors may be held either within or without the State of Louisiana.  The time and place of holding a regular or special meeting of the board of directors may be changed and another place and time fixed for such regular or special meeting by a majority of the members of the board.

The members of the board of directors, and a committee thereof, may participate in and hold a meeting of the board or of such committee by means of conference telephone or similar communications equipment provided that all persons participating in such meeting can hear and communicate with one another.  Participation in a meeting pursuant to this provision shall constitute presence in person at such meeting, except where a person participates in such meeting for the express purpose of objecting to the transaction of any business on the grounds that such meeting was not lawfully called or convened.

Section 6.                      Quorum. A majority of the directors shall constitute a quorum, but a smaller number may adjourn a meeting from time to time without further notice until a quorum is secured.  If a quorum is present, the directors present can continue to do business until adjournment notwithstanding the subsequent withdrawal of enough directors to leave less than a quorum or the refusal of any director present to vote.

Section 7.                      Compensation.  Each director shall be entitled to receive from the Corporation reimbursement of his expenses incurred in attending any regular or special meeting of the board and, by resolution of the board, such other compensation as it may approve.  Such reimbursement and compensation shall be payable whether or not an adjournment be had because of the absence of a quorum.  Nothing herein contained shall be construed to preclude any director from serving the Corporation in another capacity and receiving compensation therefor.

Section 8.                      Committees.  From time to time, the board of directors may appoint, from its own number, in addition to the committees provided for in these bylaws, such other committee or committees for such purpose or purposes as it shall determine. Subject to the limitations imposed by these bylaws, the articles of incorporation, and the laws of the State of Louisiana, each

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committee of the board of directors shall have such powers as shall be specified in the resolution of appointment.

ARTICLE IV

Indemnification

Section 1.                      Right to Indemnification - General.  The Corporation shall indemnify any person who was or is, or is threatened to be made, a party to or otherwise involved in any pending or completed action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or other proceeding, whether civil, criminal, administrative or investigative (any such threatened, pending or completed proceeding being hereinafter called a “Proceeding”) by reason of the fact that he is or was a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of another business, foreign or nonprofit corporation, partnership, joint venture, trust, employee benefit plan or other enterprise (whether the basis of his involvement in such Proceeding is alleged action in an official capacity or in any other capacity while serving as such), to the fullest extent permitted by applicable law in effect from time to time, and to such greater extent as applicable law may from time to time permit, from and against expenses, including attorney’s fees, judgments, fines, amounts paid or to be paid in settlement, liability and loss, ERISA excise taxes, actually and reasonably incurred by him or on his behalf or suffered in connection with such Proceeding or any claim, issue or matter therein; provided, however, that, except as provided in section 5 of this article, the Corporation shall indemnify any such person claiming indemnity in connection with a Proceeding initiated by such person only if such Proceeding was authorized by the board of directors.

           Section 2.                              Certain Provisions Respecting Indemnification for and Advancement of Expenses.

(a)           To the extent that a person referred to in section 1 of this article is required to serve as a witness in any Proceeding referred to therein, he shall be indemnified against all Expenses (as hereinafter defined) actually and reasonably incurred by him or on his behalf in connection with serving as a witness.

(b)           The Corporation shall from time to time pay, in advance of final disposition, all Expenses incurred by or on behalf of any person referred to in section 1 of this article claiming indemnity thereunder in respect of any Proceeding referred to therein.  Each such advance shall be made within ten days after the receipt by the Corporation of a statement from the claimant requesting the advance, which statement shall reasonably evidence the relevant Expenses and be accompanied or preceded by any such undertaking as may be required by applicable law respecting the contingent repayment of such Expenses.  Whenever and to the extent applicable law requires the board of directors to act in the specific case with respect to the payment of Expenses in advance of the final disposition of any Proceeding, the board of directors shall act with respect thereto within the period specified in the preceding sentence and shall withhold the payment of Expenses in advance only if there is a reasonable and prompt determination by the board of directors by a majority vote of a quorum of Disinterested Directors (as hereinafter defined), or (if

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such quorum is not obtainable or, even if obtainable, a quorum of Disinterested Directors so directs) by Independent Counsel (as hereinafter defined) in a written opinion, that advancement  of Expenses is inappropriate, even taking into account any undertaking given with respect to the repayment of such Expenses, because based on the facts then known there is no reasonable likelihood that the claimant would be able ultimately to demonstrate that he met the standard of conduct necessary for indemnification with respect to such Expenses.

Section 3.                      Procedure for Determination of Entitlement to Indemnification.

(a)           To obtain indemnification under this article, a claimant shall submit to the Corporation a written application. The secretary of the Corporation shall, promptly upon receipt of such an application for indemnification, advise the board of directors in writing of the application. In connection with any such application, the claimant shall provide such documentation and information as is reasonably requested by the Corporation and reasonably available to him and relevant to a determination of entitlement to indemnification.

(b)           A person’s entitlement to indemnification under this article, unless ordered by a court, shall be determined, as required or permitted by applicable law: (i) by the board of directors by a majority vote of a quorum consisting of Disinterested Directors, (ii) if a quorum of the board of directors consisting of Disinterested Directors is not obtainable or, even if obtainable, a quorum of Disinterested Directors so directs, by Independent Counsel in a written opinion, or (iii) by the shareholders of the Corporation; provided, however, that if a Change of Control (as hereinafter defined) shall have occurred, no determination of entitlement to indemnification adverse to the claimant shall be made other than one made or concurred in by Independent Counsel, selected as provided in paragraph (d) of this section, in a written opinion.

(c)           If the determination of entitlement to indemnification is to be made by Independent Counsel in the absence of a Change of Control, the Corporation shall furnish notice to the claimant within ten days after receipt of the application for indemnification specifying the identity and address of Independent Counsel.  The claimant may, within fourteen days after receipt of such written notice of selection, deliver to the Corporation a written objection to such selection, subject to paragraph (e) of this section.  If such an objection is made, either the Corporation or the claimant may petition any court of competent jurisdiction for a determination that the objection has no reasonable basis or for the appointment as Independent Counsel of counsel selected by the court.

(d)           If there has been a Change of Control, Independent Counsel to act as and to the extent required by paragraph (b) of this section or paragraph (b) of section 2 shall be selected by the claimant, who shall give the Corporation written notice advising of the identity and address of the Independent Counsel so selected.  The Corporation may, within seven days after receipt of such written notice of selection, deliver to the claimant a written objection to such selection, subject to paragraph (e) of this section.  The claimant may, within five days after the receipt of such objection, select other counsel to act as Independent Counsel, and the Corporation may, within seven days after receipt of such written notice of selection, deliver to the claimant a written objection, as aforesaid, to such second selection.  In the case of any such objection the claimant may petition any court of competent jurisdiction for a determination that the objection has no

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reasonable basis or for the appointment as Independent Counsel of counsel selected by the court.

(e)Any objection to the selection of Independent Counsel may be asserted only on the ground that the counsel so selected does not qualify as Independent Counsel under the definition contained in section 7 of this article, and the objection shall set forth with particularity the basis of such assertion.  No counsel selected by the Corporation or by the claimant may serve as Independent Counsel if a timely objection has been made to his selection unless a court has determined that such objection has no reasonable basis.

(f)The Corporation shall pay any and all reasonable fees and expenses of Independent Counsel acting pursuant to this article and in any proceeding in which such counsel is a party or a witness in respect of its investigation and report.  The Corporation shall pay all reasonable fees and expenses incident to the procedures of this section regardless of the manner in which Independent Counsel is selected or appointed.

Section 4.                      Presumptions and Effect of Certain Proceedings.

(a)           A person referred to in section 1 of this article claiming a right to indemnification under this article shall be presumed (except as may be otherwise expressly provided in this article or required by applicable law) to be entitled to such indemnification upon submission of an application for indemnification in accordance with section 3, and the Corporation shall have the burden of proof to overcome the presumption in any determination contrary to the presumption.

(b)           Unless the determination is to be made by Independent Counsel, if the person or persons empowered under section 3 of this article to determine entitlement to indemnification shall not have made and furnished the determination in writing to the claimant within 60 days after receipt by the Corporation of the application for indemnification, the determination of entitlement to indemnification shall be deemed to have been made in favor of the claimant unless the claimant knowingly misrepresented a material fact in connection with the application or such indemnification is prohibited by law. The termination of any Proceeding, or of any claim, issue or matter therein, by judgment, order, settlement or conviction, or upon a plea of nolo contender or its equivalent, shall not of itself adversely affect the right of a claimant to indemnification or create a presumption that a claimant did not act in a manner which would deny him the right to indemnification.

Section 5.                      Right of Claimant to Bring Suit.

(a)           If (i) a determination is made pursuant to the procedures contemplated by section 3 of this article that a claimant is not entitled to indemnification under this article, (ii)  advancement of Expenses is not timely made pursuant to paragraph (b) of section 2 of this article, (iii) Independent Counsel has not made and delivered a written opinion as to entitlement to indemnification within 90 days after the selection or appointment of counsel has become final by virtue of the lapse of time for objection or the overruling of objections or appointment of counsel by a court, or (iv) payment of a claim for indemnification is not made within five days after a favorable determination of entitlement to indemnification has been made or deemed to have been made pursuant to section 3 or 4 of this article, the claimant shall be entitled to bring suit against the

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Corporation to establish his entitlement to such indemnification or advancement of Expenses and to recover the unpaid amount of his claim. It shall be a defense to any such action (other than an action brought to enforce a claim for Expenses incurred in defending any Proceeding in  advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation) that the claimant did not meet the applicable standard of conduct which makes it permissible for the Corporation to indemnify the claimant for the amount claimed, but the burden of proving such defense shall be upon the Corporation.  Neither the failure of the Corporation (including its board of directors, Independent Counsel or its shareholders) to have made a determination before the commencement of such action that indemnification of the claimant is proper under the circumstances because he has met such applicable standard of conduct, nor an actual determination by the Corporation (including its board of directors, Independent Counsel or its shareholders) that the claimant has not met the applicable standard of conduct, shall be a defense to the action or create a presumption that the claimant has not met the applicable standard of conduct, and the claimant shall be entitled to a de novo trial on the merits as to any such matter as to which no determination or an adverse determination has been made.

(b)           If a claimant is successful in whole or in part in prosecuting any claim referred to in paragraph (a) of this section, the claimant shall also be entitled to recover from the Corporation, and shall be indemnified by the Corporation against, any and all Expenses actually and reasonably incurred by him in prosecuting such claim.

Section 6.                      Non-Exclusivity and Survival of Rights.  The rights of indemnification and to receive advancement of Expenses contemplated by this article shall not be deemed exclusive of any other rights to which any person may at any time be entitled under any bylaw, agreement, authorization of shareholders or directors (regardless of whether directors authorizing such indemnification are beneficiaries thereof), or otherwise, both as to action in his official capacity and as to action in another capacity; provided that no other indemnification measure shall permit indemnification of any person for the results of such person's willful or intentional misconduct.

The Corporation may procure or maintain insurance or other similar arrangement, at its expense, to protect itself and any director, officer, employee or agent of the Corporation or other corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss asserted against or incurred by such person, whether or not the Corporation would have the power to indemnify such person against such expense or liability.

In considering the cost and availability of such insurance, the Corporation, in the exercise of its business judgment, may purchase insurance which provides for any and all of (i) deductibles, (ii) limits on payments required to be made by the insurer, or (iii) coverage which may not be as comprehensive as that previously included in insurance purchased by the Corporation. The purchase of insurance with deductibles, limits on payments and coverage exclusions will be deemed to be in the best interest of the Corporation but may not be in the best interest of certain of the persons covered thereby.  As to the Corporation, purchasing insurance with deductibles, limits on payments, and coverage exclusions is similar to the Corporation’s practice of self-insurance in other areas.  In order to protect the officers and directors of the Corporation, the Corporation shall indemnify and hold each of them harmless as provided in section 1 of this article IV, without regard to whether the Corporation would otherwise be entitled to indemnify such officer or

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director under the other provisions of this article IV, to the extent  (i) of such deductibles, (ii) of amounts exceeding payments required to be made by an insurer or (iii) that prior policies of officers and directors liability insurance held by the Corporation would have provided for payment to such officer or director.  Notwithstanding the foregoing provisions of this section 6, no person shall be entitled to indemnification for the results of such person's willful or intentional misconduct.

The right to indemnification conferred in this article shall be a contract right, and no amendment, alteration or repeal of this article or any provision thereof shall restrict the indemnification rights granted by this article as to any person claiming indemnification with respect to acts, events and circumstances that occurred, in whole or in part, before such amendment, alteration or repeal.  The provisions of this article shall continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of his heirs, executors and legal representatives.

Section 7.                      Definitions. For purposes of this article:

(a)           “Change of Control” means the occurrence of any of the following events or circumstances: (1) there shall have occurred an event required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A (or in response to any similar item on any similar schedule or form) promulgated under the Exchange Act, whether or not the Corporation is then subject to such reporting requirement; (2) (i) any “person” (as such term is used in Section 13(d) and 14(d) of the Exchange Act) shall have become the “beneficial owner”, (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation representing 30% or more of the combined voting power of the Corporation’s then outstanding voting securities without the prior approval of at least two-thirds of the members of the board of directors in office immediately before such person’s attaining such percentage interest; (3) the Corporation is a party to a merger, consolidation, sale of assets or other reorganization, or the subject of a proxy contest, as a consequence of which members of the board of directors in office immediately before such transaction or event constitute less than a majority of the board of directors thereafter; (4) during any period of two consecutive years, individuals who at the beginning of such period constituted the board of directors (including for this purpose any new director whose election or nomination for election by the Corporation’s shareholders was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period) cease for any reason to constitute at least a majority of the board of directors.

(b)           “Disinterested Director” means a director of the Corporation who is not and was not a party to the Proceeding in respect of which indemnification is sought as provided in this article.

(c)           “Expenses” shall include all reasonable attorneys’ fees, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, and all other disbursements or expenses of the types customarily incurred in connection with prosecuting, defending, preparing to prosecute or defend, investigating, or being or preparing to be a witness in a Proceeding.

(d)           “Independent Counsel” means a law firm, or a member of a law firm, with

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substantial experience in matters of corporation law that neither presently is, nor in the five years before his selection or appointment has been, retained to represent: (i) the Corporation or person claiming indemnification in any matter material to either, or (ii) any other party to the Proceeding giving rise to a claim for indemnification hereunder, and is not otherwise precluded under applicable professional standards from acting in the capacity herein contemplated.

ARTICLE V

Executive Committee

Section 1.                      Election and Tenure.  The board of directors may appoint an executive committee consisting of such number of directors as it may appoint, to serve at the pleasure of the board of directors, but in any event not beyond the next annual meeting of the board of directors.  The board may at any time, without notice, remove and replace any member of the executive committee.

Section 2.                      Executive Committee.  Subject to the provisions of subsection (f) of section 1 of article III of these bylaws, the executive committee shall have a charter that will be approved, and revised as appropriate, from time to time by the committee and the board.  In general terms, the functions of the committee shall be those as set forth in the charter.

Section 3.                      Meetings.  The executive committee shall meet at stated times or on notice to all by one of its number, in which notice the time and place of the meeting shall be set forth.  The executive committee shall fix its own rules of procedure, and a majority shall constitute a quorum; but the affirmative vote of a majority of the whole committee shall be necessary in every case.  The executive committee shall keep regular minutes of its proceedings and report the same to the board of directors.

Section 4.                      Compensation.  Members of the executive committee, other than officers of the Corporation, shall receive such compensation for their services as shall be prescribed by the board of directors.  Each member of the executive committee shall be entitled to receive from the Corporation reimbursement of his expenses incurred in attending a meeting of such committee.

ARTICLE VI

Audit Committee

Section 1.                      Election and Tenure.  The board of directors may appoint an audit committee, consisting of such number of directors as it may appoint, to serve at the pleasure of the board of directors, but in any event not beyond the next annual meeting of the board of directors.  The board may at any time, without notice, remove and replace any member of the audit committee.

Section 2.                      Audit Committee.  Subject to the provisions of subsection (f) of section 1 of article III of these bylaws, the audit committee shall have a charter that will be approved, and revised as appropriate, from time to time by the committee and the board.  In general terms, the

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functions of the committee shall be those as set forth in the charter.

Section 3.                      Meetings.  The audit committee shall meet at stated times or on notice to all by one of its number, in which notice the time and place of the meeting shall be set forth.  The audit committee shall fix its own rules of procedure, and a majority shall constitute a quorum; but the affirmative vote of a majority of the whole committee shall be necessary in every case.  The audit committee shall keep regular minutes of its proceedings and report the same to the board of directors.

Section 4.                      Compensation.  Members of the audit committee, other than officers of the Corporation, shall receive such compensation for their services as shall be prescribed by the board of directors.  Each member of the audit committee shall be entitled to receive from the Corporation reimbursement of his expenses incurred in attending a meeting of the audit committee.

ARTICLE VII

Compensation Committee

Section 1.                      Election and Tenure.  The board of directors may appoint a compensation committee, consisting of such number of directors as it may appoint, to serve at the pleasure of the board of directors, but in any event not beyond the next annual meeting of the board of directors. The board may at any time, without notice, remove and replace any member of the compensation committee.

Section 2.                      Compensation Committee.  Subject to the provisions of subsection (f) of section 1 of article III of these bylaws, the compensation committee shall have a charter that will be approved, and revised as appropriate, from time to time by the committee and the board.  In general terms, the functions of the committee shall be those as set forth in the charter.

Section 3.                      Meetings.  The compensation committee shall meet at stated times or on notice to all by one of its number, in which notice the time and place of the meeting shall be set forth. The compensation committee shall fix its own rules of procedure, and a majority shall constitute a quorum; but the affirmative vote of the majority of the whole committee shall be necessary in every case. The compensation committee shall keep regular minutes of its proceedings and report the same to the board of directors.

Section 4.                      Compensation.  Members of the compensation committee, other than officers of the Corporation, shall receive such compensation for their services as shall be prescribed by the board of directors.  Each member of the compensation committee shall be entitled to receive from the Corporation reimbursement of his expenses incurred in attending a meeting of the compensation committee.

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Article VII.A.

Nominating/Governance Committee

Section 1.                      Election and Tenure.  The board of directors may appoint a nominating/governance committee consisting of such number of directors as it may appoint, to serve at the pleasure of the board of directors, but in any event not beyond the next annual meeting of the board of directors.  The board may at anytime, without notice remove and replace any member of the nominating/governance committee.

Section 2.                      Nominating/Governance Committee.  Subject to the provisions of subsection (f) of section 1 of article III of these bylaws, the nominating/governance committee shall have a charter that will be approved, and revised as appropriate, from time to time by the committee and the board.  In general terms, the functions of the committee shall be those as set forth in the charter.

Section 3.                      Meetings.  The nominating/governance committee shall meet at stated times or on notice to all by one of its number, in which notice the time and place of the meeting shall be set forth.  The nominating/governance committee shall fix its own rules of procedure, and a majority shall constitute a quorum; but the affirmative vote of a majority of the whole committee shall be necessary in every case.  The nominating/governance committee shall keep regular minutes of its proceedings and report the same to the board of directors.

Section 4.                      Compensation.  Members of the nominating/governance committee, other than officers of the Corporation, shall receive such compensation for their services as shall be prescribed by the board of directors.  Each member of the nominating/governance committee shall be entitled to receive from the Corporation reimbursement of his expenses incurred in attending a meeting of such committee.

ARTICLE VIII

Officers

Section l.                       Election, Tenure, and Compensation.  The officers of the Corporation shall consist of a president, one or more vice presidents, a secretary, a treasurer, and such other officers, including a chairman of the board of directors, as may from time to time be elected or appointed by the board of directors. Officers of the Corporation shall be elected annually by the board of directors as provided in section 3 of article III of these bylaws.  If such annual election is not held, the officers then in office shall remain as such until their respective successors shall be elected and qualify.  No officer, except the chairman of the board of directors, need be a director, and any two or more offices, except the offices of president and vice president, may be held by one person.  The powers of all officers of the Corporation shall be subject to the provisions of subsection (f) of section 1 of article III of these bylaws.

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Section 2.                      Powers and Duties of Chairman of Board of Directors.  The board of directors may elect a non-employee chairman to give leadership to the board and to serve as liaison between management and the board of directors.  In collaboration with the chief executive officer, the chairman will establish an agenda for each board meeting which covers all matters which should come before the board in the proper exercise of its duties.  The chairman will be accountable and will provide leadership for all issues of corporate governance which should come to the attention of the board and its committees.  The chairman will provide leadership to the board in the establishment of positions which the board should take on issues to come before the annual meeting of shareholders.  The chairman shall perform such other duties as from time to time may be delegated to him/her by the board of directors.

Section 3.                             Powers and Duties of President.  The president shall be the chief executive officer and/or the chief operating officer of the Corporation and, subject to the direction of the board of directors, shall (a) have general and active management of the administration and operation of the business of the Corporation, (b) have the general supervision and direction of the other officers of the Corporation and shall see that their duties are properly performed, (c) see that all orders and resolutions of the board of directors are carried into effect, (d) have the power to execute contracts and conveyances on behalf of the Corporation (including without limitation conveyances of real and personal property to and by the Corporation), and (e) perform such other functions normally performed by a chief executive officer.

Section 4.                      Powers and Duties of Vice President.  The board of directors may appoint one ormore vice presidents.  Each vice president shall have the power to execute contracts and conveyances on behalf of the Corporation, and shall have such other powers and shall perform such other duties as may be assigned to him by the board of directors or by the president.

Section 5.                      Powers and Duties of Secretary.  The secretary shall attend and record, in a book kept for such purpose, the proceedings of all meetings of the shareholders of the Corporation and of the board of directors.  He shall keep an account of stock registered and transferred in such manner as the board of directors may prescribe.  He shall keep the seal of the Corporation and, when authorized by the board of directors or the executive committee, he shall affix the seal of the Corporation to any instrument requiring the same, and attest the same by his signature, or cause the same to be attested by the signature of an assistant secretary.  He shall give proper notice of meetings of shareholders and directors and shall perform such other duties as shall be assigned to him.  Assistant secretaries shall have such duties as the board of directors may from time to time prescribe.

Section 6.                      Powers and Duties of Treasurer.  The treasurer shall have custody of the funds and securities of the Corporation, shall keep full and accurate accounts of receipts and disbursements in books belonging to the Corporation, and shall deposit or cause to be deposited all moneys and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the board of directors.  He shall disburse or cause to be disbursed the funds of the Corporation as may be ordered by the board of directors, executive committee, chief executive officer or president, taking proper vouchers for such disbursements, and shall render to the chief executive officer, the president, and the directors at the regular meetings of the board of directors, or whenever they require it, an account of all his transactions as

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treasurer and of the financial condition of the Corporation, and at the regular meeting of the board of directors next preceding the annual shareholders’ meeting, a like report for the preceding fiscal year.  He shall give the Corporation a bond, if required by the board of directors, in such sum and in form and with security satisfactory to the board of directors, for the faithful performance of the duties of his office and the restoration to the Corporation, in case of his death, resignation, or removal from office, of all books, papers, vouchers, moneys, and other property of whatever kind in his possession belonging to the Corporation.  He shall perform such other duties as the board of directors or executive committee may from time to time prescribe.  Assistant treasurers shall have such duties as the board of directors may from time to time prescribe.

Section 7.                      Delegation of Duties.  In case of the absence or disability of any officer of the Corporation, or for any other reason deemed sufficient by the board of directors, the board of directors may delegate such officer’s powers or duties for the time being to any other officer, to any employee with management responsibility, or to any director.

ARTICLE IX

Capital Stock

Section l.                      Stock Certificates.  The shares of capital stock of the Corporation may be represented by certificates in such form as may be approved by the board of directors, which certificates shall be signed by the chief executive officer, the president or one of the vice presidents of the Corporation and also by the secretary or an assistant secretary, or the treasurer or an assistant treasurer.  Such certificates shall have affixed an impression of the seal of the Corporation.  Where such certificates are countersigned by a transfer agent and by a registrar, both of which may be the same institution, the signatures of such officers and the seal of the Corporation thereon may be facsimiles, engraved or printed.  If an officer of the Corporation who shall have signed a certificate of capital stock, or whose facsimile signature has been affixed for such purpose, shall cease to be such officer of the Corporation before the stock certificate so signed shall have been issued by the Corporation, such stock certificate may nevertheless be issued and delivered with the same force and effect as though the person who signed such certificate or whose facsimile signature has been affixed for such purpose had not ceased to be such officer of the Corporation.  Notwithstanding the foregoing regarding share certificates, officers of the Corporation may provide that some or all of any or all classes or series of the Corporation’s capital stock may be uncertificated shares.

Section 2.                      Lost or Destroyed Certificates.  The board of directors may determine the conditions upon which a new certificate for capital stock of the Corporation may be issued in place of a certificate which is alleged to have been lost, stolen, or destroyed and may, in its discretion, require the owner of such certificate or his legal representative to give bond with sufficient surety to the Corporation to indemnify it against any loss or claim which may arise by reason of the issue of a new certificate in the place of the one so alleged to have been lost, stolen, or destroyed.

Section 3.                      Transfer of Shares.  The shares of capital stock of the Corporation shall be transferable only upon its books by the holders thereof in person or by their duly authorized attorneys or legal representatives, and upon such transfer the old certificates, if such shares are

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represented by certificates, shall be surrendered to the Corporation by the delivery thereof to the person in charge of the stock or transfer books and ledgers, or to such other person as the board of directors may designate, by whom they shall be canceled.  New stock certificates or uncertificated shares may thereupon be issued, representing the shares so transferred.  A record shall be made of each transfer.

Section 4.                      Dividends.  Dividends upon the capital stock may be declared by the board of directors at a regular or special meeting out of the net profits or surplus of the Corporation.  Before paying a dividend or making a distribution of profits, there may be set aside out of the accumulated profits of the Corporation such sum or sums as the directors from time to time, in their absolute discretion, think proper as a reserve fund for meeting contingencies or for equalizing dividends or for repairing or maintaining property of the Corporation or for such other purpose as the directors shall think conducive to the interests of the Corporation.

Section 5.                      Closing Transfer Books; Fixing Record Date.  The board of directors may fix the time, not exceeding 60 days preceding the date of a meeting of shareholders, a dividend payment date, or a date for the allotment of rights, during which the books of the Corporation shall be temporarily closed against transfers of stock; or, in lieu thereof, the board of directors may fix a date, not exceeding 60 days preceding the date of a meeting of shareholders, a dividend payment date, or a date for the allotment of rights, as a date for the taking of a record of the shareholders entitled to notice of and to vote at such meeting, or entitled to receive such dividends or such rights, as the case may be; and only shareholders of record on such date shall be entitled to notice of and to vote at such meeting, or to receive such dividends or rights, as the case may be.

ARTICLE X

Fair-Price Provisions

Section 1.                      Definitions.  As used in article X of these bylaws, the following terms shall have the indicated meanings:

(a)           “Affiliate,” including the term “affiliated person,” means a person that directly or indirectly through one or more intermediaries controls, is controlled by, or is under common control with, a specified person.

(b)           “Associate,” when used to indicate a relationship with any person, means any of the following:

(1)           A corporation or organization, other than the Corporation or a subsidiary of the Corporation, of which such person is an officer, director, or partner or is, directly or indirectly, the beneficial owner of 10% or more of any class or series of equity securities.

(2)           A trust or other estate on which such person has a substantial beneficial interest or as to which such person serves as trustee or in a similar fiduciary capacity.

(3)           A relative or spouse of such person, or any relative of such spouse, who has

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the same home as such person or who is a director or officer of the Corporation or any of its affiliates.

(c)           “Beneficial owner,” when used with respect to voting stock, means any of the following:

(1)           A person who individually or with any of his affiliates or associates beneficially owns voting stock, directly or indirectly.

(2)           A person who individually or with any of his affiliates or associates has either of the following rights:

(A)           To acquire voting stock, whether such right is exercisable immediately or only after the passage of time, pursuant to any agreement, arrangement, or understanding or upon the exercise of conversion rights, exchange rights, warrants, or options, or otherwise.

(B)           To vote voting stock pursuant to any agreement, arrangement, or understanding.

(3)           A person who has any agreement, arrangement, or understanding for the purpose of acquiring, holding, voting, or disposing voting stock with any other person who beneficially owns or whose affiliates beneficially own, directly or indirectly, such shares of voting stock.

(d)           “Business combination” means any of the following:

(1)           Except for a merger, consolidation, or share exchange that does not alter the contract rights of the stock as expressly set forth in the articles of incorporation of the Corporation or change or convert in whole or in part the outstanding shares of the Corporation, any merger, consolidation, or share exchange of the Corporation or any subsidiary with:

(A)           An interested shareholder; or

(B)           Another corporation, whether or not itself an interested shareholder, which is, or after the merger, consolidation, or share exchange would be, an affiliate of an interested shareholder that was an interested shareholder before the transaction.

(2)           A sale, lease, transfer, or other disposition, other than in the ordinary course of business, in one transaction or a series of transactions in any twelve-month period, to an interested shareholder or any affiliate of an interested shareholder, other than the Corporation or any of its subsidiaries, of any assets of the Corporation or any subsidiary having, measured at the time the transaction or transactions are approved by the board of directors of the Corporation, an aggregate book value as of the end of the Corporation’s most recently ended fiscal quarter of 10% or more of the total market value of the

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outstanding stock of the Corporation or of its net worth as of the end of its most recently ended fiscal quarter.

(3)           The issuance or transfer by the Corporation or any subsidiary, in one transaction or a series of transactions, of any equity securities of the Corporation or any subsidiary which has an aggregate market value of five percent or more of the total market value of the outstanding stock of the Corporation, to any interested shareholder or any affiliate of any interested shareholder, other than the Corporation or any of its subsidiaries, except pursuant to the exercise of warrants or rights to purchase securities offered pro rata to all holders of the Corporation’s voting stock or any other method affording substantially proportionate treatment of the holders of voting stock.

(4)           The adoption of a plan or proposal for the liquidation or dissolution of the Corporation in which anything other than cash will be received by an interested shareholder or an affiliate of an interested shareholder.

(5)           A reclassification of securities, including a reverse stock split or recapitalization of the Corporation, or any merger, consolidation, or share exchange of the Corporation with any of its subsidiaries which has the effect, directly or indirectly, in one transaction or a series of transactions, of increasing by five percent or more of the total number of outstanding shares the proportionate amount of the outstanding shares of any class or series of equity securities of the Corporation or any subsidiary which is directly or indirectly owned by an interested shareholder or an affiliate of an interested shareholder.

(e)           “Common stock” means stock other than preferred or preference stock.

(f)           “Control,” including the terms “controlling,” ”controlled by,” and “under common control with,” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise.  The beneficial ownership of 10% or more of the votes entitled to be cast of a corporation’s voting stock creates a presumption of control.

(g)           “Equity security” means any of the following:

(1)           Stock or a similar security, certificate of interest, or participation on any profit sharing agreement, voting trust certificate, or certificate of deposit for an equity security.

(2)           A security convertible, with or without consideration, into an equity security, or any warrant or other security carrying any right to subscribe to or purchase an equity security.

(3)           Any put, call, straddle, or other option or privilege of buying an equity security from or selling an equity security to another without being bound to do so.

(h)           (l )           “Interested shareholder” means any person other than the Corporation or

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             any subsidiary that is either of the following:

(A)           The beneficial owner, directly or indirectly, of 10% or more of the voting power of the outstanding voting stock of the Corporation.

(B)           An affiliate of the Corporation who at any time within the two-year period immediately before the date in question was the beneficial owner, directly or indirectly, of l0% or more of the voting power of the then outstanding voting stock of the Corporation.

(2)           For the purpose of determining whether a person is an interested shareholder, the number of shares of voting stock deemed to be outstanding shall include shares deemed owned by the person through application of subsection (c) of this section, but may not include any other shares of voting stock which may be issuable pursuant to any agreement, arrangement, or understanding, or upon exercise of conversion rights, warrants, or options, or otherwise.

(i)           “Market value” means the following:

(A)           In the case of stock, the highest closing sale price during the 30-day period immediately preceding the date in question of a share of such stock on the principal United States securities exchange registered under the Exchange Act on which such stock is listed, or if such stock is not listed on any such exchange, the highest closing bid quotation with respect to a share of such stock during the 30-day period preceding the date in question on the National Association of Securities Dealers, Inc., Automated Quotations System or any system then in use, or if no such quotations are available, the fair market value on the date in question of a share of such stock as determined by the board of directors of the Corporation in good faith.

(B)           In the case of property other than cash or stock, the fair market value of such property on the date in question as determined by the board of directors of the Corporation in good faith.

(j)           “Subsidiary” means any corporation of which voting stock having a majority of the votes entitled to be cast is owned, directly or indirectly, by the Corporation.

(k)           “Voting stock” means shares of capital stock of a corporation entitled to vote generally in the election of directors.

Section 2.                      Vote Required in Business Combinations.  In addition to any vote otherwise required by law or the articles of incorporation of the Corporation, a business combination shall be recommended by the board of directors and approved by the affirmative vote of at least each of the following:

(a)           80% of the votes entitled to be cast by outstanding shares of voting stock of the Corporation voting together as a single voting group.

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(b)           Two-thirds of the votes entitled to be cast by holders of voting stock other than voting stock held by the interested shareholder who is or whose affiliate is a party to the business combination or an affiliate or associate of the interested shareholder, voting together as a single voting group.

Section 3.                      When Voting Requirements Not Applicable.

(a)           Definitions. For purposes of subsection (b) of this section, the following terms shall have the indicated meanings:

(1)           “Announcement date” means the first general public announcement of a proposal or intention to make a proposal of a business combination or its first communication generally to shareholders of the Corporation, whichever is earlier.

(2)           “Determination date” means the date on which an interested shareholder first became an interested shareholder.

(3)           “Valuation date” means the following:

(A)           For a business combination voted upon by shareholders, the later of (i) the day before the day of the shareholders” vote or (ii) the day 20 days before the consummation of the business combination.

(B)                For a business combination not voted upon by shareholders, the date of the consummation of the business combination.

(b)           Conditions. The vote required by section 2 of this article X shall not apply to a business combination, as defined in section 1 of this article X, if each of the following conditions is met:

(1 )           The aggregate amount of the cash and the market value as of the valuation date of consideration other than cash to be received per share by holders of common stock in such business combination is at least equal to the highest of the following:

            (A)           The highest per share price, including any brokerage commissions, transfer taxes, and soliciting dealers’ fees, paid by the interested shareholder for any shares of common stock of the same class or series that he acquired:

(i)           within the two-year period immediately before the announcement date of the proposal of the business combination; or

(ii)           in the transaction in which he became an interested shareholder, whichever is higher; or

(B)           The market value per share of common stock of the same class or

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series on the announcement date or on the determination date, whichever is higher; or

(C)               The price per share equal to the market value per share of common stock of the same class or series determined pursuant to subparagraph (B) immediately preceding, multiplied by the fraction of:

(i)           The highest per share price, including any brokerage commissions, transfer taxes, and soliciting dealers’ fees, paid by the interested shareholder for shares of common stock of the same class or series that he acquired within the two-year period immediately before the announcement date, over

(ii)           The market value per share of common stock of the same class or series on the first day in such two-year period on which the interested shareholder acquired shares of common stock.

(2)           The aggregate amount of the cash and the market value as of the valuation date of consideration other than cash to be received per share by holders of shares of any class or series of outstanding stock other than common stock is at least equal to the highest of the following, whether or not the interested shareholder has previously acquired shares of a particular class or series of stock:

(A)           The highest per share price, including any brokerage commissions, transfer taxes, and soliciting dealers’ fees, paid by the interested shareholder for any shares of such class or series of stock that he acquired:

(i) within the two-year period immediately before the announcement date of the proposal of the business combination; or

(ii) in the transaction in which he became an interested shareholder, whichever is higher; or

(B)           The highest preferential amount per share to which the holders of shares of such class or series of stock are entitled in the event of voluntary or involuntary liquidation, dissolution, or winding up of the Corporation; or

(C)        The market value per share of such class or series of stock on the announcement date or on the determination date, whichever is higher; or

            (D)           The price per share equal to the market value per share of such class or series of stock determined pursuant to subparagraph (C) immediately preceding, multiplied by the fraction of:

(i)           The highest per share price, including any brokerage commissions, transfer taxes, and soliciting dealers’ fees, paid by the

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interested shareholder for such shares of voting stock acquired by him within the two-year period immediately before the announcement date, over

(ii)           The market value per share of the same class or series of voting stock on the first day on such two-year period on which the interested shareholder acquired shares of the same class or series of voting stock.

(3)           The consideration to be received by holders of any class or series of outstanding stock is to be in cash or in the same form as the interested shareholder previously paid for shares of the same class or series of stock. If the interested shareholder has paid for shares of any class or series of stock with varying forms of consideration, the form of consideration for such class or series of stock shall be either cash or the form used to acquire the largest number of shares of such class or series of stock that he previously acquired.

(4)           (A)           After the interested shareholder has become an interested shareholder and before the consummation of such business combination:

(i)           There shall have been no failure to declare and pay at the regular date therefor any full periodic dividends, cumulative or not, on any outstanding preferred stock of the Corporation;

(ii)           There shall have been:

(aa)           No reduction in the annual rate of dividends paid on any class or series of stock of the Corporation that is not preferred stock except as necessary to reflect any subdivision of such stock; and

(bb)           An increase in such annual rate of dividends as shall have been necessary to reflect reclassification, including reverse stock split, recapitalization, reorganization, or similar transaction, which shall have the effect of reducing the number of outstanding shares of such stock; and

            (iii)           The interested shareholder did not become the beneficial owner of additional shares of stock of the Corporation except as part of the transaction which resulted in such interested shareholder’s becoming an interested shareholder or by virtue of proportionate stock splits or stock dividends.

(B)           The provisions of (i) and (ii) of subparagraph (A) shall not apply if neither an interested shareholder nor an affiliate or associate of an interested shareholder voted as a director of the Corporation in a manner inconsistent with (i) and (ii), and the interested shareholder, within 10 days after an act or failure to act inconsistent with such subparagraphs, shall have notified the board of directors of

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the Corporation in writing that the interested shareholder disapproves thereof and requests in good faith that the board of directors rectify such act or failure to act.

(5)           After the interested shareholder has become an interested shareholder, the interested shareholder may not have received the benefit, directly or indirectly, except proportionately as a shareholder, of loans, advances, guarantees, pledges, or other financial assistance, or tax credits or other tax advantages, provided by the Corporation or any of its subsidiaries, whether in anticipation of or in connection with such business combination or otherwise.

(c)           Other Provisions.

(1)           Section 2 of this article X shall not apply to a business combination with a particular interested shareholder or his existing or future affiliates that has been approved or exempted therefrom by resolution of the board of directors of the Corporation; provided, however, that any such resolution shall have been adopted before the time that such interested shareholder first became an interested shareholder.

(2)           Unless by its terms a resolution adopted under this subsection is made irrevocable, it may be altered or repealed by the board of directors, but this shall not affect a business combination that has been consummated or is the subject of an existing agreement entered into before the alteration or repeal.

ARTICLE XI

Notices

Section 1.                      Manner of Giving Notice. Notice required to be given under the provisions of these bylaws to a director, officer, or shareholder shall not be construed to mean personal notice, but may be given by depositing written or printed notice in a post office or letter box in a postpaid wrapper addressed to such director, officer, or shareholder at such address as appears on the books of the Corporation, such notice to be deemed to have been given at the time when the same shall have been thus mailed; or, if such person has provided a telecommunications address to the Corporation, such notice may be given by prepaid written telecommunication sent to such address and in such event shall be deemed to have been given at the time when the same shall have been transmitted.

Section 2.                      Waiver of Notice. Any shareholder, officer, or director may waive, in writing or by written telecommunication, whether before or after the time stated, any notice required to be given under these bylaws.

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ARTICLE XII

Miscellaneous

Section 1.                      Fiscal Year. The fiscal year of the Corporation shall begin on the first day of January and end on the last day of December in each year.

Section 2.                      Checks and Drafts. All checks, drafts, and orders for the payment of money shall be signed by the treasurer, in person or by facsimile or other authorized means, or by such other officer or officers or agents as the board of directors may from time to time designate. No check shall be signed in blank.

Section 3.                      Books and Records. The books, accounts, and records of the Corporation shall, subject to the limitations fixed by law, be open to inspection by the shareholders at such times and subject to such regulations as the board of directors may prescribe.

Section 4.                      Separability. If one or more of the provisions of these bylaws shall be held to be invalid, illegal, or unenforceable, such invalidity, illegality, or unenforceability shall not affect any other provision hereof and these bylaws shall be construed as if such invalid, illegal, or unenforceable provision or provisions had never been contained herein.

ARTICLE XIII

Amendment of Bylaws

Section 1.                      Voting. These bylaws may be amended, repealed, or supplemented at any regular meeting of the board of directors, or at any special meeting called for such purpose, by the affirmative vote of a majority of the board of directors, or by unanimous written consent; provided, however, that in each instance an amendment, repeal, or supplement shall not be inconsistent with the law or the articles of incorporation of the Corporation and shall be subject to the power of the shareholders to amend, repeal, or supplement the bylaws so made but only upon the affirmative vote of at least 80% of all shares of capital stock entitled to vote thereon.

Section 2.                      Shareholder Proposals. No proposal by a shareholder to amend, repeal, or supplement the bylaws of the Corporation may be voted upon at a meeting of shareholders unless, at least 180 days before such meeting of shareholders, such shareholder shall have delivered in writing to the secretary of the Corporation (a) notice of such proposal, including all information required by section 7(b)(3) of article II of these bylaws, (b) the text of the proposed amendment, repeal, or supplement and (c) an opinion of counsel, which counsel and the form and substance of which opinion shall be reasonably satisfactory to the board of directors of the Corporation, to the effect that the bylaws (if any) resulting from the adoption of such proposal would not be in conflict with the articles of incorporation of the Corporation or the laws of the State of Louisiana. In no event shall any adjournment, postponement or deferral of a meeting of shareholders or the announcement thereof commence a new time period for the giving of a shareholder’s notice as described above. Within 30 days after such shareholder shall have submitted the aforesaid items,

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the secretary and the board of directors of the Corporation shall respectively determine whether the items to be ruled upon by them are reasonably satisfactory and shall notify such shareholder in writing of their respective determinations. If such shareholder fails to submit a required item in the form or within the time indicated, or if the secretary or the board of directors of the Corporation determine that the items to be ruled upon by them are not reasonably satisfactory, then such proposal by such shareholder may not be voted upon by the shareholders of the Corporation at such meeting of shareholders.

Section 3.                      Effective Date. No amendment or supplement to or repeal of any of the following provisions of these bylaws, whether resulting from action of the directors or the shareholders, shall take effect until the later of (i) one year following the adoption of such amendment, supplement, or repeal, or (ii) 10 days after the adjournment sine die of the annual meeting of shareholders next succeeding the adoption of such amendment, supplement, or repeal:

Article II, section 2;

Article II, section 8;

Article X; and

Article XIII.

ARTICLE XIV

Other Amendments to Bylaws

Section 1.                      Effective Date. No amendment or supplement to or repeal of any of the following provisions of these bylaws, whether resulting from action of the directors or the shareholders, shall take effect until the later of (i) one year following the adoption of such amendment, supplement, or repeal, or (ii) 10 days after the adjournment sine die of the annual meeting of shareholders next succeeding the adoption of such amendment, supplement, or repeal:

Article II, section 4;

Article II, section 5;

Article II, section 7;

Article II, section 9;

Article III, section 1;

Article III, section 2; and

Article XIV;

provided, however, that the board of directors shall have the power at any time, free from the foregoing restrictions, but subject to the provisions of subsection (g) of section 1 of article III of these bylaws, to amend or otherwise change subsections (a) and (d)(1) of section 1 of article III of these bylaws, and, with respect to any amendments to or changes in such subsection (d)(1), to make appropriate conforming changes in such section 1.

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ARTICLE XV

Control Share Acquisition Statute

Section 1.                      Pursuant to Section 136 of the Louisiana Business Corporation Law, the provisions of Sections 135 through 140.2 of the Louisiana Business Corporation Law, enacted as part of Title 12 of the Louisiana Revised Statutes, shall not apply to “control share acquisitions” (as defined therein) of this Corporation.

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EX-10.1

Page 1 of 12

EXHIBIT 10.1

CLECO CORPORATION

EXECUTIVE SEVERANCE PLAN

THIS EXECUTIVE SEVERANCE PLAN (the “Plan”) is adopted and maintained by Cleco Corporation (the “Company”) to be first effective as set forth below.

1. Purpose:

ThisPlan is intended to be a welfare benefit plan within the meaning of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), which benefits a select group of key management employees, subject to the terms and conditions set forth herein.

2.           Definitions:

2.1           “Affiliate” means a subsidiary or affiliate of the Company, at least 80% of the equity securities of which are owned directly or indirectly by the Company.

2.2           “Average Bonus” means the average of a Covered Executive’s annual bonus payable under the Company’s Annual Incentive Plan, or any successor thereto, during the three whole fiscal years immediately preceding such executive’s Separation Date; provided that if a Covered Executive has not been employed by the Company during the three whole fiscal years preceding his or her Separation Date, such average shall be determined with respect to amounts payable during his or her actual period of eligibility.

2.3           “Base Compensation”means a Covered Executive’s periodic regular rate of pay, determined without regard to any bonus, incentive, equity compensation, fringe benefit or similar amount.  “Annualized Base Compensation” means the annualized rate of a Covered Executive’s Base Compensation in effect immediately prior to the commencement of a Change in Control Period.

2.4           “Board” or “Board of Directors” means the Board of Directors of the Company.

2.5           “Change in Control Period”means the 60-day period preceding and the 24-month period following the consummation of a Change in Control.

2.6           “Code” means the Internal Revenue Code of 1986, as amended, including any successor thereto and any regulation or other guidance promulgated thereunder.

2.7           “Committee” means the Compensation Committee of the Company’s Board of Directors.

2.8           “Constructive Termination” means: (a) a material reduction, other than a reduction in pay uniformly applicable to all officers of the Company, in the amount of a Covered Executive’s Base Compensation; or (b) a material diminution in a Covered Executive’s authority, duties or responsibilities.  No event or condition shall constitute a Constructive Termination hereunder unless: (i) a Covered Executive provides to the Committee written notice of his or her objection to such event not later than 60 days after such executive first learns, or should have learned, of such event; (ii) such event is not corrected by the Company promptly after receipt of such notice, but in no event more than 30 days after receipt thereof; and (iii) such executive Separates From Service not more than 15 days following the expiration of the 30-day period described in clause (ii) hereof.

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2.9           “Covered Executive” means a common law employee of the Employer, provided that he or she: (a) holds the title of “general manager” or above or a substantially equivalent position as determined by the Committee; (b) is designated by the Committee as a Covered Executive hereunder; and (c) is not a party to or covered under an employment or similar agreement, plan or arrangement providing severance or similar separation benefits as of his or her Separation Date.

2.10           “Employer”means the Company and the following Affiliates: Cleco Power LLC, Cleco Midstream Resources LLC, and Cleco Support Group LLC.

2.11           “Good Reason”means that: (a) a Covered Executive’s Base Compensation in effect immediately before the commencement of a Change in Control Period is materially reduced, or there is a material reduction or termination of such executive’s rights to any employee benefit in effect immediately prior to such period; (b) a Covered Executive’s authority, duties or responsibilities are materially reduced from those in effect immediately before the commencement of a Change in Control Period, or such executive has reasonably determined that, as a result of a change in circumstances that materially affects his or her employment with the Company, he or she is unable to exercise the authority, power, duties and responsibilities assigned to him or her immediately before the commencement of such period; (c) a Covered Executive is required to be away from his or her office in the course of discharging his or her duties and responsibilities significantly more than was required before the commencement of a Change in Control Period; or (d) a Covered Executive is required to transfer to an office or business location that is more than 60 miles from the primary location to which he or she was assigned prior to the commencement of a Change in Control Period.  No event or condition shall constitute Good Reason hereunder unless: (i) a Covered Executive provides to the Committee written notice of his or her objection to such event not later than 60 days after such executive first learns, or should have learned, of such event; (ii) such event is not corrected by the Company promptly after receipt of such notice, but in no event more than 30 days after receipt thereof; and (iii) such executive Separates From Service not more than 15 days following the expiration of the 30-day period described in clause (ii) hereof.  One or more members of the Committee, as constituted immediately prior to the commencement of a Change in Control Period, shall determine whether any Separation From Service is on account of Good Reason as defined herein.

2.12           “Participant” means a Covered Executive who is eligible to receive Severance Benefits hereunder.

2.13           “Severance Benefits” means Basic Severance and Change in Control Severance; “Basic Severance” means payments and benefits on account of a Participant’s Separation from Service, other than during a Change in Control Period; “Change in Control Severance” means payments and benefits on account of a Participant’s Separation From Service during a Change in Control Period.

2.14           “Years of Employment” means a Participant’s period of consecutive service with the Employer, determined as of his or her Separation Date, measured in 12-month increments; a partial period of not less than six whole months shall be treated as a full Year of Employment; a partial period of less than six whole months shall be disregarded.  If a Participant terminates his or her employment with the Employer and is later rehired, Years of Employment shall be measured from his or her reemployment date.

2.15           Further Definitions.  The terms “Cause,” “Change in Control,” “Disability,”“Retirement,” “Separation Date” and “Separation From Service”shall have the meanings ascribed to them in the Company’s 2010 Long-Term Incentive Compensation Plan, as the same may be amended, modified, restated or replaced, from time to time (the “LTIP”).

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3.           Eligibility for Severance Benefits:

3.1           Qualifying Separation.  A Covered Executive may be eligible to receive Basic Severance or Change in Control Severance, as the case may be, provided his or her Separation From Service constitutes a Qualifying Separation.  For this purpose, the term “Qualifying Separation” shall mean a Separation From Service that:

a. Is involuntary by the Employer, other than on account of Cause, or is initiated by a Covered Executive on account of Good Reason or Constructive Termination, as the case may be.

b. With respect to Basic Severance, further: (i) that a Covered Executive’s Separation Date does not occur during a Change in Control Period; (ii) that such executive’s Separation From Service is not involuntary by the Company on account of poor performance, whether or not constituting Cause; and (iii) if such Qualifying Separation is in connection with a merger, acquisition, sale, transfer, reorganization or restructuring of the Company or any Affiliate or business unit or division thereof, other than a Change in Control, that such executive is not offered another position with the Employer, the acquiring entity or their successors that provides base salary and bonus opportunity substantially equal in the aggregate to his or her then current Base Compensation and bonus opportunity.

c. With respect to Change in Control Severance, further that a Covered Executive’s Qualifying Separation occurs during a Change in Control Period.

3.2           Waiver, Release and Covenants.  Upon a Covered Executive’s Qualifying Separation, the Committee, or its designee, shall provide to such executive written notice of his or her eligibility for Severance Benefits hereunder; provided, however, that as a condition of the receipt of any such benefits, he or she shall be required to execute and deliver to the Company a Wavier, Release and Covenants substantially in the form attached hereto as Exhibit C, which exhibit may be amended or modified as the Company shall deem necessary or appropriate, from time to time (a “Release”).  If a Covered Executive fails to timely execute a Release, or such Release does not become irrevocable in accordance with its terms, Severance Benefits shall not be due hereunder.

4. Terms And Conditions Applicable to Severance Benefits:

4.1           Benefits.  Subject to the terms and conditions of payment otherwise set forth herein, Basic Severance shall consist of those cash payments set forth on Exhibit A hereto, the terms of which are incorporated herein by this reference; Change in Control Severance shall consist of those cash payments and benefits set forth on Exhibit B hereto, the terms of which are incorporated herein by reference.

4.2           Cash Payments.  Except as provided in Section 4.5 hereof, any Base Compensation Cash Payment, Cash Payment in Lieu of Outplacement, and/or Change in Control Cash Payment, each as described in Exhibit A or B hereto, shall be aggregated and paid in the form of a single-sum as soon as practicable after a Participant’s Separation Date, provided that such Participant’s Release has then become irrevocable.

4.3           Medical Benefits.  Medical Benefits hereunder may consist of:

a.              Access to continuation coverage under the Company’s group medical plan, which coverage (i) shall be contingent upon each Participant’s timely election to continue

Page 4 of 12

coverage under such plan within the meaning of Code Section 4980B, and (ii) shall offset any period of continuation coverage otherwise available under applicable law; and/or

b. Cash payments in an amount equal to the full cost of the same type and level of continuation coverage under the Company’s group medical plan as elected by such Participant and/or his or her spouse or dependents under Code Section 4980B. Cash payments hereunder shall be made monthly during the period specified in Exhibit A or B hereto, as the case may be, 30 days in arrears.

Access to coverage and/or cash payments hereunder shall cease or be reduced, as the case may be, upon the earlier of the period specified in Exhibit A or B hereto or, if earlier, the date on which such Participant or his or her spouse or dependent becomes eligible for coverage under another employer’s group medical plan.

4.4           Home Purchase and Relocation. Subject to the provisions of Exhibit B hereto:

a. The Company shall purchase the principal residence occupied by a Participant as of his or her Separation Date (such Participant’s “Principal Residence”), provided such Principal Residence is located within 60 miles of the Participant’s primary work location, for an amount equal to the greater of (i) the fair market value of such residence as determined by the Company’s third party relocation service, or (ii) the purchase price of such residence and the documented cost of any capital improvements made by the Participant, but not more than 120% of such purchase price.

b. The Company shall further pay or reimburse a Participant for the cost of relocation, including the relocation of his or her immediate family and their household goods and other personal property, in accordance with the Company’s usual relocation practice, to any location in the continental United States.

Notwithstanding the foregoing, the Company shall not be obligated hereunder, unless: (a) a Participant actually relocates to a new principal residence that is more than 100miles from his or her Principal Residence, and (b) such Participant submits his or her written request to the Company for the purchase of such Principal Residence hereunder not later than 12 months after his or her Separation Date.  In any event, payment hereunder shall be made not later than December 31 of the calendar year following the year in which a Participant’s Separation Date occurs.

4.5           Code Section 409A Compliance.  If a Participant is a “specified employee” within the meaning of Code Section 409A as of his or her Separation Date and any amount or benefit payable or due hereunder is deemed to constitute “deferred compensation” that is subject to the payment restrictions set forth in Code Section 409A, the Company shall delay the payment of all or the affected portion of any such amount or benefit until the first business day of the seventh month following such Participant’s Separation Date.  Payment shall be made as soon as practicable thereafter, but without liability for interest or loss of investment opportunity. Status as a “specified employee” shall be determined by the Committee in accordance with its generally applicable policies and procedures.  For this purpose, each payment or benefit hereunder shall be designated as a separate payment or benefit under the short-term deferral provisions, the exemption for involuntary termination payments, the exemption for in-kind benefits, and the exemption for medical expense reimbursements.

Any payment or benefit hereunder that is deemed “deferred compensation” within the meaning of Code Section 409A and that could be due in one of two years shall be paid in the second such year.

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4.6           Excise Tax Limitation.  If any payment or benefit made or provided to a Participant by the Company or an Affiliate, is subject to the excise tax imposed under Code Section 4999 or similar tax or penalty, then such payment or benefit, including Severance Benefits hereunder, shall be reduced to the minimum extent necessary to avoid the imposition of such tax by reducing cash payments hereunder.  The amount of any such reduction shall be determined by a nationally recognized public accounting firm retained by the Company, as soon as practicable following a Participant’s Separation Date.  All fees and expenses of such accounting firm shall be borne by the Company.  The Company and any affected Participant shall promptly furnish to such accounting firm such information as may be reasonably required to calculate any reduction hereunder.  Such accounting firm shall provide a written determination of such reduction, together with detailed supporting calculations to the Company and the Participant, which shall be binding upon such parties.

5. Other Benefits:

5.1           Annual Incentive Plan.  In addition to any Severance Benefits hereunder, each Participant shall receive under the Company’s Annual Incentive Plan, or any successor thereto, an annual incentive for the Company’s fiscal year in which his or her Separation Date occurs, which:

a. With respect to Basic Severance, shall be (i) determined in accordance with the terms of such plan, (ii) prorated to reflect his or her period of service during such year, and (iii) paid at the time such incentives are customarily paid.

b. With respect to Change in Control Severance, shall be (i) determined as such Participant’s target incentive for such year, (ii) prorated to reflect his or her period of service during such year, and (iii) paid at the time or times determined in accordance with Section 4.2 hereof.

5.2           Long-Term Incentive Compensation Plan.  Each Participant shall receive, in addition to any Severance Benefits hereunder, all rights and benefits to which he or she may be entitled under the LTIP, including any predecessor thereto; the terms and conditions of such plan and any individual grant or award thereunder shall govern the rights and benefits afforded to each Participant therein.

5.3           Business Expenses.  The Company shall reimburse a Covered Executive for any reasonable and necessary business expenses incurred but not yet reimbursed as of his or her Separation Date, provided that the expenses are otherwise reimbursable under the Company’s standard reimbursement policy and that any request for reimbursement is made and documented in accordance with the Company’s standard practices.

5.4           Other Plans, Policies and Arrangements.  Except as expressly provided herein, nothing contained in this Plan is intended to impair or diminish any benefit or right accrued and vested as of a Covered Executive’s Separation Date under a separate employee benefit plan or program maintained by the Employer, which shall be administered and paid in accordance with its terms; provided, however that as a condition of the receipt of a benefit hereunder, a Participant shall be deemed to have waived and forfeited any right to receive termination, separation or severance benefits, whether payable under the terms of an employment or similar arrangement with the Company or an Affiliate or under a separate severance pay plan, policy or program maintained by the Company or an Affiliate.

6. Administration and Claims:

6.1           Administration.  The Committee shall administer this Plan, in its discretion.  Among other things, it shall determine the position or title of each Participant as of his or her Separation Date,

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whether the conditions applicable to the receipt of any Severance Benefits hereunder have been satisfied, and the amount or form of Severance Benefits payable hereunder.  The Committee may adopt rules and procedures and interpret the Plan and any form or document related to the Plan, including the resolution of uncertainty created by any conflict, ambiguity or omission contained in the Plan and/or its related forms and documents.  The Committee may delegate to the appropriate officers and employees of the Company one or more of its duties and obligations hereunder.

6.2           Claims.  The Committee or its designee shall furnish each Covered Executive with any necessary documents to claim Severance Benefits hereunder at the time of his or her Separation From Service, or as soon as practicable thereafter.

If a Covered Executive believes he or she is eligible to receive Severance Benefits, or that the amount of any such benefit has not been correctly determined, such executive may file a written claim with the Committee through the Company’s Human Resources Department.  Such claim shall identify the amount in controversy, include a description of the circumstances and provisions of the Plan supporting the claim, and include any documents or other evidence that supports payment of the disputed amount.

The Committee shall respond, in writing, within 90days following the receipt of such claim.  If the claim is denied, in whole or in part, the response shall include the reasons why the claim is denied and identify the Plan provisions and employment records upon which the denial is based.  A denial hereunder can be appealed by providing written notice to the Company’s Human Resources Department not later than 60days after the denial is received.  A Covered Executive may request copies of any documents in the possession of the Employer relevant to the determination of his or her Severance Benefits, such as salary history, promotion records and a copy of the Plan. The Committee shall provide to the Covered Executive written notice of its disposition not later than 60days after the appeal is received.

If a Covered Executive fails to file a claim within 12 months after his or her Separation Date, his or her Severance Benefits paid hereunder, if any, shall be deemed final and correct.  If a Covered Executive fails to appeal a claim within the time provided herein, the initial determination of the Committee shall be deemed final and binding on all persons claiming an interest or right in such benefit.

7.           General Provisions:

7.1           Spendthrift Provision.  Severance Benefits hereunder are not subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance or charge.  Any attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber or charge such benefit will be void and given no effect.  Any benefit payable under the terms of the Plan shall not be subject to attachment or legal process, and any such action shall not be recognized by the Employer.

7.2           Employment Rights.  Participation in the Plan is not an employment agreement; nothing contained herein is intended to provide a Covered Executive the right to be retained in the employ of the Employer, absent a written agreement to the contrary.

7.3           Amendment or Termination.  Except as provided herein, the Company has no obligation to maintain the Plan for any particular length of time; the Committee possesses the right, at any time, to amend or terminate this Plan, in whole or in part, by providing 30 days prior written notice to each Covered Executive hereunder.  Notwithstanding the foregoing: (a) no amendment or termination shall impair any Severance Benefits due with respect to a Qualifying Separation that occurs before the adoption or effective date of any such amendment or termination; and (b) no amendment shall materially adversely affect the rights or benefits of any Covered Executive hereunder during a Change in Control Period without his or her prior written consent.

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Nothing contained herein shall be deemed to amend any plan, policy or program maintained by the Employer, or to prohibit the amendment, modification or termination of any plan, policy or program maintained by the Employer, including but not limited to the group medical plan, which shall be at the discretion of the Employer in accordance with the provisions of any such plan.

7.4           Coordination with WARN.  Severance Benefits payable hereunder shall reduce any amount required to be paid under the Worker Adjustment and Retraining Notification Act.

7.5           Successors; Binding Plan.  This Plan is binding upon the Company and any successor to the Company, whether by purchase, merger, consolidation or otherwise.  This Plan shall inure to the benefit of each Covered Executive, including his or her personal or legal representatives, and executors or heirs.  If a Participant dies while Severance Benefits remain payable hereunder, the remaining amount shall be paid to his or her surviving spouse or estate.

7.6           Governing Law.  The Plan is governed by federal law to the extent applicable, and to the extent not applicable, by the internal laws of the State of Louisiana.

7.7           General Assets.  Benefits payable from the Plan are solely from the general assets of the Employer.  The Employer has not established a trust or earmarked any asset to pay benefits, and it has not acquired any form of insurance to fund any benefit hereunder.

7.8           Taxes. As a condition of any payment hereunder, the Company shall withhold any federal, state or local taxes required by law to be withheld.

7.9           Attorneys’ Fees.  In the event any dispute in connection with this Plan arises with respect to the payment of Severance Benefits hereunder, all costs, fees and expenses, including attorneys’ fees, of any legal action in connection with such matters shall be borne by the Company, provided that a Covered Executive prevails on at least one material issue.

7.10           Arbitration.  As a condition of the receipt of Severance Benefits under the Plan, any dispute or controversy that arises hereunder and after the Plan’s claims procedures are exhausted, shall be resolved by arbitration.  Any arbitration proceeding shall be conducted in accordance with the employment rules of the American Arbitration Association (“AAA”).  Any dispute or claim shall be presented to a single arbitrator selected by the mutual agreement of the parties (or the arbitrator will be selected in accordance with the rules of the AAA).  All determinations of the arbitrator will be final and binding.  Each party to the arbitration proceeding will bear its own costs in connection with the proceedings, except that the costs and expenses of the arbitrator will be divided evenly between the parties.  The venue for any arbitration proceeding and for any judicial proceeding related to this arbitration provision (including a judicial proceeding to enforce this provision) will be in Pineville, Louisiana.

THIS EXECUTIVE SEVERANCE PLAN was approved by the Board of Directors of Cleco Corporation on October 28, 2011, to be effective as of such date.

 CLECO CORPORATION

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EXHIBIT A

BASIC SEVERANCE BENEFITS

BASIC SEVERANCE BENEFITS
Title	Base Compensation Cash Payment	Cash Payment  in Lieu of Outplacement	Medical Benefits/Payments
General Manager	Minimum Benefit: 26 weeks of Base Compensation	$10,000	Cash payments for a maximum period equal to the number of whole months of Base Compensation Cash Payment
	Additional one month for each YOE
	Maximum Benefit: 52 weeks of Base Compensation
Vice President	Minimum Benefit: 32 weeks of Base Compensation	$20,000	Cash payments for a maximum period equal to the number of whole months of Base Compensation Cash Payment
	Additional one month for each YOE
	Maximum Benefit: 52 weeks of Base Compensation
Senior Vice President	1.         52 weeks of Base Compensation	$25,000	Cash payments for a maximum period of 18 months
Executive Vice President or above	52 weeks of Base Compensation	$50,000	Cash payments for a maximum period of 18 months

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EXHIBIT B

CHANGE IN CONTROL SEVERANCE BENEFITS

CHANGE IN CONTROL SEVERANCE BENEFITS
Title	Change in Control Cash Payment	Home Purchase/ Relocation	Medical Benefits/Payments
General Manager	1 X the sum of Annualized Base Compensation and Average Bonus	NA	Cash payments for a maximum period of 12 months
Vice President	2 X the sum of Annualized Base Compensation and Average Bonus	Available	Cash payments and coverage for a maximum period of 24 months
Senior Vice President or above	2 X  the sum of Annualized Base Compensation and Average Bonus	Available	Cash payments and coverage for a maximum period of 24 months

Attachment A

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EXHIBIT C

FORM OF WAIVER, RELEASE AND COVENANTS

Separation Date:  [TO COME]

Notice Date:  [TO COME]

Name of Executive:   

THIS WAIVER, RELEASE AND COVENANTS (the “Release”) is made by the Executive named above (“Executive”) in consideration and as a condition of the receipt of Separation Benefits more fully described in that certain Executive Severance Plan (the “Plan”) adopted by Cleco Corporation (the “Company”) and effective as of [DATE], the sufficiency of which is hereby acknowledged. Unless otherwise defined, capitalized terms used herein shall have the meanings ascribed to them in the Plan.

1.           Acknowledgements:  Executive understands that signing this Release is an important legal act; in connection with such execution, Executive:

a. Acknowledges that he or she has been advised to consult an attorney before signing this Release and that Executive has done so.

b. Agrees that this Release shall not be signed and dated prior to his or her Separation Date (above) or after the period described in subsection c hereof.

c. Understands that he or she has 21 calendar days after the later of his or her Separation Date or Notice Date (above) to consider whether to sign this Release, without alteration, and return it to the Company by first class mail or by hand delivery, and that if he or she executes and delivers this Release before the expiration of the 21-day period, Executive will be deemed to have waived the balance of the period. Executive agrees that any negotiation or modification of this Release shall not extend such 21-day period.

d. Acknowledges that he or she has been given an opportunity to review this Release, that he or she fully understands its provisions, and that he or she has voluntarily entered into this Release.

e. Understands that he or she may revoke this Release by providing written notice to the Company by hand delivery or by U.S. mail, postage prepaid, during the seven-day period following its execution; thereafter, this Release shall be irrevocable. Executive acknowledges that if he or she revokes this Release, the Company shall have no obligation to provide Severance Benefits under the Plan.

f. Acknowledges that the payments described in the Plan are voluntary on the part of the Company and are not required by any legal obligation of the Company, other than under the terms of the Plan and this Release.

2.           Release.  By execution below, Executive irrevocably and completely releases the Company and its Affiliates, including their predecessors and successors, and each of their directors and officers, employees, representatives, agents, and employee benefit plans, policies and arrangements, and the fiduciaries and agents of said plans, policies and arrangements from any and all claims, demands, actions, liabilities, expenses, benefits, payments, promises, agreements, costs, damages, and causes of

Page 11 of 12

action, whether known or unknown, suspected or unsuspected, arising in law or in equity, that arise out of or are related in any way to Executive’s employment with the Company, including his or her separation therefrom, including without limitation, any and all claims and causes under: Title VII of the Civil Rights Act of 1964, as amended by the Civil Rights Act of 1991; the Civil Rights Act of 1966; the Civil Rights Act of 1866; the Age Discrimination in Employment Act of 1967, as amended; the Older Workers Benefit Protection Act of 1990, as amended; the Americans with Disabilities Act of 1990, as amended; the Employee Retirement Income Security Act of 1974, as amended; the Family and Medical Leave Act of 1993, as amended; any claims of breach of contract, tort, defamation, slander, emotional distress or wrongful termination; and any other claims, whether arising under state or federal statutory or common law, including federal securities laws.

Notwithstanding the generality of the foregoing provisions of this Section 2, Executive does not waive or release: any right or claim arising after the date on which Executive executes this Release; ordinary claims for benefits accrued and vested or due as of his or her Separation Date under any benefit plan subject to ERISA or other benefit plan or arrangement or equity compensation plan sponsored and maintained by the Company or its Affiliates; any claim for compensation accrued and payable under applicable law; and any right to indemnification that Executive may possess as an employee of the Company, including its Affiliates, to the fullest extent provided under the indemnification and insurance arrangements of the Company.

Nothing contained herein shall be deemed to prevent Executive from filing a charge or complaint, including a challenge to the validity of this Release, with the Equal Employment Opportunity Commission (“EEOC”), or from participating in any investigation or proceeding conducted by the EEOC; provided that Executive understands and agrees that he or she shall not be entitled to any damages or other type or form of award relating to any event that occurred prior to his or her execution of this Release.

3.           Restrictive Covenants:  Executive acknowledges that the payments described in the Plan constitute consideration for the covenants set forth in this Section 3, the adequacy of which is hereby acknowledged.

3.1           Confidential Information.  Executive recognizes and acknowledges that prior to his or her Separation Date he or she shall have accessed and used confidential, proprietary, non-public information concerning the Company and its Affiliates, which may include, without limitation: (a) books and records relating to operations, finance, accounting, personnel and management; (b) cost, price, rate and volume data, future price, rate and trading plans, and test data; (c) product design and development; (d) records, computer software, customer lists, information obtained on competitors, and sales tactics; and (e) various other non-public trade or business information, including business opportunities, potential acquisitions, marketing, business diversification plans, acquisitions, strategic plans, methods and processes, and financial data and the like (collectively, the “Confidential Information”).  Executive agrees that he or she shall not at any time make any independent use of, or disclose to any other person or organization (except as authorized by the Company or pursuant to law, court order or administrative process with subpoena powers), any Confidential Information.

3.2           Non-Solicitation.  Executive agrees that during the two-year period following his or her Separation Date, he or she shall not, directly or indirectly, whether for his or her own benefit or on behalf of another:

a. Hire or offer to hire any of the Company’s officers, employees or agents;

Page 12 of 12

b. Persuade, or attempt to persuade, any officer, employee or agent of the Company to discontinue any relationship with the Company; or

c. Solicit or divert or attempt to divert any customer or supplier of the Company then doing business in the Restricted Area.

For this purpose, the term “Restricted Area” shall mean the following parishes in the State of Louisiana: Acadia, Allen, Avoyelles, Beauregard, Calcasieu, Catahoula, DeSoto, Evangeline, Grant, Iberia, Jefferson Davis, Lafayette, Natchitoches, Rapides, Red River, Sabine, St. Landry, St. Martin, St. Mary, St. Tammany, Vernon and Washington.

3.3           Business Reputation.  Executive agrees that he or she shall refrain from performing any act, engaging in any conduct or course of action or making or publishing an adverse, untrue or misleading statement which has or may reasonably have the effect of demeaning the name or business reputation of the Company or which adversely affects (or may reasonably adversely affect) the best interests, economic or otherwise, of the Company, unless required by law or pursuant to court order or administrative process with subpoena power.

3.4           Remedies.  Executive agrees that in the event of his or her material breach of this Release, including any covenant contained herein, in addition to any other legal or equitable remedy, the Company shall be entitled to recover any payments made under the Plan, or to cease further payments and benefits thereunder, subject to any restrictions on such recovery or as may be imposed under applicable law or as may be required to ensure that this Release is and remains valid and enforceable.

In the event of a breach or threatened breach by Executive of the covenants set forth in Section 3 hereof, Executive agrees that the Company shall further be entitled to a temporary restraining order or a preliminary injunction, which may be obtained by means of a judicial proceeding without the posting of bond in connection therewith.  Executive further acknowledges that the Company shall have no further obligation to provide any payment or benefit, whether due to Executive or his or her estate, spouse or dependents, under the Plan following such breach or threatened breach.

3.5           Restrictions Reasonable; Severable; Reformation Permitted.  Executive agrees that each of the covenants set forth in this Section 3 is intended to constitute a separate provision.  Accordingly, should any such covenant be declared invalid or unenforceable, such covenant shall be deemed severable from and shall not affect the remainder thereof.  Executive further agrees that the restrictions set forth in Section 3.2 hereof are reasonable in both time and geographic scope; should a court or arbitrator determine that any restriction set forth herein is unenforceable, such court or arbitrator may reform such restriction to the extent necessary to provide for its enforcement under applicable law.

4.           General.  Executive acknowledges and agrees that the provisions of Section 7 of the Plan shall be deemed incorporated herein by this reference, including, but not limited to those provisions requiring the arbitration of disputes thereunder.

EXECUTIVE:	WITNESS:
/s/ Jeffrey W. Hall	By:         /s/ Judy P. Miller
Date:               10-28-2011	Date:       10-28-2011

EX-10.2

 Page 1 of 2  EXHIBIT 10.2

CLECO CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

AMENDMENT

(Modification of Change in Control Provisions; Elimination of Business Transaction Benefits)

Whereas, Cleco Corporation, a corporation organized and existing under the laws of the State of Louisiana with its principal place of business in Pineville, Louisiana (the “Company”), sponsors andmaintains the Cleco Corporation Supplemental Executive Retirement Plan, which plan constitutes a deferred compensation arrangement subject to Section 409A of the Internal Revenue Code of 1986, as amended, and was most recently amended and restated effective as of January 1, 2009 (the “Plan”); and

Whereas, the Board of Directors of the Company now desires to modify the change in control provisions thereof in contemplation of the expiration of certain employment agreements by and between the Company and its officers, among other reasons; and

Whereas, the Board of Directors of the Company has determined that business transaction benefits provided thereunder are no longer necessary or appropriate on account of changes to the corporate structure of the Company and its affiliates, among other reasons; and

Whereas, Section 9.6 of the Plan provides that the Board of Directors possesses the authority to amend the Plan, subject to the limitations set forth therein;

Now, Therefore, effective as of October 28, 2011, the Plan shall be amended as follows:

1.           Section 7.2 of the Plan shall be amended and restated in its entirety as follows:

“7.2           Change in Control Benefits. If a Participant’s employment is involuntarily terminated by the Company or an Affiliate, without Cause, or a Participant terminates his or her employment with the Company or an Affiliate on account of Good Reason, in each case such termination occurring during the Change in Control Period:

a. He or she shall be credited with three years of age for purposes of determining his or her Benefit Percentage in accordance with Section 5.3 hereof; provided, however, that in no event shall such percentage be less than 50%; and

b. He or she shall be credited with three years of age for purposes of applying any actuarial reduction required under Section 5.4 hereof on account of the commencement of benefits prior to his or her Normal Retirement Date.

As used herein, the term “Change in Control Period” shall mean (i) if a Participant commences participation hereunder on or after October 28, 2011, the 60-day period preceding and the 24-month period following the consummation of a Change in Control, or (ii) if a Participant commenced her participation hereunder prior to October 28, 2011, the 60-day period preceding and the 36-month period following such consummation.

A Participant shall further be entitled to accelerate the payment of his or her Prior Plan Benefit in the event of a Change in Control subject to the terms, conditions and limitations set forth in the Prior Plan.”

Page 2 of 2

2.           Effective as of October 28, 2011, the Plan shall no longer provide benefits on account of the occurrence of a “Business Transaction” and the following sections of the Plan shall thereafter be deemed amended:

a. The text of Section 2.4 of the Plan, defining the term “Business Transaction,” shall be removed and that section marked “Reserved.”

b. The text of Section 4.1c of the Plan, providing for accelerated vesting upon the occurrence of a Business Transaction, shall be removed and that section marked “Reserved.”

c. Section 7.3 of the Plan, entitled “Benefits Upon a Business Transaction” shall be removed and such section marked “Reserved.”

This Amendment was approved by the Board of Directors of Cleco Corporation onOctober 28, 2011, to be effective as of such date provided for herein.

Cleco Corporation

By:       /s/ Jeffrey W. Hall                            

Date:    10-28-11                                            

EX-10.3

Exhibit 10.3

Cleco Corporation

Summary of Director Compensation, Benefits and Policies

As Approved by the Board of Directors on July 23, 2004 and

Last Revised on July 29, 2011

Annual Retainer Each non-management Director receives an annual retainer of $40,000.  This retainer is paid in quarterly installments of $10,000.  Effective January 1, 2012, the annual retainer will increase to $45,000 and will be paid in quarterly installments of $11,250.  The non-management Chairman of the Board receives an additional annual retainer of $90,000.  Effective January 1, 2012, the additional annual retainer for the non-management Chairman of the Board will increase to $100,000.

Each non-management Director who is chairman of a board committee receives an additional annual fee of $5,000, except the chairman of the Executive Committee, who does not receive any additional compensation for holding that position, and the chairman of the Audit Committee.  The chairman of the Audit Committee receives an additional annual fee of $12,500, which reflects the increased responsibilities of this position as a result of the Sarbanes-Oxley Act of 2002.  Effective January 1, 2012, the additional annual fee for the chairman of the Compensation Committee will increase to $7,500.  The total annual retainer may be paid, at the election of each Director, in the form of cash, Cleco common stock, or a combination of both cash and stock.

Meeting Fees Each non-management Director receives meeting fees as follows:  (1) $1,750 for each in-person board meeting attended; (2) $1,750 for each in-person Audit Committee meeting attended; (3) $1,500 for each in-person other committee meeting attended; and (4) $500 for each telephone conference meeting of the board or one of its committees attended, including informal telephone conference meetings.  Meeting fees may be paid, at the election of each Director, in the form of cash, Cleco common stock, or a combination of both cash and stock.

The Chairman of the Board is not paid for attendance at meetings (whether in person or by phone) of committees on which he does not serve, except quarterly phone meetings of the Audit Committee for review of the Form 10-K and/or Form 10-Q.  Nor is the Chairman compensated for meetings not associated with Board or committee meetings or for regular on-site visits to Cleco to receive updates from the management staff.

Corporate Governance Guidelines

Page 2 of 3

Special Services While expected to occur infrequently, when a non-management Director is requested to perform special services considered to be beyond the scope of the Director’s normal duties, each day spent performing those duties shall be considered the equivalent of attending a Board or committee meeting for purposes of Director compensation.  Normally compensation for such matters will be appropriate only if the Director is required to spend more than four hours on the matter and associated travel.  Examples, not inclusive, of such activities would be participating in the interview process for potential new Board candidates and/or members of senior management and working with consultants to the Board.  Determinations as to the applicability of compensation to a particular circumstance will be reviewed on a case-by-case basis by the President/CEO and the Corporate Secretary.

Expenses Directors are reimbursed for travel and related expenses incurred for attending meetings of the Board of Directors and board committees, including costs related to spousal travel, as well as for any special services as described above.  This reimbursement includes the cost of first class air fare as authorized by Cleco’s CEO.

As noted above, spousal travel forDirectors has been approved and authorized by Cleco’s CEO.  Therefore, reimbursement by Cleco to Directors for all costs related to spousal travel will be allowed.  Such costs will be charged to a specific account to allow for proper tax treatment by the Company.  (These costs will not be tax deductible for Cleco, nor will they be taxable to the Director.)

Restricted Stock Each non-management Director receives an annual restricted stock award of Cleco common stock valued at $50,000, not to exceed 10,000 shares of stock in any year.  The grant date of the award will be the date of the January Board meeting each year, and the valuation date of the stock will be the first trading day of the year.  The number of shares to be issued will be determined by dividing 85% of the stock price on the valuation date into $50,000.  Directors are not required to provide any consideration in exchange for the restricted stock award.  Restrictions on the stock subject to the award lapse after a six-year period measured from the date of the award or at the Director’s retirement if earlier, and the stock cannot be sold or transferred during this period.  Effective January 1, 2012, the value of this annual restricted stock award of Cleco common stock will increase to $65,000 for all directors except the non-management Chairman of the Board.  Effective January 1, 2012, the value of this annual restricted stock award of Cleco common stock will increase to $80,000 for the

Corporate Governance Guidelines

Page 3 of 3

non-management Chairman of the Board.  The number of shares to be issued will be determined by dividing 100% of the stock price on the valuation date into $65,000 and $80,000, respectively.

Stock Ownership Cleco has adopted stock ownership guidelines for Directors.  Under the guidelines, Cleco recommends that its current Directors beneficially own common stock of Cleco having a value equal to at least five times the annual Board retainer.  New Directors will have five years following their election to the Board to meet this recommended stock ownership level, and current Directors will have three years following each increase in the annual Board retainer to meet this recommended stock ownership level.  The intent of the guidelines is to encourage stock ownership by Directors and not to force a Director to purchase more stock, if and when the stock price declines.  Where the guidelines are not met within the applicable time, the matter will be reviewed by the Nominating/Governance Committee, which may determine to waive the guidelines or to make an appropriate recommendation to the Board.

Deferred 

Compensation

Plan A non-management Director may elect to participate in a deferred compensation plan and defer the receipt of all or part of his or her fees and restricted stock.  Benefits are equal to the amount credited to each Director’s individual account based on compensation deferred plus applicable investment returns.  Accounts are payable when a Director ceases to serve on the Board or attains a specified age.  (Please note:  Due to the complexity of the income tax rules related to deferred compensation, Directors may wish to consult their personal tax advisors.)

Life Insurance/

         Disability Plan Cleco provides its non-management Directors with $200,000 of life insurance and permanent total disability coverage under a group accidental death and dismemberment plan maintained by Cleco Power LLC, a wholly owned subsidiary of Cleco.  This coverage is terminated at the time the Director ceases to serve on the Board.  Coverage may not be continued, even if the departing Director agrees to pay the premium.

Management 

Directors Directors who are Cleco employees receive no additional compensation for serving as a Director.

EX-10.4

EXHIBIT 10.4

CLECO CORPORATION

2010 LONG-TERM INCENTIVE COMPENSATION PLAN

Amendment

(Elimination of Business Transaction)

Whereas, Cleco Corporation, a corporation organized and existing under the laws of the State of Louisiana with its principal place of business in Pineville, Louisiana (the “Company”), sponsors and maintains the Cleco Corporation 2010 Long-Term Incentive Compensation Plan, which plan provides for the grant or award of incentives related to shares of the Company’s common stock, $1.00 par value per share (the “Plan”); and

Whereas, the Board of Directors of the Company has determined that business transaction benefits provided thereunder are no longer necessary or appropriate on account of changes to the corporate structure of the Company and its affiliates, among other reasons; and

Whereas, pursuant to Section 12.1 of the Plan, the Board of Directors now possesses the authority to amend the Plan as contemplated herein, without further approval or consent;

Now, Therefore, effective with respect to the grant or award of incentives on or after October 28, 2011, the text of Sections 2.3 and 12.5 of the Plan shall be eliminated and such sections marked “Reserved.”

This Amendment was approved by the Board of Directors of Cleco Corporation on October 28, 2011, to be effective as provided herein.

Cleco Corporation

By:        /s/  Jeffrey W. Hall                          

Date:      10-28-11                                          

EX-10.5

 EXHIBIT EXHIBIT 10.5

CLECO CORPORATION

DEFERRED COMPENSATION PLAN

Amendment

(Business Transaction Definition)

Whereas, Cleco Corporation, a corporation organized and existing under the laws of the State of Louisiana with its principal place of business in Pineville, Louisiana (the “Company”), sponsors and maintains the Cleco Corporation Deferred Compensation Plan, which plan provides for the voluntary deferral of compensation otherwise payable to a participant therein (the “Plan”); and

Whereas, the Plan presently provides for the elective distribution of certain account balances accrued thereunder before January 1, 2005, following the occurrence of a business transaction with respect to the Company; and

Whereas, the Board of Directors now desires to expressly include a definition of the term “business transaction” in the Plan, but to make no other changes with respect thereto;

Now, Therefore, effective as of October 28, 2011, Section 2.7 of the Plan shall be amended and restated as follows:

“2.7           Business Transaction means the sale, lease or other disposition of all or substantially all of the assets of an Affiliate (in one or a series of transactions) to an entity, other than the Company or another Affiliate, or the sale or other disposition of all or substantially all of the issued and outstanding stock or other equity interests of an Affiliate to an entity, other than the Company or another Affiliate, provided that a Business Transaction hereunder shall not otherwise constitute a Change in Control as defined herein.”

This Amendment was approved by the Board of Directors of Cleco Corporation on October 28, 2011, to be effective as provided herein.

Cleco Corporation

By:       /s/  Jeffrey W. Hall                           

Date:     10-28-11                                           

EX-12.A

CLECO CORPORATION EXHIBIT 12(a)

Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined

Fixed Charges and Preferred Stock Dividends

	FOR THE THREE MONTHS ENDED			FOR THE NINE MONTHS ENDED			FOR THE TWELVE MONTHS ENDED
(THOUSANDS, EXCEPT RATIOS)				SEPTEMBER 30, 2011
Earnings from continuing operations	$	65,842		$	165,205		$	185,829
Undistributed equity income from investees		1			(3,385	)		(3,022	)
Income taxes		24,737			73,451			88,538
Earnings from continuing operations before income taxes	$	90,580		$	235,271		$	271,345
Fixed charges:
Interest, long-term debt	$	20,776		$	64,036		$	84,611
Interest, other (including interest on short-term debt)		4,635			13,157			16,013
Amortization of debt expense, premium, net		694			2,175			3,009
Portion of rentals representative of an interest factor		126			363			464
Interest of capitalized lease		442			1,356			1,827
Total fixed charges	$	26,673		$	81,087		$	105,924
Earnings from continuing operations before income taxes	$	90,580		$	235,271		$	271,345
Plus:  total fixed charges from above		26,673			81,087			105,924
Plus:  amortization of capitalized interest		77			154			308
Earnings from continuing operations before income taxes and fixed charges	$	117,330		$	316,512		$	377,577
Ratio of earnings to fixed charges		4.40	X		3.90	X		3.56	X
Total fixed charges from above		26,673			81,087			105,924
Preferred stock dividends		-			38			56
Total fixed charges and preferred stock dividends		26,673			81,125			105,980
Ratio of earnings to combined fixed charges and preferred stock dividends		4.40	X		3.90	X		3.56	X

EX-12.B

CLECO POWER EXHIBIT 12(b)

Computation of Ratios of Earnings to Fixed Charges

	FOR THE THREE MONTHS ENDED			FOR THE NINE  MONTHS ENDED			FOR THE TWELVE MONTHS ENDED
(THOUSANDS, EXCEPT RATIOS)				SEPTEMBER 30, 2011
Earnings from continuing operations	$	53,833		$	119,557		$	143,377
Income taxes		31,656			61,935			78,744
Earnings from continuing operations before income taxes	$	85,489		$	181,492		$	222,121
Fixed charges:
Interest, long-term debt	$	20,776		$	62,416		$	81,838
Interest, other (including interest on short-term debt)		4,258			11,175			13,325
Amortization of debt expense, premium, net		598			1,795			2,360
Portion of rentals representative of an interest factor		126			363			464
Interest of capitalized lease		442			1,356			1,827
Total fixed charges	$	26,200		$	77,105		$	99,814
Earnings from continuing operations before income taxes	$	85,489		$	181,492		$	222,121
Plus:  total fixed charges from above		26,200			77,105			99,814
Earnings from continuing operations before income taxes and fixed charges	$	111,689		$	258,597		$	321,935
Ratio of earnings to fixed charges		4.26	X		3.35	X		3.23	X

EX-31.1

CLECO CORPORATION EXHIBIT 31.1

Certification

I, Bruce A. Williamson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cleco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 2, 2011

/s/ Bruce A. Williamson

Bruce A. Williamson

President and Chief Executive Officer

EX-31.2

CLECO CORPORATION  EXHIBIT 31.2

Certification

I, Darren J. Olagues, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cleco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 2, 2011

/s/  Darren J. Olagues

Darren J. Olagues

Senior Vice President & Chief Financial Officer

EX-31.3

CLECO POWER LLC  EXHIBIT 31.3

Certification

I, Bruce A. Williamson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cleco Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 2, 2011

/s/  Bruce A. Williamson

Bruce A. Williamson

Chief Executive Officer

EX-31.4

CLECO POWER LLC EXHIBIT 31.4

Certification

I, Darren J. Olagues, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cleco Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 2, 2011

/s/  Darren J. Olagues

Darren J. Olagues

Senior Vice President & Chief Financial Officer

EX-32.1

CLECO CORPORATION EXHIBIT 32.1

Cleco Corporation

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Cleco Corporation (the “Company”) on Form 10-Q for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bruce A. Williamson, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 2, 2011

/s/  Bruce A. Williamson

Bruce A. Williamson

President and Chief Executive Officer

EX-32.2

CLECO CORPORATION EXHIBIT 32.2

Cleco Corporation

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Cleco Corporation (the “Company”) on Form 10-Q for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Darren J. Olagues, Senior Vice President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 2, 2011

/s/  Darren J. Olagues

Darren J. Olagues

Senior Vice President & Chief Financial Officer

EX-32.3

CLECO POWER LLC EXHIBIT 32.3

Cleco Power LLC

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Cleco Power LLC (the “Company”) on Form 10-Q for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bruce A. Williamson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 2, 2011

/s/  Bruce A. Williamson

Bruce A. Williamson

Chief Executive Officer

 

EX-32.4

CLECO POWER LLC EXHIBIT 32.4

Cleco Power LLC

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Cleco Power LLC (the “Company”) on Form 10-Q for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Darren J. Olagues, Senior Vice President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 2, 2011

/s/  Darren J. Olagues

Darren J. Olagues

Senior Vice President & Chief Financial Officer

XML

Acadia Transactions (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2011
Acadia Unit 1 and Facilities [Member] | APH [Member]
Significant Acquisitions and Disposals [Line Items]
Indemnification against third parties	$ 6.8
Third parties' share of entity's liabilities (in hundredths)	50.00%
APH [Member] | Acadia Unit 2 and Facilities [Member]
Significant Acquisitions and Disposals [Line Items]
Recognized gain on transaction	62.0
Indemnification against third parties	10.9
Third parties' share of entity's liabilities (in hundredths)	50.00%
Net adjustment to equity income	26.2
Impairment of investment	45.9
Capitalized interest and other	19.7
Acadia Unit 1 and Facilities [Member] | Acadia Power Partners [Member]
Significant Acquisitions and Disposals [Line Items]
Recognized gain on transaction	82.0
Acadia Unit 1 and Facilities [Member]
Significant Acquisitions and Disposals [Line Items]
Value of plant acquisition	304.0
Deferred taxes recognized	78.4
Acadia Unit 2 and Facilities [Member]
Significant Acquisitions and Disposals [Line Items]
Value of plant acquisition	$ 298.8

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net income	$ 65,842	$ 49,612	$ 165,205	$ 234,768
Other comprehensive income (loss), net of tax:
Amortization of post-retirement benefit net income (loss), net of tax (expense) benefit	269	9	910	(9)
Cash flow hedges:
Total other comprehensive income (loss), net of tax	(18,219)	(128)	(17,687)	(163)
Comprehensive income, net of tax	47,623	49,484	147,518	234,605
CLECO POWER [Member]
Net income	53,833	52,335	119,557	123,584
Other comprehensive income (loss), net of tax:
Amortization of post-retirement benefit net income (loss), net of tax (expense) benefit	146	(89)	519	(274)
Cash flow hedges:
Total other comprehensive income (loss), net of tax	(18,342)	(226)	(18,078)	(428)
Comprehensive income, net of tax	35,491	52,109	101,479	123,156
CLECO POWER [Member] | Interest Rate Swap [Member]
Cash flow hedges:
Net unrealized gain(loss) on derivatives, net of tax expense (benefit)	0	(231)	0	(441)
CLECO POWER [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, net of tax expense (benefit)	0	119	0	364
CLECO POWER [Member] | Treasury Rate Locks [Member]
Cash flow hedges:
Net unrealized gain(loss) on derivatives, net of tax expense (benefit)	(18,433)	0	(18,433)	0
CLECO POWER [Member] | Treasury Rate Locks [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, net of tax expense (benefit)	(55)	(25)	(164)	(77)
Interest Rate Swap [Member]
Cash flow hedges:
Net unrealized gain(loss) on derivatives, net of tax expense (benefit)	0	(231)	0	(441)
Interest Rate Swap [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, net of tax expense (benefit)	0	119	0	364
Treasury Rate Locks [Member]
Cash flow hedges:
Net unrealized gain(loss) on derivatives, net of tax expense (benefit)	(18,433)	0	(18,433)	0
Treasury Rate Locks [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, net of tax expense (benefit)	$ (55)	$ (25)	$ (164)	$ (77)

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) Parenthetical (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Other comprehensive income (loss), before tax:
Amortization of post-retirement benefit net income (loss), tax expense (benefit)	$ 178	$ 6	$ 454	$ (6)
CLECO POWER [Member]
Other comprehensive income (loss), before tax:
Amortization of post-retirement benefit net income (loss), tax expense (benefit)	99	(55)	227	(172)
CLECO POWER [Member] | Interest Rate Swap [Member]
Cash flow hedges:
Net derivatives loss arising during the period, tax expense (benefit)	0	(145)	0	(276)
CLECO POWER [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, tax expense (benefit)	0	75	0	228
CLECO POWER [Member] | Treasury Rate Locks [Member]
Cash flow hedges:
Net derivatives loss arising during the period, tax expense (benefit)	(11,529)	0	(11,529)	0
CLECO POWER [Member] | Treasury Rate Locks [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, tax expense (benefit)	(34)	(16)	(103)	(48)
Interest Rate Swap [Member]
Cash flow hedges:
Net derivatives loss arising during the period, tax expense (benefit)	0	(145)	0	(276)
Interest Rate Swap [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, tax expense (benefit)	0	75	0	228
Treasury Rate Locks [Member]
Cash flow hedges:
Net derivatives loss arising during the period, tax expense (benefit)	(11,529)	0	(11,529)	0
Treasury Rate Locks [Member] | Interest Expense [Member]
Cash flow hedges:
Reclassification, tax expense (benefit)	$ (34)	$ (16)	$ (103)	$ (48)

XML

Subsequent Event

9 Months Ended

Sep. 30, 2011

Subsequent Event [Abstract]

Subsequent Event

Note 16 — Subsequent Event

On October 13, 2011, Cleco settled the 2001 through 2003 audit cycle with the IRS.  As a result of the settlement, Cleco made a miscellaneous other federal income tax payment in accordance with Revenue Procedure 2001-18 in the amount of $13.0 million, and no interest was assessed.  Cleco will reverse $30.9 million of previously accrued federal and state interest expense and the corresponding deferred tax benefit of $11.9 million.  Cleco expects its effective tax rate to increase approximately 4.55% for the year.

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 28, 2011
Entity Information [Line Items]
Entity Registrant Name	CLECO CORP
Entity Central Index Key	0001089819
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		60,665,607
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
CLECO POWER [Member]
Entity Information [Line Items]
Entity Registrant Name	CLECO POWER LLC
Entity Central Index Key	0000018672
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3

XML

Affiliate Transactions (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Receivable from affiliate	$ 0	$ 831
Payable to affiliate	0	155
Cleco Power [Member]
Related Party Transaction [Line Items]
Receivable from affiliate	2,802	2,738
Payable to affiliate	7,332	7,945
Cleco Power [Member] | Cleco Corporation [Member]
Related Party Transaction [Line Items]
Payable to affiliate	900
Cleco Power [Member] | Support Group [Member]
Related Party Transaction [Line Items]
Receivable from affiliate	2,700
Payable to affiliate	6,400
Cleco Power [Member] | Other Affiliates [Member]
Related Party Transaction [Line Items]
Receivable from affiliate	0
Payable to affiliate	0
Cleco Power [Member] | Midstream [Member]
Related Party Transaction [Line Items]
Receivable from affiliate	$ 100

XML

Fair Value Accounting (Policies)

9 Months Ended

Sep. 30, 2011

Fair Value Accounting [Abstract]

Fair Value, Transfers, Policy

Cleco has a policy which states that transfers between Levels 1, 2, and 3 are recognized at the end of a reporting period.  During the nine months ended September 30, 2011, and the year ended December 31, 2010, Cleco did not experience any transfers between levels.

XML

LPSC Fuel Audit (Details) (USD $) In Billions	Sep. 30, 2011
Louisiana Public Service Commission Fuel Audit [Abstract]
Fuel Expenses Included in Audit	$ 3.2

XML

Debt

9 Months Ended

Sep. 30, 2011

Debt [Abstract]

Debt

Note 5 — Debt

Short-term Debt

At September 30, 2011, Cleco had no short-term debt outstanding compared to $150.0 million outstanding at December 31, 2010. The short-term debt outstanding at December 31, 2010, was a bank term loan Cleco Corporation entered into in February 2010.  The bank term loan had an interest rate of LIBOR plus 2.75% and was set to mature in February 2011.  In January 2011, Cleco extended the bank term loan to mature August 19, 2011 and lowered the interest rate to LIBOR plus 2.50% or ABR plus 1.50%.  On April 29, 2011, Cleco repaid the $150.0 million bank term loan.  As part of the repayment, Cleco paid $0.6 million for accrued interest on the term loan.

Cleco Power had no short-term debt outstanding at September 30, 2011, or December 31, 2010.

Long-term Debt

At September 30, 2011, Cleco’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.41 billion outstanding at December 31, 2010, of which $12.3 million was due within one year.  The long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco, long-term debt decreased $28.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011 and a $15.0 million decrease in credit facility draws outstanding.  

At September 30, 2011, Cleco Power’s long-term debt outstanding was $1.38 billion, of which $13.1 million was due within one year, compared to $1.40 billion outstanding at December 31, 2010, of which $12.3 million was due within one year.  The long-term debt due within one year at September 30, 2011, represents principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.  For Cleco Power, long-term debt decreased $13.3 million primarily due to $12.3 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2011.  

The $32.0 million solid waste disposal facility bonds due in 2038, which were issued by the Rapides Finance Authority for the benefit of Cleco Power in October 2008, were required to be mandatorily tendered by the bondholders for purchase on October 1, 2011, pursuant to the terms of the indenture. On October 3, 2011, Cleco Power purchased all $32.0 million outstanding bonds at face value plus $1.0 million of accrued interest.  In connection with the purchase, the interest rate of the bonds was converted to a weekly mode and will reset each week based on the SIFMA (Securities Industry and Financial Markets Association) index. The initial interest rate of the bonds at October 3, 2011, was 0.16% per annum. The bonds were issued by the Rapides Finance Authority in connection with a loan agreement between the Rapides Finance Authority and Cleco Power.  The bonds remain outstanding and Cleco Power will report the bonds as a $32.0 million long-term liability and a corresponding $32.0 million long-term asset.  Interest expense will continue to be recorded with a corresponding amount recorded as interest income, excluding amortization of debt issuance costs. Cleco Power has the option to remarket the bonds for new terms and new interest rates, both to be determined by market conditions.

Credit Facilities

On October 7, 2011, Cleco Corporation amended its credit facility agreement.  Under the amended agreement, Cleco Corporation’s maximum capacity was increased from $200.0 million to $250.0 million, the maturity date was extended to October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.50%, plus facility fees of 0.25%.  At September 30, 2011, Cleco Corporation had no borrowings outstanding under its existing credit facility.

On October 7, 2011, Cleco Power amended its credit facility agreement.  Under the amended agreement, the maturity date was extended to October 7, 2016, and the borrowing costs were lowered to equal LIBOR plus 1.275%, plus facility fees of 0.225% and the borrowing capacity remained $300.0 million.  At September 30, 2011, Cleco Power had no borrowings outstanding under its existing credit facility.

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Variable Interest Entities (Policies)

9 Months Ended

Sep. 30, 2011

Variable Interest Entities [Abstract]

Accounting Policy - Equity Investments

Cleco reports its investments in VIEs in accordance with the authoritative guidance.  Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.

Prior to April 30, 2011, Cleco Corporation also reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.

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Disclosures about Segments (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information [Line Items]
Electric operations	$ 324,532	$ 325,629	$ 823,484	$ 839,528
Tolling operations	9,133	11,153	16,137	23,016
Other operations	16,064	13,305	41,775	34,425
Electric customer credits	1,852	(6,314)	(3,405)	(6,314)
Affiliate revenue	0	119	202	1,426
Operating revenue	351,581	343,892	878,193	892,081
Depreciation	30,557	28,847	89,641	82,899
Interest charges	25,779	25,068	78,011	72,020
Interest income	509	128	794	369
Equity income (loss) from investees, before tax	(1)	2,494	62,051	39,212
Gain on toll settlement			0	148,402
Federal and state income tax expense (benefit)	24,737	30,155	73,451	127,411
Segment profit (loss)	65,842	49,612	165,205	234,768
Additions to long-lived assets	80,368	36,203	158,033	400,058
Equity investment in investees	13,081		13,081		86,732
Total segment assets	4,071,541		4,071,541		4,161,410
Reconciliation of segment profit to consolidated profit:
Segment profit (loss)	65,842	49,612	165,205	234,768
Unallocated items:
Preferred dividends requirements, net of tax	0	12	26	35
Preferred stock redemption costs, net of tax			112	0
Net income applicable to common stock	65,842	49,600	165,067	234,733
Cleco Power [Member]
Segment Reporting Information [Line Items]
Electric operations	324,532	325,629	823,484	839,528
Other operations	15,565	12,819	40,261	32,959
Electric customer credits	1,852	(6,314)	(3,405)	(6,314)
Affiliate revenue	347	343	1,041	1,029
Operating revenue	342,296	332,477	861,381	867,202
Depreciation	28,859	27,133	84,543	77,941
Interest charges	25,306	16,044	74,029	57,104
Interest income	276	117	557	351
Federal and state income tax expense (benefit)	31,656	26,568	61,935	58,299
Segment profit (loss)	53,833	52,335	119,557	123,584
Additions to long-lived assets	76,213	35,308	152,082	397,301
Equity investment in investees	13,073		13,073		13,073
Total segment assets	3,774,385		3,774,385		3,795,205
Reconciliation of segment profit to consolidated profit:
Segment profit (loss)	53,833	52,335	119,557	123,584
Midstream [Member]
Segment Reporting Information [Line Items]
Tolling operations	9,133	11,153	16,137	23,016
Other operations	1	1	8	2
Affiliate revenue		5	45	924
Operating revenue	9,134	11,159	16,190	23,942
Depreciation	1,457	1,446	4,370	4,334
Interest charges	752	1,109	1,963	5,972
Interest income	5		6
Equity income (loss) from investees, before tax		2,494	62,053	39,211
Gain on toll settlement				148,402
Federal and state income tax expense (benefit)	444	2,758	21,296	72,905
Segment profit (loss)	5,946	5,156	39,274	117,176
Additions to long-lived assets	4,074	454	5,202	1,576
Equity investment in investees					73,648
Total segment assets	234,537		234,537		316,165
Reconciliation of segment profit to consolidated profit:
Segment profit (loss)	5,946	5,156	39,274	117,176
Reconciling Items [Member]
Segment Reporting Information [Line Items]
Other operations	500	488	1,511	1,470
Affiliate revenue	13,448	11,290	37,544	34,783
Operating revenue	13,948	11,778	39,055	36,253
Depreciation	241	268	728	624
Interest charges	(308)	7,949	1,891	9,575
Interest income	199	44	103	649
Equity income (loss) from investees, before tax	(1)		(2)	1
Federal and state income tax expense (benefit)	(7,363)	830	(9,781)	(3,793)
Segment profit (loss)	6,063	(7,879)	6,374	(5,992)
Additions to long-lived assets	81	441	749	1,181
Equity investment in investees	9		9		11
Total segment assets	200,854		200,854		401,663
Reconciliation of segment profit to consolidated profit:
Segment profit (loss)	6,063	(7,879)	6,374	(5,992)
Eliminations [Member]
Segment Reporting Information [Line Items]
Other operations	(2)	(3)	(5)	(6)
Affiliate revenue	(13,795)	(11,519)	(38,428)	(35,310)
Operating revenue	(13,797)	(11,522)	(38,433)	(35,316)
Interest charges	29	(34)	128	(631)
Interest income	29	(33)	128	(631)
Federal and state income tax expense (benefit)		(1)	1
Equity investment in investees	(1)		(1)
Total segment assets	$ (138,235)		$ (138,235)		$ (351,623)

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Fair Value Accounting (Details) (USD $)	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Established guidelines for short-term investments to mitigate potential credit risk [Abstract]
Minimum assets under management in money market funds	$ 1,000,000,000
Minimum existence of investments (in years)	not less than two years
Maximum portfolios composition securities issued by foreign entities (in hundredths)	50.00%
Liability Description
Net current risk management liability	5,200,000
HedgingLiabilitiesCurrentGross	5,700,000
Current margin deposits	500,000	4,300,000
Option premiums	0
Institutional money market funds cash and cash equivalents	153,700,000
Institutional money market funds current restricted cash	3,600,000
Institutional money market funds non-current restricted cash	25,300,000
Cleco Power [Member]
Liability Description
Institutional money market funds cash and cash equivalents	139,500,000
Institutional money market funds current restricted cash	3,600,000
Institutional money market funds non-current restricted cash	25,200,000
Cleco Power [Member] | Carrying Value [Member]
Financial instruments not marked-to-market
Cash and cash equivalents	143,015,000	184,912,000
Restricted cash	28,807,000	40,951,000
Long-term debt, excluding debt issuance costs	1,376,567,000	1,388,836,000
Cleco Power [Member] | Estimated Fair Value [Member]
Financial instruments not marked-to-market
Cash and cash equivalents	143,015,000	184,912,000
Restricted cash	28,807,000	40,951,000
Long-term debt, excluding debt issuance costs	1,566,805,000	1,447,063,000
Cleco Power [Member] | Measured on a Recurring Basis [Member] | Estimated Fair Value [Member]
Asset Description
Energy market derivatives		97,000
Institutional money market funds	168,307,000	224,451,000
Total assets	168,307,000	224,548,000
Liability Description
Energy market derivatives	5,685,000	15,245,000
TreasuryRateLock	29,962,000
Total liabilities	35,647,000	15,245,000
Cleco Power [Member] | Measured on a Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Liability Description
Energy market derivatives	381,000	3,317,000
Total liabilities	381,000	3,317,000
Cleco Power [Member] | Measured on a Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member]
Asset Description
Energy market derivatives		97,000
Institutional money market funds	168,307,000	224,451,000
Total assets	168,307,000	224,548,000
Liability Description
Energy market derivatives	5,304,000	11,928,000
TreasuryRateLock	29,962,000
Total liabilities	35,266,000	11,928,000
Cleco Power [Member] | Maximum Amount of Loss [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentrations of credit risk through short-term investments	168,300,000
Concentrations of credit risk through short-term investments in cash	139,500,000
Concentrations of credit risk through short-term investments in restricted cash	28,800,000
Carrying Value [Member]
Financial instruments not marked-to-market
Cash and cash equivalents	158,232,000	191,128,000
Restricted cash	28,903,000	41,048,000
Long-term debt, excluding debt issuance costs	1,376,567,000	1,403,836,000
Preferred stock not subject to mandatory redemption		1,029,000
Estimated Fair Value [Member]
Financial instruments not marked-to-market
Cash and cash equivalents	158,232,000	191,128,000
Restricted cash	28,903,000	41,048,000
Long-term debt, excluding debt issuance costs	1,566,805,000	1,462,063,000
Preferred stock not subject to mandatory redemption		844,000
Measured on a Recurring Basis [Member] | Estimated Fair Value [Member]
Asset Description
Energy market derivatives		97,000
Institutional money market funds	182,603,000	229,748,000
Total assets	182,603,000	229,845,000
Liability Description
Energy market derivatives	5,685,000	15,245,000
TreasuryRateLock	29,962,000
Total liabilities	35,647,000	15,245,000
Maximum Amount of Loss [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentrations of credit risk through short-term investments	182,600,000
Concentrations of credit risk through short-term investments in cash	153,700,000
Concentrations of credit risk through short-term investments in restricted cash	28,900,000
Treasury Rate Locks [Member]
Interest rate cash flow hedge [Abstract]
Description of hedged item	interest rate exposure on coupon payments related to a forecasted debt issuance.
Notional amount of Treasury rate lock	150,000,000
Unrealized mark-to-market gain (loss) on treasury rate lock	(30,000,000)
Reference Rate As Of Contract Date	3.77%
Reference Rate As Of Period End	2.89%
Measured on a Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Liability Description
Energy market derivatives	381,000	3,317,000
Total liabilities	381,000	3,317,000
Measured on a Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member]
Asset Description
Energy market derivatives		97,000
Institutional money market funds	182,603,000	229,748,000
Total assets	182,603,000	229,845,000
Liability Description
Energy market derivatives	5,304,000	11,928,000
TreasuryRateLock	29,962,000
Total liabilities	35,266,000	11,928,000
Derivatives Not Designated As Hedging Instruments [Member] | Fuel Cost Hedges [Member]
Fair values of derivative instruments [Abstract]
Total	(5,685,000)	(15,148,000)
Derivatives Not Designated As Hedging Instruments [Member] | Fuel Cost Hedges [Member] | Risk Management Liability, Net [Member]
Fair values of derivative instruments [Abstract]
Current	(5,685,000)	(13,497,000)
Derivatives Not Designated As Hedging Instruments [Member] | Fuel Cost Hedges [Member] | Other Deferred Credits [Member]
Fair values of derivative instruments [Abstract]
Long-term		$ (1,651,000)

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Regulatory Assets and Liabilities (Policies)	9 Months Ended
	Sep. 30, 2011
Regulatory Assets and Liabilities [Abstract]
Regulatory Assets and Liabilities	Cleco Power follows the authoritative guidance on regulated operations, which allows utilities to capitalize or defer certain costs based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered through the ratemaking process.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities [Abstract]

Variable Interest Entities

Note 10 — Variable Interest Entities

Cleco reports its investments in VIEs in accordance with the authoritative guidance.  Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.

Prior to April 30, 2011, Cleco Corporation also reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.

Consolidated VIEs

Acadia

In February 2009, Cleco Power announced that it had chosen the acquisition of Acadia Unit 1 as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010.  Beginning in January 2010, Acadia operated the plant and served Cleco Power under a short-term tolling agreement covering Acadia Unit 1.  In February 2010, Cleco Power acquired Acadia Unit 1 and half of Acadia Power Station’s related common facilities and the tolling agreement was terminated.  In conjunction with this transaction, Acadia became 100% owned by Cajun, which prior to April 29, 2011, was 50% owned by APH and 50% owned by third parties.  For additional information regarding the Acadia Unit 1 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 1.”

In October 2009, Acadia and Entergy Louisiana announced that definitive agreements had been executed whereby Entergy Louisiana would acquire Acadia Unit 2.  On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 to Entergy Louisiana for $298.8 million.  Following the disposition, Acadia no longer owns any materials and supply inventory, property, plant and equipment, or land.  Acadia has minimal ongoing operations relating only to settling accounts receivable and accounts payable resulting from operations prior to the closing of the transaction and servicing indemnifications which Cleco assumed in the transaction.  In conjunction with the transaction, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Cleco Power continues to operate both units at the Acadia Power Station.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

The following tables contain summarized financial information for Cajun prior to the disposition of Acadia Unit 2.

(THOUSANDS)	AT DECEMBER 31, 2010
Current assets	$	7,133
Property, plant and equipment, net		203,793
Total assets	$	210,926
Current liabilities	$	1,950
Other liabilities		9,429
Partners’ capital		199,547
Total liabilities and partners’ capital	$	210,926

(THOUSANDS)	FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
Operating revenue		$	31,883
Operating expenses			30,566
Other income			3,671
Income before taxes		$	4,988

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)		2011	*		2010
Operating revenue	$	5,227		$	46,508
Operating expenses		5,914			54,011
Gain on sale of assets		71,422			82,023
Other income		929			3,902
Income before taxes	$	71,664		$	78,422
* The 2011 income statement includes only activity prior to the April 29, 2011, reconsolidation.

Other liabilities at December 31, 2010, represented an indemnification liability related to the Cleco Power transaction.  For additional information on Acadia’s indemnification liability, see Note 11 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

Prior to the reconsolidation, income tax expenses related to Cajun were recorded on APH’s financial statements.  For the four months ended April 30, 2011, income taxes related to Cajun on APH’s financial statements were $24.0 million.  For the three and nine months ended September 30, 2010, tax expenses recorded on APH’s financial statements were $1.0 million and $14.8 million, respectively.

In connection with the Entergy Louisiana transaction, APH has agreed to indemnify the third-party owners of Cajun and their affiliates against their share of Acadia’s contingent obligations related to the transaction.  For additional information on the Entergy Louisiana indemnification, see Note 11 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

Equity Method VIEs

Equity investment in investees at September 30, 2011, primarily represented Cleco Power’s $13.1 million investment in Oxbow.  Equity investments which are less than 100% owned by Cleco Innovations LLC represented less than $0.1 million of the total balance.

The following table presents the equity income (loss) from each investment accounted for using the equity method.   

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	-		$	2,494
Subsidiaries less than 100% owned by Cleco Innovations		(1	)		-
Total equity (loss) income	$	(1	)	$	2,494

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	62,053		$	39,211
Subsidiaries less than 100% owned by Cleco Innovations		(2	)		1
Total equity income	$	62,051		$	39,212

As a result of the disposition of Acadia Unit 2, Cleco’s 50% share of income from Cajun included $26.2 million of equity income that represents the 2007 investment impairment charge of $45.9 million, partially offset by $19.7 million of interest capitalized during the construction of Acadia.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

Oxbow

Oxbow is owned 50% by Cleco Power and 50% by SWEPCO and is accounted for as an equity method investment.  Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO.  Cleco’s current assessment of its maximum exposure to loss related to Oxbow at September 30, 2011, consisted of its equity investment of $13.1 million.  The table below presents the components of Cleco Power’s equity investment in Oxbow.

INCEPTION TO DATE (THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Purchase price	$	12,873	$	12,873
Cash contributions		200		200
Total equity investment in investee	$	13,073	$	13,073

The following table compares the carrying amount of Oxbow’s assets and liabilities with Cleco’s maximum exposure to loss related to its investment in Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Oxbow’s net assets/liabilities	$	26,146	$	26,146
Cleco Power’s 50% equity	$	13,073	$	13,073
Cleco’s maximum exposure to loss	$	13,073	$	13,073

The following tables contain summarized financial information for Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Current assets	$	685	$	583
Property, plant and equipment, net		23,422		23,597
Other assets		2,148		2,141
Total assets	$	26,255	$	26,321
Current liabilities	$	36	$	175
Other liabilities		73		-
Partners’ capital		26,146		26,146
Total liabilities and partners’ capital	$	26,255	$	26,321

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	382	$	245
Operating expenses		382		245
Income before taxes	$	-	$	-

	FOR THE NINE MONTHS ENDED SEPTEMBBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	880	$	564
Operating expenses		880		564
Income before taxes	$	-	$	-

Oxbow’s property, plant and equipment, net consists of land and lignite reserves.  The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station.  DHLC mines the lignite reserves at Oxbow through the Amended Lignite Mining Agreement.

Oxbow has no third-party agreements, guarantees, or other third-party commitments that contain obligations affecting Cleco Power’s investment in Oxbow.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation

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

Prior to April 30, 2011, Cleco reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2 to Entergy Louisiana, APH received 100% ownership in Acadia in exchange for its 50% ownership interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Following the disposition, Acadia’s assets, liabilities, revenues, expenses, and cash flows are presented on the corresponding line items of Cleco’s Condensed Consolidated Financial Statements, prospectively.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.  For additional information on the operations of these entities, see Note 10 — “Variable Interest Entities.”

Basis of Presentation

The condensed consolidated financial statements of Cleco Corporation and Cleco Power have been prepared pursuant to the rules and regulations of the SEC.  Accordingly, certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted; however, Cleco believes that the disclosures are adequate to make the information presented not misleading.

The year-end condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  The unaudited financial information included in the condensed consolidated financial statements of Cleco Corporation and Cleco Power reflects all adjustments of a normal recurring nature which are, in the opinion of the management of Cleco Corporation and Cleco Power, necessary for a fair statement of the financial position and the results of operations for the interim periods.  Information for interim periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery, and other factors, and is not indicative necessarily of the results that may be expected for the full fiscal year.  For additional information on recent authoritative guidance and its effect on financial results, see Note 2 — “Recent Authoritative Guidance.”

Property, Plant and Equipment

Property, plant and equipment consist primarily of regulated utility generation and energy transmission assets.  Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction.  Jointly owned assets are reflected in property, plant and equipment at Cleco Power’s share of the cost to construct or purchase the assets.  

Property, plant and equipment consist of:

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Regulated utility plants	$	3,604,938		$	3,552,054
Other		254,683			258,842
Total property, plant and equipment		3,859,621			3,810,896
Accumulated depreciation		(1,218,818	)		(1,162,456	)
Net property, plant and equipment	$	2,640,803		$	2,648,440

Restricted Cash

Various agreements to which Cleco is subject contain covenants that restrict its use of cash.  As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general corporate purposes.  Cleco’s restricted cash consisted of:  

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Power’s future storm restoration costs		24,652		25,992
Cleco Power’s renewable energy grant		600		-
Cleco Katrina/Rita’s storm recovery bonds		3,554		8,822
Cleco Power’s GO Zone bonds		-		6,137
Total restricted cash	$	28,903	$	41,048

Cleco Katrina/Rita has the right to bill and collect storm restoration costs from Cleco Power’s customers.  As cash is collected, it is restricted for payment of operating expenses, interest, and principal on storm recovery bonds.  During 2011, Cleco Katrina/Rita has collected $14.5 million net of operating expenses.  In March and September 2011, Cleco Katrina/Rita used $6.3 million and $6.0 million, respectively for scheduled storm recovery bond principal payments and $3.8 million and $3.7 million, respectively for related interest.  In 2011, Cleco Power received a renewable energy grant from the Louisiana Department of Natural Resources.  

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values.  Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance.  Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes under GAAP.  Other financial assets and liabilities, such as long-term debt, are reported at their carrying values at their date of issuance on the condensed consolidated balance sheets with their fair values disclosed without regard to the three levels.  For additional information about fair value levels, see Note 4 — “Fair Value Accounting.”

Risk Management

Market risk inherent in Cleco Power’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas on different energy exchanges.  

Commodity Market Price Risk

Cleco’s Energy Market Risk Management Policy authorizes the use of various derivative instruments, including exchange traded futures and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations in the price of power and natural gas.  Cleco applies the authoritative guidance as it relates to derivatives and hedging to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market.  Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting because Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements.  Cleco Power entered into certain financial transactions it considered economic hedges to mitigate the risk associated with a contract for fixed-price power provided to a wholesale customer through December 2010.  These transactions were marked-to-market with the resulting gain or loss recorded on the income statement as a component of operating revenue.  The contract expired on December 31, 2010 along with the economic hedges; therefore, no gain or loss related to the economic hedges was recorded during the three and nine months ended September 30, 2011.  For the three and nine months ended September 30, 2010, Cleco Power had realized losses of $0.3 million and $0.8 million and mark-to-market gains of $0.2 million for both periods recorded in other operations revenue.  

Cleco Power has entered into other positions to mitigate the volatility in customer fuel costs.  These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of energy risk management assets or liabilities.  Such gain or loss is deferred as a component of deferred fuel assets or liabilities.  When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers’ bills as a component of the fuel cost adjustment.  Based on market prices at September 30, 2011, and December 31, 2010, the net mark-to-market impact relating to these positions were losses of $5.7 million and $15.1 million, respectively.  Deferred losses relating to closed natural gas positions totaled $1.3 million and $1.6 million at September 30, 2011, and December 31, 2010, respectively.

Cleco Power maintains margin accounts with commodity brokers used to partially fund the acquisition of natural gas futures, options, and swap contracts.  These contracts/positions are used to mitigate the risks associated with the volatility in customer fuel costs noted above.  At September 30, 2011, and December 31, 2010, Cleco Power had deposited net collateral of $0.5 million and $4.3 million, respectively, to cover requirements relating to open natural gas futures, options, and swap positions.  The current and long-term portions of collateral are reported as a component of energy risk management assets or liabilities and other deferred credits, respectively.

Cleco and Cleco Power maintain a master netting agreement policy and monitor credit risk exposure through review of counterparty credit quality, counterparty credit exposure, and counterparty concentration levels.  Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and by requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Cleco Power has agreements in place with various counterparties that authorize the netting of financial buys and sells and contract payments to mitigate credit risk for transactions entered into for risk management purposes.  

Interest Rate Risk

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011 or the date of issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.  Management determined that the forecasted debt issuance is probable of occurring before or on November 14, 2011, and in an amount at least equal to the treasury rate lock contract’s notional amount.  When the forecasted debt issuance occurs and the treasury rate lock contract is settled, the effective portion of the settlement will be recognized in accumulated other comprehensive income and any ineffective portion will be reclassified into the income statement.  

For additional information on accounting for derivatives, see Note 4 — “Fair Value Accounting.”

Reclassifications

Certain reclassifications have been made to the 2010 financial statements to conform them to the presentation used in the 2011 financial statements.  These reclassifications had no effect on Cleco Corporation’s net income applicable to common stock or total common shareholder’s equity or Cleco Power’s net income or total member’s equity.

The Registrants determined that an error existed in the statement of cash flow methodology for determining non-cash transactions related to property, plant and equipment, specifically the dollar amount of property, plant and equipment acquisitions included in accounts payable.  This caused errors between the operating activities section and investing activities section for prior periods, including 2008, 2009, and 2010.

Cleco and Cleco Power’s Condensed Consolidated Statements of Cash Flows for the period ended September 30, 2010, have been adjusted to correct the presentation of cash flows related to accruals for property, plant and equipment.  These corrections had no impact on the Registrants’ financial condition or results of operations.  Management believes that these corrections did not have a material effect on the Registrants’ Condensed Consolidated Statements of Cash Flows. The corrections to the September 30, 2010 Condensed Consolidated Statements of Cash Flows are presented in the following table.

	CLECO						CLECO POWER
	FOR THE NINE MONTHS ENDED						FOR THE NINE MONTHS ENDED
	SEPTEMBER 30, 2010						SEPTEMBER 30, 2010
(THOUSANDS)	AS REPORTED			AS ADJUSTED			AS REPORTED			AS ADJUSTED
Accounts receivable	$	(49,329	)	$	(30,329	)	$	(50,579	)	$	(31,579	)
Accounts payable	$	(17,248	)	$	(13,277	)	$	(16,621	)	$	(12,137	)
Retainage payable	$	745		$	-		$	745		$	-
Net cash provided by operating activities	$	170,141		$	192,368		$	76,949		$	99,688
Additions to property, plant and equipment	$	(230,485	)	$	(252,711	)	$	(75,660	)	$	(98,399	)
Net cash used in investing activities	$	(212,592	)	$	(234,819	)	$	(49,780	)	$	(72,519	)
Net decrease in cash and cash equivalents	$	(77,357	)	$	(77,357	)	$	(110,729	)	$	(110,729	)
Cash and cash equivalents at the beginning of the period	$	145,193		$	145,193		$	138,113		$	138,113
Cash and cash equivalents at the end of the period	$	67,836		$	67,836		$	27,384		$	27,384
Accrued additions to property, plant and equipment	$	17,506		$	5,314		$	17,506		$	4,757

Earnings per Average Common Share

The following table shows the calculation of basic and diluted earnings per share.

							FOR THE THREE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	65,842					$	49,612
Deduct:  non-participating stock dividends (4.5% preferred stock)		-						12
Basic net income applicable to common stock	$	65,842		60,467,595	$	1.09	$	49,600		60,471,183	$	0.82
Effect of dilutive securities
Add:  stock option grants				20,441						26,680
Add:  restricted stock (LTICP)				385,275						327,435
Diluted net income applicable to common stock	$	65,842		60,873,311	$	1.08	$	49,600		60,825,298	$	0.82

							FOR THE NINE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	165,205					$	234,768
Deduct:  non-participating stock dividends (4.5% preferred stock)		26						35
Deduct:  non-participating stock redemption costs (4.5% preferred stock)		112						-
Basic net income applicable to common stock	$	165,067		60,549,860	$	2.73	$	234,733		60,405,388	$	3.89
Effect of dilutive securities
Add:  stock option grants				20,965						29,771
Add:  restricted stock (LTICP)				259,426						196,979
Diluted net income applicable to common stock	$	165,067		60,830,251	$	2.71	$	234,733		60,632,138	$	3.87

Stock option grants are excluded from the computation of diluted earnings per share if the exercise price is higher than the average market price.  There were no stock option grants excluded from the computation of diluted earnings per share for the three and nine months ended September 30, 2011 and 2010, due to the average market price being higher than the exercise prices of the stock options.  

Preferred Stock Redemption

On June 24, 2011, Cleco Corporation redeemed all 10,288 outstanding shares of its 4.5% preferred stock.  The redemption price was $101 per share plus accrued and unpaid dividends to the redemption date, or $101.296 per share.  As of the redemption date, no shares of 4.5% preferred stock were outstanding.  Holders are no longer entitled to dividends and all rights of such holders as shareholders of Cleco Corporation by reason of their ownership of such 4.5% preferred stock have ceased.

Stock-Based Compensation

At September 30, 2011, Cleco had two stock-based compensation plans:  the ESPP and the LTICP.  Substantially all employees, excluding officers and general managers, may choose to participate in the ESPP and purchase a limited amount of common stock at a discount through a stock option agreement.  Options or restricted shares of stock, known as non-vested stock as defined by the authoritative guidance on stock-based compensation, common stock equivalents, and stock appreciation rights may be granted to certain officers, key employees, or directors of Cleco Corporation and its subsidiaries pursuant to the LTICP.  

On January 28, 2011, Cleco granted 145,002 shares of non-vested stock to certain officers, key employees, and directors of Cleco Corporation and its subsidiaries pursuant to the LTICP.  On July 5, 2011, Cleco granted an additional 40,000 shares of non-vested stock to certain officers of Cleco Corporation and its subsidiaries pursuant to the LTICP.

Cleco and Cleco Power reported pre-tax compensation expense for their share-based compensation plans as shown in the following table:

	CLECO CORPORATION				CLECO POWER				CLECO CORPORATION				CLECO POWER
			FOR THE THREE MONTHS ENDED SEPTEMBER 30,								FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010		2011		2010		2011		2010
Equity classification
Non-vested stock	$	1,095	$	573	$	225	$	150	$	3,042	$	1,703	$	748	$	418
Stock options		69		13		-		-		105		38		-		-
Total equity classification	$	1,164	$	586	$	225	$	150	$	3,147	$	1,741	$	748	$	418
Liability classification
Common stock equivalent units	$	1,024	$	1,237	$	435	$	537	$	2,583	$	1,867	$	1,020	$	885
Total pre-tax compensation expense	$	2,188	$	1,823	$	660	$	687	$	5,730	$	3,608	$	1,768	$	1,303
Tax benefit (excluding income tax gross-up)	$	842	$	702	$	254	$	264	$	2,205	$	1,388	$	680	$	501

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Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees (Tables)

9 Months Ended

Sep. 30, 2011

Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees [Abstract]

Off-Balance Sheet Commitments

Cleco’s off-balance sheet commitments as of September 30, 2011, are summarized in the following table, and a discussion of the off-balance sheet commitments follows the table.  The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco’s financial condition.

			AT SEPTEMBER 30, 2011
	FACE				NET
(THOUSANDS)	AMOUNT		REDUCTIONS		AMOUNT
Cleco Corporation
Guarantee issued to Entergy Mississippi on behalf of Attala	$	500	$	-	$	500
Cleco Power
Obligations under standby letter of credit issued to the Louisiana Department of Labor		3,725		-		3,725
Total	$	4,225	$	-	$	4,225

Expected Termination Dates of Off-Balance Sheet Commitments and On-Balance Sheet Guarantees

The following table summarizes the expected termination dates of the off-balance sheet commitments and on-balance sheet guarantees discussed above:

							AT SEPTEMBER 30, 2011
			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
	NET								MORE
	AMOUNT		LESS THAN						THAN
(THOUSANDS)	COMMITTED		ONE YEAR		1-3 YEARS		3-5 YEARS		5 YEARS
Off-balance sheet commitments	$	4,225	$	3,725	$	-	$	-	$	500
On-balance sheet guarantees		33,449		-		29,443		-		4,006
Total	$	37,674	$	3,725	$	29,443	$	-	$	4,506

Future Equity Contributions

The following table reflects remaining future equity contributions.

(THOUSANDS)	CONTRIBUTION
Three months ending December 31, 2011	$	11,508
Years ending December 31,
2012		76,629
2013		36,225
2014		22,927
2015		21,904
Thereafter		20,808
Total	$	190,001

EquityInvestmentsWithImputedInterestRate

The table below contains the disclosures required by the authoritative guidelines for equity investments with an imputed interest rate.

(THOUSANDS)
Equity contributions, imputed interest rate 6%
Principal payment schedule above:	$	190,001
Less:  unamortized discount		22,098
Total	$	167,903

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Income Taxes

Note 7 — Income Taxes

The following table summarizes the effective income tax rates for Cleco Corporation and Cleco Power for the three- and nine-month periods ended September 30, 2011, and 2010.

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30,		FOR THE NINE MONTHS ENDED SEPTEMBER 30,
	2011	2010	2011	2010
Cleco Corporation	27.3%	37.8%	30.8%	35.2%
Cleco Power	37.0%	33.7%	34.1%	32.1%

Effective Tax Rates

For the three months ended September 30, 2011, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, and state tax expense.

For the nine months ended September 30, 2011, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, a reversal of the valuation allowance on the deferred tax asset for a capital loss carryforward due to capital gains generated in 2011, and state tax expense.

For the three months ended September 30, 2010, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, and state tax expense.

For the nine months ended September 30, 2010, the effective income tax rates for Cleco Corporation and Cleco Power were different than the federal statutory rate due to permanent tax deductions, flow-through of tax benefits associated with AFUDC equity, a valuation allowance on the deferred tax asset for a capital loss carryforward, an adjustment for Medicare Part D from health care legislation enacted in the first quarter of 2010, an adjustment for the implementation of new retail rates, and state tax expense.

Valuation Allowance

During 2010, a $1.2 million valuation allowance against the $2.7 million deferred tax asset on capital loss carryforwards was reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  This $1.2 million valuation allowance was reversed in the second quarter of 2011 due to capital gains generated in 2011 by the disposition of Acadia Unit 2.

Net Operating Losses

As of September 30, 2011, Cleco generated federal net operating losses and state net operating losses of $51.7 million and $45.2 million, respectively, which will begin to expire in 2031 and 2026.  Cleco Power generated federal net operating losses and state net operating losses of $48.2 million and $41.4 million, respectively, which will begin to expire in 2031 and 2026.  Cleco and Cleco Power consider it more likely than not that these losses will be utilized to reduce future income taxes.  Cleco and Cleco Power expect to utilize the entire net operating loss carryforward in 2012.

Uncertain Tax Positions

Effective January 1, 2007, Cleco adopted the provisions of the authoritative guidance on accounting for uncertain tax positions.  With this adoption, Cleco classified all interest related to uncertain tax positions as a component of interest payable and interest expense.  The total amounts of uncertain tax positions and related interest payable and interest expense, as reflected on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets and Statements of Income, are shown in the following tables:

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Interest payable
Cleco Corporation	$	43,972	$	41,018
Cleco Power	$	16,567	$	15,211

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011		2010
Interest charges
Cleco Corporation	$	93		$	2,518		$	2,954	$	6,504
Cleco Power	$	(420	)	$	(5,091	)	$	1,356	$	(2,613	)

The total liability for unrecognized tax benefits for Cleco Corporation and Cleco Power at September 30, 2011, and December 31, 2010, are shown in the following tables:

Cleco

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	102,785
Reduction for tax positions of current period		(3,116	)
Additions for tax positions of prior periods		10,585
Reduction for tax positions of prior periods		(9,546	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	100,708

Cleco Power

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	60,975
Reduction for tax positions of current period		(3,032	)
Additions for tax positions of prior periods		3,634
Reduction for tax positions of prior periods		(8,670	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	52,907

The federal income tax years that remain subject to examination by the IRS are 2001 through 2010.  The Louisiana state income tax years that remain subject to examination by the Louisiana Department of Revenue are 2001 through 2010.  In December 2010, Cleco deposited $52.2 million with the IRS associated with the years currently under audit, of which $45.9 million reduced accrued income taxes payable and $6.3 million reduced accrued interest payable.  In February 2011, Cleco deposited an additional $8.2 million with the IRS associated with the years currently under audit, which reduced income taxes payable.

Cleco is currently under audit by the IRS which has proposed adjustments to taxes for various issues, including but not limited to, depreciable tax lives, bonus depreciation, deductible storm costs, research and experimentation costs, domestic production activities deduction, and repair allowance deductions.  Cleco expects that the balance of unrecognized tax benefits as of September 30, 2011, will decrease by a maximum of $42.7 million for Cleco and $2.6 million for Cleco Power in the next 12 months as a result of reaching a settlement with the IRS.  This settlement will result in the payment of additional taxes, the adjustment of deferred taxes, and the recognition of tax benefits which will affect Cleco’s effective tax rate.

On October 13, 2011, Cleco settled the 2001 through 2003 audit cycle with the IRS.  For additional information on the settlement, see Note 16 — “Subsequent Event.”

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LPSC Fuel Audit

9 Months Ended

Sep. 30, 2011

Louisiana Public Service Commission Fuel Audit [Abstract]

LPSC Fuel Audit

Note 12 — LPSC Fuel Audit

The LPSC Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit of fuel adjustment clause filings will be performed not less than every other year.  Cleco Power’s last fuel audit was for the years 2001 and 2002.  Cleco Power currently has fuel adjustment clause filings for 2003 through 2010 subject to audit.  In March 2009, the LPSC proceeded with the audit of fuel adjustment clause filings for the years 2003 through 2008.  The total amount of fuel expenses included in the audit is approximately $3.2 billion.  Cleco Power has responded to several data requests from the LPSC.  These responses are currently under review by the LPSC.  The LPSC has not stated an amount of the fuel costs, if any, that would be disallowed and result in a refund to the customers.  Management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to this audit.  However, if a disallowance of fuel costs is ordered resulting in a refund, any such refund could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

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Disclosures about Segments

9 Months Ended

Sep. 30, 2011

Disclosures about Segments [Abstract]

Disclosures about Segments

Note 8 — Disclosures about Segments

Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by first-tier subsidiary.  Cleco’s reportable segments are Cleco Power and Midstream.  The reconciling items in the following tables consist of the holding company, a shared services subsidiary, two transmission interconnection facilities, and an investment subsidiary.  

Each reportable segment engages in business activities from which it earns revenue and incurs expenses.  Segment managers report periodically to Cleco’s Chief Executive Officer (the chief operating decision-maker) with discrete financial information and, at least quarterly, present discrete financial information to Cleco Corporation’s Board of Directors.  Each reportable segment prepared budgets for 2011 that were presented to and approved by Cleco Corporation’s Board of Directors.  

The financial results of Cleco’s segments are presented on an accrual basis.  Management evaluates the performance of its segments and allocates resources to them based on segment profit and the requirements to implement new strategic initiatives and projects to meet current business objectives.  Material intercompany transactions occur on a regular basis.  These intercompany transactions relate primarily to joint and common administrative support services provided by Support Group.

SEGMENT INFORMATION FOR THE THREE MONTHS ENDED SEPTEMBER 30,

	CLECO				RECONCILING
2011 (THOUSANDS)	POWER		MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	324,532	$	-	$	-		$	-		$	324,532
Tolling operations		-		9,133		-			-			9,133
Other operations		15,565		1		500			(2	)		16,064
Electric customer credits		1,852		-		-			-			1,852
Affiliate revenue		347		-		13,448			(13,795	)		-
Operating revenue	$	342,296	$	9,134	$	13,948		$	(13,797	)	$	351,581
Depreciation	$	28,859	$	1,457	$	241		$	-		$	30,557
Interest charges	$	25,306	$	752	$	(308	)	$	29		$	25,779
Interest income	$	276	$	5	$	199		$	29		$	509
Equity loss from investees, before tax	$	-	$	-	$	(1	)	$	-		$	(1	)
Federal and state income tax expense (benefit)	$	31,656	$	444	$	(7,363	)	$	-		$	24,737
Segment profit	$	53,833	$	5,946	$	6,063		$	-		$	65,842
Additions to long-lived assets	$	76,213	$	4,074	$	81		$	-		$	80,368
Equity investment in investees	$	13,073	$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385	$	234,537	$	200,854		$	(138,235	)	$	4,071,541

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	325,629		$	-	$	-		$	-		$	325,629
Tolling operations		-			11,153		-			-			11,153
Other operations		12,819			1		488			(3	)		13,305
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		343			5		11,290			(11,519	)	$	119
Operating revenue	$	332,477		$	11,159	$	11,778		$	(11,522	)	$	343,892
Depreciation	$	27,133		$	1,446	$	268		$	-		$	28,847
Interest charges	$	16,044		$	1,109	$	7,949		$	(34	)	$	25,068
Interest income	$	117		$	-	$	44		$	(33	)	$	128
Equity income from investees, before tax	$	-		$	2,494	$	-		$	-		$	2,494
Federal and state income tax expense (benefit)	$	26,568		$	2,758	$	830		$	(1	)	$	30,155
Segment profit (loss) (1)	$	52,335		$	5,156	$	(7,879	)	$	-		$	49,612
Additions to long-lived assets	$	35,308		$	454	$	441		$	-		$	36,203
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	49,612
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									12
	Net income applicable to common stock								$	49,600

SEGMENT INFORMATION FOR THE NINE MONTHS ENDED SEPTEMBER 30,

	CLECO					RECONCILING
2011 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	823,484		$	-	$	-		$	-		$	823,484
Tolling operations		-			16,137		-			-			16,137
Other operations		40,261			8		1,511			(5	)		41,775
Electric customer credits		(3,405	)		-		-			-			(3,405	)
Affiliate revenue		1,041			45		37,544			(38,428	)		202
Operating revenue	$	861,381		$	16,190	$	39,055		$	(38,433	)	$	878,193
Depreciation	$	84,543		$	4,370	$	728		$	-		$	89,641
Interest charges	$	74,029		$	1,963	$	1,891		$	128		$	78,011
Interest income	$	557		$	6	$	103		$	128		$	794
Equity income (loss) from investees, before tax	$	-		$	62,053	$	(2	)	$	-		$	62,051
Federal and state income tax expense (benefit)	$	61,935		$	21,296	$	(9,781	)	$	1		$	73,451
Segment profit (1)	$	119,557		$	39,274	$	6,374		$	-		$	165,205
Additions to long-lived assets	$	152,082		$	5,202	$	749		$	-		$	158,033
Equity investment in investees	$	13,073		$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385		$	234,537	$	200,854		$	(138,235	)	$	4,071,541
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	165,205
	Unallocated items:
	Preferred dividends requirements, net of tax									26
	Preferred stock redemption costs, net of tax									112
	Net income applicable to common stock								$	165,067

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	839,528		$	-	$	-		$	-		$	839,528
Tolling operations		-			23,016		-			-			23,016
Other operations		32,959			2		1,470			(6	)		34,425
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		1,029			924		34,783			(35,310	)		1,426
Operating revenue	$	867,202		$	23,942	$	36,253		$	(35,316	)	$	892,081
Depreciation	$	77,941		$	4,334	$	624		$	-		$	82,899
Interest charges	$	57,104		$	5,972	$	9,575		$	(631	)	$	72,020
Interest income	$	351		$	-	$	649		$	(631	)	$	369
Equity income from investees, before tax	$	-		$	39,211	$	1		$	-		$	39,212
Gain on toll settlement	$	-		$	148,402	$	-		$	-		$	148,402
Federal and state income tax expense (benefit)	$	58,299		$	72,905	$	(3,793	)	$	-		$	127,411
Segment profit (loss) (1)	$	123,584		$	117,176	$	(5,992	)	$	-		$	234,768
Additions to long-lived assets	$	397,301		$	1,576	$	1,181		$	-		$	400,058
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	234,768
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									35
	Net income applicable to common stock								$	234,733

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Effective Income Tax Rates

The following table summarizes the effective income tax rates for Cleco Corporation and Cleco Power for the three- and nine-month periods ended September 30, 2011, and 2010.

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30,		FOR THE NINE MONTHS ENDED SEPTEMBER 30,
	2011	2010	2011	2010
Cleco Corporation	27.3%	37.8%	30.8%	35.2%
Cleco Power	37.0%	33.7%	34.1%	32.1%

Liability for Unrecognized Tax Benefits

The total amounts of uncertain tax positions and related interest payable and interest expense, as reflected on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets and Statements of Income, are shown in the following tables:

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Interest payable
Cleco Corporation	$	43,972	$	41,018
Cleco Power	$	16,567	$	15,211

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011		2010
Interest charges
Cleco Corporation	$	93		$	2,518		$	2,954	$	6,504
Cleco Power	$	(420	)	$	(5,091	)	$	1,356	$	(2,613	)

The total liability for unrecognized tax benefits for Cleco Corporation and Cleco Power at September 30, 2011, and December 31, 2010, are shown in the following tables:

Cleco

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	102,785
Reduction for tax positions of current period		(3,116	)
Additions for tax positions of prior periods		10,585
Reduction for tax positions of prior periods		(9,546	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	100,708

Cleco Power

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at December 31, 2010	$	60,975
Reduction for tax positions of current period		(3,032	)
Additions for tax positions of prior periods		3,634
Reduction for tax positions of prior periods		(8,670	)
Reduction for settlement with taxing authority		-
Reduction for lapse of statute of limitations		-
Balance at September 30, 2011	$	52,907

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Pension Plan and Employee Benefits

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Pension Plan and Employee Benefits

Note 6 — Pension Plan and Employee Benefits

Pension Plan and Other Benefits Plan

Most employees hired before August 1, 2007 are covered by a non-contributory, defined benefit pension plan.  Benefits under the plan reflect an employee’s years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last 10 years of employment with Cleco Corporation.  Cleco Corporation’s policy is to base its contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the IRS’s full funding limitation.  During January 2011, Cleco made $60.0 million in discretionary contributions to the pension plan, with $40.1 million designated for the 2010 plan year and the remaining $19.9 million designated for the 2011 plan year.  Cleco Power expects to be required to make approximately $15.2 million in additional contributions to the pension plan over the next five years, none of which it expects will be required for the remainder of the 2011 or the 2012 plan year.  The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years.  The ultimate amount and timing of the contributions may be affected by changes in the discount rate, changes in the funding regulations, and actual returns on fund assets.  Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.  

Cleco Corporation’s retirees and their dependents are eligible to receive medical, dental, vision, and life insurance benefits (other benefits).  Cleco Corporation recognizes the expected cost of these other benefits during the periods in which the benefits are earned.

The components of net periodic pension and other benefit cost for the three and nine months ended September 30, 2011, and 2010, are as follows:

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	2,097		$	1,863		$	390		$	383
Interest cost		4,407			4,286			443			499
Expected return on plan assets		(6,161	)		(5,057	)		-			-
Amortizations:
Transition obligation		-			-			5			5
Prior period service cost		(18	)		(18	)		(51	)		(505	)
Net loss		1,389			789			246			250
Net periodic benefit cost	$	1,714		$	1,863		$	1,033		$	632

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	6,292		$	5,588		$	1,149		$	1,149
Interest cost		13,222			12,859			1,364			1,498
Expected return on plan assets		(18,484	)		(15,171	)		-			-
Amortizations:
Transition obligation		-			-			15			15
Prior period service cost		(54	)		(54	)		(154	)		(1,516	)
Net loss		4,167			2,367			758			751
Net periodic benefit cost	$	5,143		$	5,589		$	3,132		$	1,897

Since Cleco Power is the pension plan sponsor and the related trust holds the assets, the net unfunded status of the pension plan is reflected at Cleco Power.  The liability of Cleco Corporation’s other subsidiaries is transferred, with a like amount of assets, to Cleco Power monthly.  The expense of the pension plan related to Cleco Corporation’s other subsidiaries for the three and nine months ended September 30, 2011, was $0.5 million and $1.6 million, respectively, compared to $0.5 million and $1.4 million for the same periods in 2010.

Cleco Corporation is the plan sponsor for the other benefit plans.  There are no assets set aside in a trust, and the liabilities are reported on the individual subsidiaries’ financial statements.  At both September 30, 2011, and December 31, 2010, the current portion of the other benefits liability for Cleco was $3.0 million.  At both September 30, 2011, and December 31, 2010, the current portion of the other benefits liability for Cleco Power was $2.8 million.  The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, was $0.9 million and $2.7 million, respectively, compared to $0.5 million and $1.6 million for the same periods in 2010.  

In March 2010, the President signed the PPACA, a comprehensive health care law.  While the provisions of the PPACA are not effective immediately, the provisions could increase the Registrants’ retiree medical unfunded liability and related expenses before the effective date.  Management will continue to monitor this law and its possible impact on the Registrants.  

SERP

Certain Cleco executive officers are covered by the SERP.  The SERP is a non-qualified, non-contributory, defined benefit pension plan.  Benefits under the plan reflect an employee’s years of service, age at retirement, and the sum of the highest base salary paid out of the last five calendar years and the average of the three highest bonuses paid during the 60 months prior to retirement, reduced by benefits received from any other defined benefit pension plan, SERP Plan or Cleco contributions under the enhanced 401(k) Plan to the extent such contributions exceed the limits of the 401(k) Plan.  Cleco Corporation does not fund the SERP liability, but instead pays for current benefits out of the general funds available.  Cleco Power has formed a Rabbi Trust designated as the beneficiary for life insurance policies issued on the SERP participants.  Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ life insurance benefits, as well as future SERP payments.  However, since SERP is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency.  All SERP benefits are paid out of the general cash available of the respective companies from which the officer retired.  No contributions to the SERP were made during the nine months ended September 30, 2011, or 2010.  Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
Components of periodic benefit costs:
Service cost	$	392	$	453	$	1,175	$	1,148
Interest cost		526		541		1,578		1,591
Amortizations:
Prior period service cost		13		13		40		40
Net loss		235		253		705		695
Net periodic benefit cost	$	1,166	$	1,260	$	3,498	$	3,474

The SERP liabilities are reported on the individual subsidiaries’ financial statements.  At September 30, 2011, and December 31, 2010, the current portion of the SERP liability for Cleco was $1.8 million and $2.0 million, respectively.  At September 30, 2011, and December 31, 2010, the current portion of the SERP liability for Cleco Power was $0.7 million and $0.6 million, respectively.  The expense related to the SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income was $0.3 million and $0.9 million for the three and nine months ended September 30, 2011, respectively, compared to $0.4 million and $0.9 million for the same periods in 2010.  

401(k) Plan

Most employees are eligible to participate in the 401(k) Plan.  Under the 401(k) Plan, Cleco Corporation makes matching contributions and funds dividend reinvestments with cash.  Cleco’s 401(k) Plan expense for the three and nine months ended September 30, 2011, and 2010 is as follows:

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
401(k) Plan expense	$	945	$	925	$	2,998	$	2,784

Cleco Power is the plan sponsor for the 401(k) Plan.  The expense of the 401(k) Plan related to Cleco Corporation’s other subsidiaries for the three and nine months ended September 30, 2011, was $0.2 million and $0.7 million, respectively, compared to $0.2 million and $0.6 million for the same periods in 2010.  

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Condensed Consolidated Balance Sheets (Unaudited) Parenthetical (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Current assets
Customer accounts receivable, allowance for doubtful accounts	$ 1,177	$ 1,046
Other accounts receivable, allowance for doubtful accounts	1,985	2,409
Shareholders' equity
Preferred stock, not subject to mandatory redemption, par value (in dollars)	$ 100	$ 100
Preferred stock, not subject to mandatory redemption, authorized (in shares)	1,491,900	1,491,900
Preferred stock, not subject to mandatory redemption, issued (in shares)	0	10,288
Common stock, par value (in dollars)	$ 1	$ 1
Common stock, authorized (in shares)	100,000,000	100,000,000
Common stock, issued (in shares)	60,683,947	60,539,624
Common stock, outstanding (in shares)	60,273,131	60,526,126
Treasury stock, at cost (in shares)	410,816	13,498
CLECO POWER [Member]
Current assets
Customer accounts receivable, allowance for doubtful accounts	1,177	1,046
Other accounts receivable, allowance for doubtful accounts	$ 1,924	$ 2,349

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Recent Authoritative Guidance

9 Months Ended

Sep. 30, 2011

Recent Authoritative Guidance [Abstract]

Recent Authoritative Guidance

Note 2 — Recent Authoritative Guidance

The Registrants adopted, or will adopt, the recent authoritative guidance listed below on their respective effective dates.

In May 2010, FASB amended the authoritative guidance pertaining to compensation in order to clarify the issuance of stock options in currencies other than the ones in which employees are normally paid.  This amendment was effective for reporting periods that began on or after December 15, 2010.  The adoption of this amendment did not have an impact on the financial condition or results of operations of the Registrants.

In July 2010, FASB amended the authoritative guidance on receivables, which required companies to improve their disclosures about the credit quality of their financing receivables and the credit reserves held against them.  For public companies, the amendment was effective for interim and annual reporting periods ending on or after December 15, 2010, with specific items, such as allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010.  The adoption of this amendment did not have any effect on the financial condition or results of operations of the Registrants.

In December 2010, FASB amended the authoritative guidance on business combinations to expand supplemental pro forma disclosures and to require comparative prior period financial statement disclosures as if the combination occurred as of the beginning of the prior annual period.  The amendment was effective prospectively for business combination acquisition dates on or after the beginning of the first annual reporting period beginning on or after December 15, 2010.  The adoption of this amendment did not have any effect on the financial condition or results of operations of the Registrants.

In April 2011, FASB issued additional guidance to creditors for evaluating whether a modification or restructuring of a receivable is a troubled debt restructuring.  The implementation of this guidance was effective in the first interim or annual period beginning on or after June 15, 2011.  The adoption of this guidance did not have a material impact on the financial condition or results of operations of the Registrants.

In April 2011, FASB issued guidance to improve the accounting for repurchase agreements and other similar agreements.  Specifically, this guidance modifies the criteria for determining when these transactions would be accounted for as financings as opposed to sales or purchases with commitments to repurchase or resale.  The adoption of this guidance is effective in the first interim or annual period beginning on or after December 15, 2011.  The adoption of this guidance is not expected to have a material impact on the financial condition or results of operations of the Registrants.

In May 2011, FASB issued guidance on fair value measurements.  This guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS (International Financial Reporting Standards).  The adoption of this guidance is effective prospectively for interim and annual periods beginning after December 15, 2011.  The adoption of this guidance is not expected to have a material impact on the financial condition or results of operations of the Registrants.

In June 2011, FASB issued guidance on the presentation of comprehensive income. This guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The adoption of this guidance is effective for interim and annual periods beginning after December 15, 2011.  The adoption of this guidance will not have any impact on the financial condition or results of operations of the Registrants.

In September 2011, FASB revised the testing of goodwill for impairment.  The revision provides entities the option to first use qualitative factors to determine whether it is necessary to perform the quantitative two-step test.  The adoption of this guidance is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with some provisions for early adoption.  The adoption of this guidance will not have any impact on the financial condition or results of operations of the Registrants.

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Debt (Details) (USD $)	9 Months Ended			9 Months Ended		9 Months Ended					9 Months Ended
	Sep. 30, 2011	Oct. 03, 2011	Dec. 31, 2010	Sep. 30, 2011 Cleco Power [Member]	Dec. 31, 2010 Cleco Power [Member]	Sep. 30, 2011 Cleco Power [Member] Katrina/Rita Storm Recovery Bonds [Member]	Sep. 30, 2011 Cleco Power [Member] Credit Facility [Member]	Sep. 30, 2011 Bank Term Loan [Member]	Apr. 29, 2011 Bank Term Loan [Member]	Jan. 27, 2011 Bank Term Loan [Member]	Sep. 30, 2011 Katrina/Rita Storm Recovery Bonds [Member]	Sep. 30, 2011 Credit Facility [Member]
Short-term Debt [Line Items]
Short-term debt outstanding	$ 0		$ 150,000,000
Issuance date								February 2010.
Interest rate, prior to extension										LIBOR plus 2.75%
Maturity date , prior to extension								February 2011
Interest rate option 1, subsequent to extension									LIBOR plus 2.50%
Interest rate option 2, subsequent to extension									ABR plus 1.50%
Repayment of debt									150,000,000
Accrued interest as part of repayment									600,000
Short Term Debt Instrument Maturity Date								Aug. 19, 2011
Debt Instrument [Line Items]
Long-term debt outstanding	1,380,000,000		1,410,000,000	1,380,000,000	1,400,000,000
Long-term debt due within one year	13,108,000		12,269,000	13,108,000	12,269,000
Long-term debt decreased	28,300,000			13,300,000
Repayment of credit facility draws												15,000,000
Scheduled principal payment						12,300,000					12,300,000
Credit facility maximum borrowing capacity							300,000,000					250,000,000
Credit facility borrowing capacity at period end							300,000,000					200,000,000
Interest Rates Subsequent To Extension							libor plus 1.275% plus facility fees of 0.225%					libor plus 1.50% plus facility fees of 0.25%
Long Term Debt Instrument Maturity Date							Oct. 07, 2016					Oct. 07, 2016
DebtRepurchasedAndHeld
Stated interest rate of bonds repurchased and held (in hundredths)		0.16%
Face Value Of Bonds Repurchased		32,000,000
Accrued Interest On Purchased Bonds		1,000,000
Investment In Repurchased Bonds		$ 32,000,000

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Pension Plan and Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs

The components of net periodic pension and other benefit cost for the three and nine months ended September 30, 2011, and 2010, are as follows:

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	2,097		$	1,863		$	390		$	383
Interest cost		4,407			4,286			443			499
Expected return on plan assets		(6,161	)		(5,057	)		-			-
Amortizations:
Transition obligation		-			-			5			5
Prior period service cost		(18	)		(18	)		(51	)		(505	)
Net loss		1,389			789			246			250
Net periodic benefit cost	$	1,714		$	1,863		$	1,033		$	632

	PENSION BENEFITS						OTHER BENEFITS
	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010			2011			2010
Components of periodic benefit costs:
Service cost	$	6,292		$	5,588		$	1,149		$	1,149
Interest cost		13,222			12,859			1,364			1,498
Expected return on plan assets		(18,484	)		(15,171	)		-			-
Amortizations:
Transition obligation		-			-			15			15
Prior period service cost		(54	)		(54	)		(154	)		(1,516	)
Net loss		4,167			2,367			758			751
Net periodic benefit cost	$	5,143		$	5,589		$	3,132		$	1,897

SERP

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
Components of periodic benefit costs:
Service cost	$	392	$	453	$	1,175	$	1,148
Interest cost		526		541		1,578		1,591
Amortizations:
Prior period service cost		13		13		40		40
Net loss		235		253		705		695
Net periodic benefit cost	$	1,166	$	1,260	$	3,498	$	3,474

401(k) Plan Expense

Cleco’s 401(k) Plan expense for the three and nine months ended September 30, 2011, and 2010 is as follows:

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,				FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010
401(k) Plan expense	$	945	$	925	$	2,998	$	2,784

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Subsequent Event (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Subsequent Event [Abstract]
Miscellaneous other income tax payment	$ 13.0
Previously accrued federal and state interest expense to be reversed	30.9
Tax benefit	$ 11.9
Change in the effective tax rate (in hundreths)	4.55%

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets and Liabilities

Note 3 — Regulatory Assets and Liabilities

Cleco Power follows the authoritative guidance on regulated operations, which allows utilities to capitalize or defer certain costs based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered through the ratemaking process.  The following chart summarizes Cleco Power’s regulatory assets and liabilities at September 30, 2011, and December 31, 2010:

	AT SEPTEMBER 30,			AT DECEMBER 31,
(THOUSANDS)	2011			2010
Regulatory assets – deferred taxes, net	$	213,847		$	203,696
Deferred mining costs	$	19,755		$	21,666
Deferred interest costs		6,758			7,033
Deferred asset removal costs		814			768
Deferred postretirement plan costs		113,538			117,651
Deferred tree trimming costs		9,057			11,086
Deferred training costs		7,525			7,642
Deferred storm surcredits, net		9,080			10,633
Deferred construction carrying costs		12,416			18,830
Lignite mining agreement contingency		3,781			3,781
AFUDC equity gross-up		74,496			74,859
Deferred rate case costs		1,252			1,654
Deferred Acadia Unit 1 acquisition costs		2,997			3,076
Deferred IRP/RFP costs		625			977
Deferred AMI pilot costs		185			283
Total regulatory assets – other	$	262,279		$	279,939
Deferred construction carrying costs		(40,298	)		(87,875	)
Deferred fuel and purchased power		9,162			10,348
Total regulatory assets, net	$	444,990		$	406,108

Deferred Construction Carrying Costs

In February 2006, the LPSC approved Cleco Power’s plans to build Madison Unit 3.  Terms of the approval included authorization for Cleco Power to collect from customers an amount equal to 75% of the LPSC-jurisdictional portion of the carrying costs of capital during the construction phase of the unit.  In any calendar year during the construction period, the amount collected from customers was not to exceed 6.5% of Cleco Power’s projected retail revenues.  Cleco Power began collection of the carrying costs and established a regulatory liability in May 2006.  In October 2009, the LPSC voted unanimously to approve Cleco Power’s retail rate plan.  The retail rate plan established that Cleco Power return $183.2 million of carrying costs to customers over a five-year period and record a regulatory asset for all carrying costs incurred by Cleco Power above the actual amount collected from customers.  On February 12, 2010, Madison Unit 3 commenced commercial operation and the new rates became effective.  At that time, Cleco Power began returning the construction carrying costs to customers and amortizing the regulatory asset over a five-year period.  In March 2010, the LPSC issued an order changing the period of return from five years to four years and established that Cleco Power return approximately $166.4 million over the four-year period.  At September 30, 2011, the regulatory liability and the related regulatory asset were $40.3 million and $12.4 million, respectively.  As of September 30, 2011, Cleco Power had returned $126.1 million to customers.  At September 30, 2011, $33.3 million was due to be returned to customers within one year.

Deferred Fuel and Purchased Power Costs

The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to its customers substantially all such charges.  For the three months ended September 30, 2011, approximately 94% of Cleco Power’s total fuel cost was regulated by the LPSC, while the remainder was regulated by FERC.  

The $1.2 million decrease in the under-recovered costs was primarily due to a $9.5 million decrease in mark-to-market losses on natural gas positions, which was primarily due to the contractual expiration of certain positions.  Partially offsetting this decrease was $8.5 million in additional deferred fuel and purchased power costs.

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Income Taxes (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Effective Income Tax Rate [Line Items]
Effective income tax rate (in hundredths)	27.30%	37.80%	30.80%	35.20%
Capital Loss Carryforwards [Line Items]
Deferred tax asset					$ 2,700,000
Valuation allowance					1,200,000
Reversal of valuation allowance			1,200,000
Uncertain Tax Positions [Abstract]
Interest associated with uncertain tax positions	43,972,000		43,972,000		41,018,000
Interest expense related to uncertain tax positions	93,000	2,518,000	2,954,000	6,504,000
Liability for unrecognized tax benefits [Roll Forward]
Balance at Period Start			102,785,000
Reduction for tax positions of current period			3,116,000
Additions for tax positions of prior periods			10,585,000
Reduction for tax positions of prior periods			9,546,000
Balance at Period End	100,708,000		100,708,000		102,785,000
Deposits with the IRS			8,200,000		52,200,000
Maximum increase (decrease) in unrecognized tax benefits as a result of settlement with the IRS	(42,700,000)		(42,700,000)
Amounts deposited with the IRS - accrued income taxes payable					45,900,000
Amounts deposited with the IRS- accrued interest payable					6,300,000
Cleco Power [Member]
Effective Income Tax Rate [Line Items]
Effective income tax rate (in hundredths)	37.00%	33.70%	34.10%	32.10%
Uncertain Tax Positions [Abstract]
Interest associated with uncertain tax positions	16,567,000		16,567,000		15,211,000
Interest expense related to uncertain tax positions	(420,000)	(5,091,000)	1,356,000	(2,613,000)
Liability for unrecognized tax benefits [Roll Forward]
Balance at Period Start			60,975,000
Reduction for tax positions of current period			3,032,000
Additions for tax positions of prior periods			3,634,000
Reduction for tax positions of prior periods			8,670,000
Balance at Period End	52,907,000		52,907,000
Maximum increase (decrease) in unrecognized tax benefits as a result of settlement with the IRS	(2,600,000)		(2,600,000)
Cleco Power [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	48,200,000		48,200,000
Net operating loss carryforwards, expiration date			2031
Cleco Power [Member] | State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	41,400,000		41,400,000
Net operating loss carryforwards, expiration date			2026
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	51,700,000		51,700,000
Net operating loss carryforwards, expiration date			2031
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 45,200,000		$ 45,200,000
Net operating loss carryforwards, expiration date			2026

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2011

Summary of Significant Accounting Policies [Abstract]

Property Plant and Equipment

Property, plant and equipment consist of:

(THOUSANDS)	AT SEPTEMBER 30, 2011			AT DECEMBER 31, 2010
Regulated utility plants	$	3,604,938		$	3,552,054
Other		254,683			258,842
Total property, plant and equipment		3,859,621			3,810,896
Accumulated depreciation		(1,218,818	)		(1,162,456	)
Net property, plant and equipment	$	2,640,803		$	2,648,440

Restricted Cash Table

Cleco’s restricted cash consisted of:  

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Power’s future storm restoration costs		24,652		25,992
Cleco Power’s renewable energy grant		600		-
Cleco Katrina/Rita’s storm recovery bonds		3,554		8,822
Cleco Power’s GO Zone bonds		-		6,137
Total restricted cash	$	28,903	$	41,048

Reclassifications

The corrections to the September 30, 2010 Condensed Consolidated Statements of Cash Flows are presented in the following table.

	CLECO						CLECO POWER
	FOR THE NINE MONTHS ENDED						FOR THE NINE MONTHS ENDED
	SEPTEMBER 30, 2010						SEPTEMBER 30, 2010
(THOUSANDS)	AS REPORTED			AS ADJUSTED			AS REPORTED			AS ADJUSTED
Accounts receivable	$	(49,329	)	$	(30,329	)	$	(50,579	)	$	(31,579	)
Accounts payable	$	(17,248	)	$	(13,277	)	$	(16,621	)	$	(12,137	)
Retainage payable	$	745		$	-		$	745		$	-
Net cash provided by operating activities	$	170,141		$	192,368		$	76,949		$	99,688
Additions to property, plant and equipment	$	(230,485	)	$	(252,711	)	$	(75,660	)	$	(98,399	)
Net cash used in investing activities	$	(212,592	)	$	(234,819	)	$	(49,780	)	$	(72,519	)
Net decrease in cash and cash equivalents	$	(77,357	)	$	(77,357	)	$	(110,729	)	$	(110,729	)
Cash and cash equivalents at the beginning of the period	$	145,193		$	145,193		$	138,113		$	138,113
Cash and cash equivalents at the end of the period	$	67,836		$	67,836		$	27,384		$	27,384
Accrued additions to property, plant and equipment	$	17,506		$	5,314		$	17,506		$	4,757

Earnings Per Average Common Share

The following table shows the calculation of basic and diluted earnings per share.

							FOR THE THREE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	65,842					$	49,612
Deduct:  non-participating stock dividends (4.5% preferred stock)		-						12
Basic net income applicable to common stock	$	65,842		60,467,595	$	1.09	$	49,600		60,471,183	$	0.82
Effect of dilutive securities
Add:  stock option grants				20,441						26,680
Add:  restricted stock (LTICP)				385,275						327,435
Diluted net income applicable to common stock	$	65,842		60,873,311	$	1.08	$	49,600		60,825,298	$	0.82

							FOR THE NINE MONTHS ENDED SEPTEMBER 30,
					2011						2010
(THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)	INCOME		SHARES		PER SHARE AMOUNT		INCOME		SHARES		PER SHARE AMOUNT
Income from continuing operations	$	165,205					$	234,768
Deduct:  non-participating stock dividends (4.5% preferred stock)		26						35
Deduct:  non-participating stock redemption costs (4.5% preferred stock)		112						-
Basic net income applicable to common stock	$	165,067		60,549,860	$	2.73	$	234,733		60,405,388	$	3.89
Effect of dilutive securities
Add:  stock option grants				20,965						29,771
Add:  restricted stock (LTICP)				259,426						196,979
Diluted net income applicable to common stock	$	165,067		60,830,251	$	2.71	$	234,733		60,632,138	$	3.87

Stock Based Compensation

Cleco and Cleco Power reported pre-tax compensation expense for their share-based compensation plans as shown in the following table:

	CLECO CORPORATION				CLECO POWER				CLECO CORPORATION				CLECO POWER
			FOR THE THREE MONTHS ENDED SEPTEMBER 30,								FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010		2011		2010		2011		2010		2011		2010
Equity classification
Non-vested stock	$	1,095	$	573	$	225	$	150	$	3,042	$	1,703	$	748	$	418
Stock options		69		13		-		-		105		38		-		-
Total equity classification	$	1,164	$	586	$	225	$	150	$	3,147	$	1,741	$	748	$	418
Liability classification
Common stock equivalent units	$	1,024	$	1,237	$	435	$	537	$	2,583	$	1,867	$	1,020	$	885
Total pre-tax compensation expense	$	2,188	$	1,823	$	660	$	687	$	5,730	$	3,608	$	1,768	$	1,303
Tax benefit (excluding income tax gross-up)	$	842	$	702	$	254	$	264	$	2,205	$	1,388	$	680	$	501

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Disclosures about Segments (Tables)

9 Months Ended

Sep. 30, 2011

Disclosures about Segments [Abstract]

Segment Information

SEGMENT INFORMATION FOR THE THREE MONTHS ENDED SEPTEMBER 30,

	CLECO				RECONCILING
2011 (THOUSANDS)	POWER		MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	324,532	$	-	$	-		$	-		$	324,532
Tolling operations		-		9,133		-			-			9,133
Other operations		15,565		1		500			(2	)		16,064
Electric customer credits		1,852		-		-			-			1,852
Affiliate revenue		347		-		13,448			(13,795	)		-
Operating revenue	$	342,296	$	9,134	$	13,948		$	(13,797	)	$	351,581
Depreciation	$	28,859	$	1,457	$	241		$	-		$	30,557
Interest charges	$	25,306	$	752	$	(308	)	$	29		$	25,779
Interest income	$	276	$	5	$	199		$	29		$	509
Equity loss from investees, before tax	$	-	$	-	$	(1	)	$	-		$	(1	)
Federal and state income tax expense (benefit)	$	31,656	$	444	$	(7,363	)	$	-		$	24,737
Segment profit	$	53,833	$	5,946	$	6,063		$	-		$	65,842
Additions to long-lived assets	$	76,213	$	4,074	$	81		$	-		$	80,368
Equity investment in investees	$	13,073	$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385	$	234,537	$	200,854		$	(138,235	)	$	4,071,541

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	325,629		$	-	$	-		$	-		$	325,629
Tolling operations		-			11,153		-			-			11,153
Other operations		12,819			1		488			(3	)		13,305
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		343			5		11,290			(11,519	)	$	119
Operating revenue	$	332,477		$	11,159	$	11,778		$	(11,522	)	$	343,892
Depreciation	$	27,133		$	1,446	$	268		$	-		$	28,847
Interest charges	$	16,044		$	1,109	$	7,949		$	(34	)	$	25,068
Interest income	$	117		$	-	$	44		$	(33	)	$	128
Equity income from investees, before tax	$	-		$	2,494	$	-		$	-		$	2,494
Federal and state income tax expense (benefit)	$	26,568		$	2,758	$	830		$	(1	)	$	30,155
Segment profit (loss) (1)	$	52,335		$	5,156	$	(7,879	)	$	-		$	49,612
Additions to long-lived assets	$	35,308		$	454	$	441		$	-		$	36,203
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	49,612
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									12
	Net income applicable to common stock								$	49,600

SEGMENT INFORMATION FOR THE NINE MONTHS ENDED SEPTEMBER 30,

	CLECO					RECONCILING
2011 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	823,484		$	-	$	-		$	-		$	823,484
Tolling operations		-			16,137		-			-			16,137
Other operations		40,261			8		1,511			(5	)		41,775
Electric customer credits		(3,405	)		-		-			-			(3,405	)
Affiliate revenue		1,041			45		37,544			(38,428	)		202
Operating revenue	$	861,381		$	16,190	$	39,055		$	(38,433	)	$	878,193
Depreciation	$	84,543		$	4,370	$	728		$	-		$	89,641
Interest charges	$	74,029		$	1,963	$	1,891		$	128		$	78,011
Interest income	$	557		$	6	$	103		$	128		$	794
Equity income (loss) from investees, before tax	$	-		$	62,053	$	(2	)	$	-		$	62,051
Federal and state income tax expense (benefit)	$	61,935		$	21,296	$	(9,781	)	$	1		$	73,451
Segment profit (1)	$	119,557		$	39,274	$	6,374		$	-		$	165,205
Additions to long-lived assets	$	152,082		$	5,202	$	749		$	-		$	158,033
Equity investment in investees	$	13,073		$	-	$	9		$	(1	)	$	13,081
Total segment assets	$	3,774,385		$	234,537	$	200,854		$	(138,235	)	$	4,071,541
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	165,205
	Unallocated items:
	Preferred dividends requirements, net of tax									26
	Preferred stock redemption costs, net of tax									112
	Net income applicable to common stock								$	165,067

	CLECO					RECONCILING
2010 (THOUSANDS)	POWER			MIDSTREAM		ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	839,528		$	-	$	-		$	-		$	839,528
Tolling operations		-			23,016		-			-			23,016
Other operations		32,959			2		1,470			(6	)		34,425
Electric customer credits		(6,314	)		-		-			-			(6,314	)
Affiliate revenue		1,029			924		34,783			(35,310	)		1,426
Operating revenue	$	867,202		$	23,942	$	36,253		$	(35,316	)	$	892,081
Depreciation	$	77,941		$	4,334	$	624		$	-		$	82,899
Interest charges	$	57,104		$	5,972	$	9,575		$	(631	)	$	72,020
Interest income	$	351		$	-	$	649		$	(631	)	$	369
Equity income from investees, before tax	$	-		$	39,211	$	1		$	-		$	39,212
Gain on toll settlement	$	-		$	148,402	$	-		$	-		$	148,402
Federal and state income tax expense (benefit)	$	58,299		$	72,905	$	(3,793	)	$	-		$	127,411
Segment profit (loss) (1)	$	123,584		$	117,176	$	(5,992	)	$	-		$	234,768
Additions to long-lived assets	$	397,301		$	1,576	$	1,181		$	-		$	400,058
Equity investment in investees (2)	$	13,073		$	73,648	$	11		$	-		$	86,732
Total segment assets (2)	$	3,795,205		$	316,165	$	401,663		$	(351,623	)	$	4,161,410
(1)Reconciliation of segment profit to consolidated profit:	Segment profit								$	234,768
(2)Balances as of December 31, 2010	Unallocated items:
	Preferred dividends requirements, net of tax									35
	Net income applicable to common stock								$	234,733

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Pension Plan and Employee Benefits (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
401(k) Plan [Abstract]
401(k) Plan expense	$ 945,000	$ 925,000	$ 2,998,000	$ 2,784,000
Cleco Power [Member] | Other Benefits [Member]
Amortizations:
Net periodic benefit cost	900,000	500,000	2,700,000	1,600,000
Current portion of other benefits liability	2,800,000		2,800,000		2,800,000
Cleco Power [Member] | SERP [Member]
Amortizations:
Net periodic benefit cost	300,000	400,000	900,000	900,000
Current portion of SERP liability	700,000		700,000		600,000
Other Subsidiaries [Member]
401(k) Plan [Abstract]
401(k) Plan expense	200,000	200,000	700,000	600,000
Other Subsidiaries [Member] | Pension Plan [Member]
Amortizations:
Net periodic benefit cost	500,000	500,000	1,600,000	1,400,000
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
General information			Benefits under the plan reflect an employee's years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last 10 years of employment with Cleco Corporation.
Discretionary contributions to pension plan			60,000,000
Contributions designated for prior plan year			40,100,000
Contributions designated for current plan year			19,900,000
Discretionary contributions to pension plans during the next five years	15,200,000		15,200,000
Components of periodic benefit costs
Service cost	2,097,000	1,863,000	6,292,000	5,588,000
Interest cost	4,407,000	4,286,000	13,222,000	12,859,000
Expected return on plan assets	(6,161,000)	(5,057,000)	(18,484,000)	(15,171,000)
Amortizations:
Prior period service cost	(18,000)	(18,000)	(54,000)	(54,000)
Net loss	1,389,000	789,000	4,167,000	2,367,000
Net periodic benefit cost	1,714,000	1,863,000	5,143,000	5,589,000
Other Benefits [Member]
Components of periodic benefit costs
Service cost	390,000	383,000	1,149,000	1,149,000
Interest cost	443,000	499,000	1,364,000	1,498,000
Amortizations:
Transition obligation	5,000	5,000	15,000	15,000
Prior period service cost	(51,000)	(505,000)	(154,000)	(1,516,000)
Net loss	246,000	250,000	758,000	751,000
Net periodic benefit cost	1,033,000	632,000	3,132,000	1,897,000
Current portion of other benefits liability	3,000,000		3,000,000		3,000,000
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
General information			Benefits under the plan reflect an employee's years of service, age at retirement, and the sum of the highest base salary paid out of the last five calendar years and the average of the three highest bonuses paid during the 60 months prior to retirement, reduced by benefits received from any other defined benefit pension plan, SERP Plan or Cleco contributions under the enhanced 401(k) Plan to the extent such contributions exceed the limits of the 401(k) Plan.
Components of periodic benefit costs
Service cost	392,000	453,000	1,175,000	1,148,000
Interest cost	526,000	541,000	1,578,000	1,591,000
Amortizations:
Prior period service cost	13,000	13,000	40,000	40,000
Net loss	235,000	253,000	705,000	695,000
Net periodic benefit cost	1,166,000	1,260,000	3,498,000	3,474,000
Current portion of SERP liability	$ 1,800,000		$ 1,800,000		$ 2,000,000

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Fair Value Accounting (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Accounting [Abstract]

Fair Value By Balance Sheet Grouping

The following charts summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments subject to fair value accounting.

Cleco

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	158,232	$	158,232	$	191,128	$	191,128
Restricted cash	$	28,903	$	28,903	$	41,048	$	41,048
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,403,836	$	1,462,063
Preferred stock not subject to mandatory redemption	$	-	$	-	$	1,029	$	844

Cleco Power

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	143,015	$	143,015	$	184,912	$	184,912
Restricted cash	$	28,807	$	28,807	$	40,951	$	40,951
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,388,836	$	1,447,063

Fair Value of Financial Assets and Liabilities Measured On A Recurring Basis

The tables below disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis and within the scope of the authoritative guidance for fair value measurements and disclosures.

Cleco

	CLECO CONSOLIDATED FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		182,603		-		182,603		-		229,748		-		229,748		-
Total assets	$	182,603	$	-	$	182,603	$	-	$	229,845	$	-	$	229,845	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

Cleco Power

	CLECO POWER FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		168,307		-		168,307		-		224,451		-		224,451		-
Total assets	$	168,307	$	-	$	168,307	$	-	$	224,548	$	-	$	224,548	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

Fair Values of Derivative Instruments

The following table presents the fair values of derivative instruments and their respective line items as recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as of September 30, 2011, and December 31, 2010:

	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
	LIABILITY DERIVATIVES
(THOUSANDS) FAIR VALUE	BALANCE SHEET LINE ITEM	AT SEPTEMBER 30, 2011			DECEMBER 31, 2010
Commodity contracts
Fuel cost hedges:
Current	Energy risk management liability, net	$	(5,685	)	$	(13,497	)
Long-term	Other deferred credits		-			(1,651	)
Total		$	(5,685	)	$	(15,148	)

Effect of Derivatives On Consolidated Statements of Income

The following table presents the effect of derivatives not designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

		FOR THE THREE MONTHS ENDED							FOR THE NINE MONTHS ENDED
		SEPTEMBER 30, 2011			SEPTEMBER 30, 2010				SEPTEMBER 30, 2011			SEPTEMBER 30, 2010
(THOUSANDS)	GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES
Commodity contracts
Economic hedges	Other operations revenue	$	-		$	(157	) (1)	Other operations revenue	$	-		$	(648	) (2)
Fuel cost hedges(3)	Fuel used for electric generation		(5,678	)		(10,182	)	Fuel used for electric generation		(14,675	)		(32,397	)
Total		$	(5,678	)	$	(10,339	)		$	(14,675	)	$	(33,045	)
(1)For the three months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(2)For the nine months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(3)In accordance with the authoritative guidance for regulated operations, an additional $5.7 million of unrealized losses and $1.3 million of deferred losses associated with fuel cost hedges are reported in Accumulated Deferred Fuel on the balance sheet as of September 30, 2011, compared to $15.1 million of unrealized losses and $1.6 million of deferred losses associated with fuel cost hedges as of December 31, 2010. As gains and losses are realized in future periods, they will be recorded as Fuel Used for Electric Generation on the Income Statement.

The following table presents the effect of derivatives designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(376	)	$	(194	)*
Treasury rate locks	$	(29,962	)	$	89	*	$	-		$	41	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

	FOR THE NINE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(717	)	$	(592	)*
Treasury rate locks	$	(29,962	)	$	267	*	$	-		$	125	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

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Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

9 Months Ended

Sep. 30, 2011

Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees [Abstract]

Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Note 11 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

Devil’s Swamp

In October 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study (RI/FS) from the EPA.  The special notice requested that Cleco Corporation and Cleco Power, along with many other listed PRPs, enter into negotiations with the EPA for the performance of an RI/FS at an area known as the Devil’s Swamp Lake site just northwest of Baton Rouge, Louisiana.  The EPA has identified Cleco as one of many companies sending PCB wastes for disposal to the site.  The Devil’s Swamp Lake site has been proposed to be added to the National Priorities List (NPL) based on the release of PCBs to fisheries and wetlands located on the site.  The EPA has yet to make a final determination on whether to add Devil’s Swamp Lake site to the NPL.  The PRPs began discussing a potential proposal to the EPA in February 2008.  Negotiations among the PRPs and the EPA are ongoing in regard to the RI/FS for the Devil’s Swamp Lake site, with little progress having been made since February 2008.  Since this investigation is in the preliminary stages, management is unable to determine whether the costs associated with possible remediation of the facility site, if any, will have a material adverse effect on the Registrants’ financial condition, results of operations, or cash flows.

Discrimination Complaints

On December 11, 2009, a complaint was filed in the U.S. District Court for the Western District of Louisiana (the Court) on behalf of eight current employees and four former employees alleging that Cleco discriminated against each of them on the basis of race.  Each is seeking various remedies provided under applicable statutes prohibiting racial discrimination in the workplace, and together, the plaintiffs seek monetary compensation exceeding $35.0 million.  On July 29, 2010, the plaintiffs moved to add an additional current employee alleging that Cleco had discriminated on the basis of race.  The plaintiff seeks compensation of no less than $2.5 million and became the thirteenth plaintiff.  On April 13, 2011, Cleco entered into a settlement with one of the current employees which resulted in a dismissal of one of the thirteen cases with prejudice.  On September 22, 2011 the Court ruled on Cleco’s summary judgment motions that had been pending for the last year.  The judge granted and denied the motions in part, with the end result that eleven out of twelve of the remaining plaintiffs have at least one claim remaining.  The Court has severed the cases of the eleven remaining plaintiffs for further discovery and proceedings, and if necessary, trial.  None of these matters have been set for trial.  In view of the uncertainty of the claims, management is not able to predict or give a reasonable estimate of the possible range, if any, of these claims.

On September 23, 2010, the New Orleans Field Office of the U.S. Equal Employment Opportunity Commission (EEOC) issued its determination that there is reason to believe that violations of Title VII of the Civil Rights Act of 1964 had occurred at one of Cleco’s training facilities on October 5, 2007.  In its initial determination, the EEOC suggested that Cleco pay the charging party $0.1 million in satisfaction of any compensatory or punitive damages.  Under EEOC procedures, Cleco pursued conciliation efforts to resolve the charge which resulted in a complete settlement with the charging party and the EEOC.  

City of Opelousas

On March 9, 2010, a complaint was filed in the 27th Judicial District Court of St. Landry Parish, State of Louisiana, on behalf of three Cleco Power customers in Opelousas, Louisiana.  The complaint alleges that Cleco Power overcharged the plaintiffs by applying to customers in Opelousas the same retail rates as Cleco Power applies to all of its retail customers.  The plaintiffs allege that Cleco Power should have established, solely for customers in Opelousas, retail rates that are separate and distinct from the retail rates that apply to other customers of Cleco Power and that Cleco Power should not collect from customers in Opelousas the storm surcharge approved by the LPSC following Hurricanes Katrina and Rita.  Cleco Power currently operates in Opelousas pursuant to a franchise granted to Cleco Power by the City of Opelousas in 1986 and an operating and franchise agreement dated May 14, 1991, pursuant to which Cleco Power operates its own electric facilities and leases and operates electric facilities owned by the City of Opelousas.  In April 2010, Cleco Power filed a petition with the LPSC appealing to its expertise in declaring that the ratepayers of Opelousas have been properly charged the rates that are applicable to Cleco Power’s retail customers and that no overcharges have been collected.  In addition, Cleco Power removed the purported class action lawsuit filed on behalf of Opelousas electric customers from the state court to the U.S. District Court for the Western District of Louisiana in April 2010, so that it could be properly addressed under the terms of the Class Action Fairness Act.  On May 11, 2010, a second class action lawsuit was filed in the 27th Judicial District Court of St. Landry Parish, State of Louisiana, repeating the allegations of the first complaint, which was submitted on behalf of 249 Opelousas residents.  Cleco Power has responded in the same manner as with the first class action lawsuit.  On September 29, 2010, the federal court remanded both cases to the state court in which they were originally filed for further proceedings.  On January 21, 2011, the presiding judge in the state court proceeding ruled that the jurisdiction to hear the two class actions resides in the state court and not with the LPSC as argued by both Cleco and the LPSC Staff.  Both Cleco and the LPSC Staff appealed this ruling to the Third Circuit Court of Appeals for the State of Louisiana (Third Circuit).  On September 9, 2011, the Third Circuit denied both appeals.  On October 10, 2011, both Cleco and the LPSC appealed the Third Circuit’s ruling to the Louisiana Supreme Court.  On February 7, 2011, the administrative law judge in the LPSC proceeding ruled that the LPSC has jurisdiction to decide the claims raised by the class action plaintiffs.  The customers have not stated an amount of overcharges they seek to recover.  In view of the uncertainty of the claims, management is not able to predict or give a reasonable estimate of the possible range, if any, of these claims.

Madison Unit 3

In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Madison Unit 3.  Construction of Madison Unit 3 began in May 2006.  In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract, which contract has subsequently been amended by the parties.  The project achieved commercial operations on February 12, 2010, whereby Cleco Power accepted care, custody, and control of the unit.  Cleco Power and Shaw submitted various claims, relating to the Amended EPC Contract, to arbitration.  On April 30, 2010, Shaw filed a demand for arbitration asserting claims of $32.0 million including impacts due to the 2008 hurricane force majeure, alleged excess fuel moisture, intake water quality and a river embankment slope failure, and the associated recovery of schedule related liquidated damages withheld by Cleco Power.  In May 2010, Cleco Power issued to Shaw a notice of default relating to Shaw’s inability to meet certain material obligations under the Amended EPC Contract.  Furthermore, as a result of Shaw filing the demand for arbitration, certain claims exceeded a $1.0 million threshold, triggering an unwind of certain fuel-related matters included in a prior settlement between the parties, Amendment No. 4, and Cleco demanded an associated payment of $19.0 million.  In February 2011, Cleco drew on the Shaw letter of credit in an amount of $19.0 million for amounts relating to the unwind.  Certain of these matters were argued in arbitration hearings which concluded on June 8, 2011.  On June 24, 2011, Cleco and Shaw each submitted their proposed resolutions to all of the matters in dispute in this arbitration proceeding.  Shaw submitted that Cleco owed $32.5 million in satisfaction of all of such matters.  Cleco submitted that it owed Shaw $4.0 million.  On August 5, 2011, the arbitrator announced his decision in favor of Shaw’s claims of Cleco Power owing Shaw $32.5 million (including the return of the amounts drawn on Shaw’s letter of credit).  Cleco Power paid this amount on August 22, 2011, which was included as a cost of Madison Unit 3 and reflected as property, plant and equipment.  

Shaw has not reached project completion as defined in the Amended EPC Contract, as various performance tests, the reliability test, and specified boiler performance criteria have not been met.  Under the Amended EPC Contract, Shaw must correct the identified items, complete the performance guarantee tests, meet a 30-day reliability performance test, and correct certain warranty issues to meet final acceptance, or pay certain liquidated damages and financially settle incomplete work.  The disputed items relating to the liquidated damages for Shaw’s inability to meet performance guarantees, as well as for completion of minor or warranty work, were bifurcated from the arbitration proceedings and remain outstanding.  These matters may be resolved through a second arbitration proceeding or potentially settled.

LPSC Fuel Audit

The LPSC is currently auditing Cleco Power’s fuel expenditures for the years 2003 through 2008 which includes approximately $3.2 billion of fuel expenses.  Cleco Power has responded to several sets of data requests and the responses are currently under review.  The LPSC has not stated an amount of the fuel costs, if any, that would be disallowed and result in a refund to Cleco Power’s customers.  As such, management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to this audit.  However, if a disallowance of fuel costs is ordered resulting in a refund, any such refund could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Other

Cleco is involved in various litigation matters, including regulatory, environmental, and administrative proceedings before various courts, regulatory commissions, arbitrators, and governmental agencies regarding matters arising in the ordinary course of business.  The liability Cleco may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued.  Management regularly analyzes current information and, as of September 30, 2011, believes the range of probable and reasonably estimable liabilities based on the eventual disposition of these matters is between $2.0 million and $6.0 million.  

Off-Balance Sheet Commitments

Cleco Corporation and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Corporation’s subsidiaries and equity investees (affiliates).  Cleco Corporation and Cleco Power also have agreed to contractual terms that require them to pay third parties if certain triggering events occur.  These contractual terms generally are defined as guarantees in the authoritative guidance.  

Cleco Corporation entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations.  If Cleco Corporation had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco Corporation’s Condensed Consolidated Balance Sheets because management has determined that Cleco’s affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco will be required.  Cleco’s off-balance sheet commitments as of September 30, 2011, are summarized in the following table, and a discussion of the off-balance sheet commitments follows the table.  The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco’s financial condition.

			AT SEPTEMBER 30, 2011
	FACE				NET
(THOUSANDS)	AMOUNT		REDUCTIONS		AMOUNT
Cleco Corporation
Guarantee issued to Entergy Mississippi on behalf of Attala	$	500	$	-	$	500
Cleco Power
Obligations under standby letter of credit issued to the Louisiana Department of Labor		3,725		-		3,725
Total	$	4,225	$	-	$	4,225

In January 2006, Cleco Corporation provided a $0.5 million guarantee to Entergy Mississippi for Attala’s obligations under the Interconnection Agreement.  This guarantee will be effective through the life of the agreement.

Acadia provided limited guarantees and indemnifications to Cleco Power under the Master Reorganization and Redemption Agreement related to the acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities in February 2010.  In connection with this transaction, Acadia became 100% owned by Cajun.  Prior to April 29, 2011, Cleco Corporation reported the investment in Cajun on the equity method of accounting and therefore APH’s 50% portion of the indemnity was off-balance sheet.  On April 29, 2011, in conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.

Acadia and Entergy Services entered into an amended capacity sale and fuel conversion services agreement on June 30, 2010, with an effective date of October 1, 2010.  In conjunction with the agreement, Cleco Corporation provided to Entergy Louisiana a limited guarantee, in an amount not to exceed $10.0 million, for certain performance obligations by Acadia under the agreement.  On April 29, 2011, the agreement and the related guarantee terminated as a result of the Acadia Unit 2 transaction.  For additional information regarding this transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

The State of Louisiana allows employers of certain financial net worth to self-insure their workers’ compensation benefits.  Cleco Power has a certificate of self-insurance from the Louisiana Office of Workers’ Compensation and is required to post a $3.7 million letter of credit, an amount equal to 110% of the average losses over the previous three years, as surety.

Disclosures about Guarantees

Cleco Corporation provided a limited guarantee and an indemnification to Entergy Louisiana and Entergy Gulf States for Perryville’s performance, indemnity, representation, and warranty obligations under the Sale Agreement, the Power Purchase Agreement, and other ancillary agreements related to the sale of the Perryville facility in 2004.  This is a continuing guarantee and all obligations of Cleco Corporation shall continue until the guaranteed obligations have been fully performed or otherwise extinguished.  The discounted probability-weighted liability under the guarantees and indemnifications recognized on Cleco Corporation’s Condensed Consolidated Balance Sheets as of September 30, 2011, was $0.2 million.  The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million.  Currently, management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under the guarantee.

In February 2010, Cleco Power acquired Acadia Unit 1 and half of Acadia Power Station’s related common facilities. Acadia provided limited guarantees and indemnifications to Cleco Power under the Master Reorganization and Redemption Agreement.  The maximum amount of the potential payment to Cleco Power for indemnifications is $30.0 million, except for the indemnifications relating to the fundamental organizational structure of Acadia against which there is no maximum amount.  Cleco Corporation is obligated to pay a maximum of $10.0 million if Acadia is unable to pay claims to Cleco Power pursuant to the guarantee.  Acadia recorded an indemnification liability and a corresponding reduction of the gain of $13.5 million which represents the fair value of these indemnifications.  In a related agreement, APH agreed to accept 50% of Acadia’s indemnification liability that would be held by the third parties who indirectly owned 50% of Acadia in return for $6.8 million received from the third parties.  The $6.8 million was recorded as an indemnification liability by APH.  Events that would require payments to Cleco Power pursuant to the indemnity include, but are not limited to:

§   Environmental costs that were caused by events occurring before the closing of the transaction;

§   Claims against Cleco Power for liabilities retained by Acadia;

§   Certain conditions of Acadia Unit 1 that were discovered prior to September 30, 2010; and

§   Breach of fundamental representations of Acadia, such as legal existence, ownership of Acadia Unit 1, and valid authorization to dispose of Acadia Unit 1.

Acadia and APH will reduce the indemnification liabilities either through expiration of the contractual life or through a reduction in the probability of a claim arising.  The indemnification obligation is expected to have a term of approximately three years, which reflects both contractual expiration of the underlying indemnifications and management’s assumptions about the decreasing probability of a payment due to the passage of time.  After the three-year period, a residual value of less than $0.1 million will remain.  At September 30, 2011, Acadia had an indemnification liability of $7.6 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco Corporation’s Condensed Consolidated Balance Sheet.  APH recognized no income for the three months ended September 30, 2011, and $0.5 million for the nine months ended September 30, 2011, primarily due to the contractual expiration of the underlying indemnification.  During the three and nine months ended September 30, 2011, Acadia recognized income of $1.0 million and $1.1 million, respectively, primarily due to the contractual expiration of the underlying indemnification.  

On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  Acadia provided limited guarantees and indemnifications to Entergy Louisiana and recorded an indemnification liability and a corresponding reduction of the gain of $21.8 million, which represents the fair value of these indemnifications.  APH agreed to indemnify the third-party owners of Cajun and their affiliates against 50% of Acadia’s liabilities and other obligations related to the Acadia Unit 2 transaction in exchange for $10.9 million received from the third parties.  The $10.9 million was recorded as an indemnification liability by APH.  In conjunction with the disposition of Acadia Unit 2, APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Events that would require payments to Entergy Louisiana pursuant to the indemnity include, but are not limited to:

§   Environmental costs that were caused by events occurring before the closing of the transaction;

§   Claims against Entergy Louisiana for liabilities retained by Acadia;

§   Certain conditions of Acadia Unit 2 that were discovered prior to September 30, 2010; and

§   Breach of fundamental representations of Acadia, such as legal existence, ownership of Acadia Unit 2, and valid authorization to dispose of Acadia Unit 2.

Acadia and APH will reduce the indemnification liabilities either through expiration of the contractual life or through a reduction in the probability of a claim arising.  The indemnification obligation is expected to have a term of three years, which reflects both contractual expiration of the underlying indemnifications and management’s assumptions about the decreasing probability of a payment due to the passage of time.  After the three-year period, a residual value of approximately $0.2 million will remain.  At September 30, 2011, Acadia had an indemnification liability of $21.8 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco Corporation’s Condensed Consolidated Balance Sheet.  The maximum amount of the potential payment to Entergy Louisiana for the indemnifications is the purchase price of $298.8 million, except for the liabilities retained by Acadia, for which there is no maximum amount.  Cleco Corporation is obligated to pay the same maximum amounts as Acadia if Acadia is unable to pay claims to Entergy Louisiana pursuant to the guarantee.  

As part of the Lignite Mining Agreement amended in 2009, Cleco Power and SWEPCO, joint owners of Dolet Hills, have agreed to pay the lignite miner’s loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay.  Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered.  At September 30, 2011, Cleco Power had a liability of $3.8 million related to the amended agreement.  The maximum projected payment by Cleco Power under this guarantee is estimated to be $72.5 million; however, the Amended Lignite Mining Agreement does not contain a cap.  The projection is based on the forecasted loan and lease obligations to be incurred by DHLC, primarily for purchases of equipment.  Cleco Power has the right to dispute the incurrence of loan and lease obligations through the review of the mining plan before the incurrence of such loan and lease obligations.  The Amended Lignite Mining Agreement does not terminate pursuant to its terms until 2026 and does not affect the amount the Registrants can borrow under their credit facilities.  Currently, management does not expect to be required to pay DHLC under the guarantee.

The following table summarizes the expected termination dates of the off-balance sheet commitments and on-balance sheet guarantees discussed above:

							AT SEPTEMBER 30, 2011
			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
	NET								MORE
	AMOUNT		LESS THAN						THAN
(THOUSANDS)	COMMITTED		ONE YEAR		1-3 YEARS		3-5 YEARS		5 YEARS
Off-balance sheet commitments	$	4,225	$	3,725	$	-	$	-	$	500
On-balance sheet guarantees		33,449		-		29,443		-		4,006
Total	$	37,674	$	3,725	$	29,443	$	-	$	4,506

In its bylaws, Cleco Corporation has agreed to indemnify directors, officers, agents, and employees who are made a party to a pending or completed suit, arbitration, investigation, or other proceeding whether civil, criminal, investigative or administrative, if the basis of inclusion arises as the result of acts conducted in the discharge of their official capacity.  Cleco Corporation has purchased various insurance policies to reduce the risks associated with the indemnification.  In its Operating Agreement, Cleco Power provides for the same indemnification as described above with respect to its managers, officers, agents, and employees.

Generally, neither Cleco Corporation nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations.  The one exception is the insurance contracts associated with the indemnification of directors, managers, officers, agents, and employees.  There are no assets held as collateral for third parties that either Cleco Corporation or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.

Other Commitments

Acadia Transactions

In February 2009, Cleco Power announced that it had chosen the acquisition of Acadia Unit 1 as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010.  Beginning in January 2010, Acadia operated the plant and served Cleco Power under a short-term tolling agreement covering Acadia Unit 1.  In February 2010, the transaction closed and the tolling agreement was terminated.  For additional information regarding the Cleco Power transaction, see Note 15 — “Acadia Transactions — Acadia Unit 1.”

In October 2009, Acadia and Entergy Louisiana announced that definitive agreements had been executed whereby Entergy Louisiana would acquire Acadia Unit 2.  A capacity sale and fuel conversion services agreement between Acadia and Entergy Louisiana began in June 2010.  Effective October 1, 2010, this agreement was subject to a $10.0 million guarantee by Cleco Corporation.  For additional information regarding this guarantee, please refer to “— Off-Balance Sheet Commitments” above.  On April 29, 2011, the transaction closed and the agreement terminated.  Cleco Power will continue to operate both units at the Acadia Power Station.  In connection with this transaction and in exchange for reasonable consideration, APH has indemnified the third-party owners of Cajun and their affiliates against their 50% of Acadia’s liabilities and other obligations related to the Entergy Louisiana transaction.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

New Markets Tax Credits

In August 2008, Cleco Corporation acquired a 99.9% membership interest in U.S. Bank New Markets Tax Credit Fund 2008-1 LLC (Fund).  The Fund was formed by U.S. Bancorp Community Development Corporation (USBCDC).  The purpose of the Fund is to invest in projects located in qualified active low-income communities that are underserved by typical debt capital markets.  These investments are designed to generate new markets tax credits and historical rehabilitation tax credits.

In July 2011, the operating agreement of the Fund was amended to facilitate investments in Section 1603 grant qualifying renewable energy projects and to adjust the guaranteed performance targets that the Fund is obligated to provide to Cleco.  U.S. Bank guarantees the cash flow and net present value of the Fund.  U.S. Bank is the parent company of the managing member of the Fund.

The tax benefits received from the Fund reduce the federal income tax obligations of Cleco Corporation.  In total, Cleco Corporation will contribute $286.3 million of equity contributions to the Fund and will receive at least $304.6 million of net tax benefits and cash from the inception of the investment in 2008 over the life of the investment, which ends in 2018.  The $18.3 million difference between equity contributions and total benefits received will be recognized over the life of the Fund as net tax benefits are delivered.  The following table reflects remaining future equity contributions.

(THOUSANDS)	CONTRIBUTION
Three months ending December 31, 2011	$	11,508
Years ending December 31,
2012		76,629
2013		36,225
2014		22,927
2015		21,904
Thereafter		20,808
Total	$	190,001

Of the $190.0 million, $69.6 million is due to be paid within the next twelve months.  Due to the right of offset, the investment and associated debt are presented on Cleco Corporation’s Condensed Consolidated Balance Sheet in the line item titled tax credit fund investment, net.  The amount of tax benefits delivered in excess of capital contributions as of September 30, 2011 was $78.0 million.  The amount of tax benefits received but not utilized as of September 30, 2011 was $63.6 million and is reflected as a deferred tax asset.

The equity contribution does not contain a stated rate of interest.  Cleco Corporation has recorded the liability and investment at its calculated fair value within the framework of the authoritative guidance.  In order to calculate the fair value, management used an imputed rate of interest assuming that Cleco Corporation obtained financing of a similar nature from a third-party.  The imputed interest rate was used in a net present value model in order to calculate the fair value of the remaining portion of the delayed equity contributions.  The table below contains the disclosures required by the authoritative guidelines for equity investments with an imputed interest rate.

(THOUSANDS)
Equity contributions, imputed interest rate 6%
Principal payment schedule above:	$	190,001
Less:  unamortized discount		22,098
Total	$	167,903

The gross investment amortization expense will be recognized over a ten-year period, with seven years remaining, using the cost method in accordance with the authoritative guidance for investments.

Risks and Uncertainties

Cleco Corporation

Cleco Corporation could be subject to possible adverse consequences if Cleco’s counterparties fail to perform their obligations or if Cleco Corporation or its affiliates are not in compliance with loan agreements or bond indentures.  

Evangeline 2010 Tolling Agreement

JPMorgan Chase & Co. guarantees JPMVEC’s obligations under the Evangeline 2010 Tolling Agreement.  For additional information regarding this tolling agreement, see Note 14 — “Evangeline Transactions.”

Other

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  After assessing the current operating performance, liquidity, and credit ratings of Cleco, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  If Cleco Corporation’s credit ratings were to be downgraded by Moody’s and Standard & Poor’s, Cleco Corporation would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.

Changes in the regulatory environment or market forces could cause Cleco to determine its assets have suffered an other-than-temporary decline in value, whereby an impairment would be required to be taken and Cleco’s financial condition could be materially adversely affected.

Cleco Power

Cleco Power supplies the majority of its customers’ electric power requirements from its own generation facilities.  In addition to power obtained from power purchase agreements, Cleco Power purchases power from other utilities and marketers to supplement its generation at times of relatively high demand or when the purchase price of power is less than its own cost of generation.  Due to its location on the transmission grid, Cleco Power relies on two main suppliers of electric transmission when accessing external power markets.  At times, constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory.

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.  After assessing the current operating performance, liquidity, and credit ratings of Cleco Power, management believes that Cleco Power will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.  Cleco Power pays fees and interest under its bank credit agreements based on the highest rating held.  If Cleco Power’s credit ratings were to be downgraded by Moody’s and Standard & Poor’s, Cleco Power would be required to pay additional fees and higher interest rates under its bank credit agreements.  Cleco Power’s collateral for derivatives is based on the lowest rating held.  If Cleco Power’s credit ratings were to be downgraded by Moody’s or Standard & Poor’s, Cleco Power would be required to pay additional collateral for derivatives.

In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Madison Unit 3.  In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract.  Under the terms of the Amended EPC Contract until final acceptance of Madison Unit 3, in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million.  In the event of further downgrade to both of its credit ratings to:  (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.

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Fair Value Accounting

9 Months Ended

Sep. 30, 2011

Fair Value Accounting [Abstract]

Fair Value Accounting

Note 4 — Fair Value Accounting

The amounts reflected in Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets at September 30, 2011, and December 31, 2010, for cash and cash equivalents, accounts receivable, other accounts receivable, accounts payable, and short-term debt approximate fair value because of their short-term nature.  Estimates of the fair value of Cleco and Cleco Power’s long-term debt and Cleco’s nonconvertible preferred stock are based upon the quoted market price for the same or similar issues or by a discounted present value analysis of future cash flows using current rates obtained by Cleco and Cleco Power for debt and by Cleco for preferred stock with similar maturities.  In June 2011, Cleco Corporation redeemed all of its outstanding preferred stock.  For more information on the preferred stock redemption, see Note 1 — “Summary of Significant Accounting Policies — Preferred Stock Redemption.”  The following charts summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments subject to fair value accounting.

Cleco

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	158,232	$	158,232	$	191,128	$	191,128
Restricted cash	$	28,903	$	28,903	$	41,048	$	41,048
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,403,836	$	1,462,063
Preferred stock not subject to mandatory redemption	$	-	$	-	$	1,029	$	844

Cleco Power

	AT SEPTEMBER 30, 2011				AT DECEMBER 31, 2010
(THOUSANDS)	CARRYING VALUE		ESTIMATED FAIR VALUE		CARRYING VALUE		ESTIMATED FAIR VALUE
Financial instruments not marked-to-market
Cash and cash equivalents	$	143,015	$	143,015	$	184,912	$	184,912
Restricted cash	$	28,807	$	28,807	$	40,951	$	40,951
Long-term debt, excluding debt issuance costs	$	1,376,567	$	1,566,805	$	1,388,836	$	1,447,063

At September 30, 2011, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash.  Cleco had $182.6 million ($153.7 million of cash and $28.9 million of restricted cash) in short-term investments in institutional money market funds.  If the money market funds failed to perform under the terms of the investment, Cleco would be exposed to a loss of the invested amounts.  Cleco Power had $168.3 million ($139.5 million of cash and $28.8 million of restricted cash) in short-term investments in institutional money market funds.  If the money market funds failed to perform under the terms of the investments, Cleco Power would be exposed to a loss of the invested amounts.  Collateral on these types of investments is not required by either Cleco or Cleco Power.  In order to mitigate credit risk, Cleco and Cleco Power have established guidelines for short-term investments.  Money market funds must have at least $1.0 billion in assets under management; must have been in existence for not less than two years; must have portfolios not comprised of more than 50% of securities issued by foreign entities; and must be rated in the top two ratings categories by at least one nationally recognized rating agency.  Commercial paper must be issued by a company with headquarters in the U.S. and rated not less than A1 by Standard & Poor’s or P1 by Moody’s.  For split-rated issuers, the second rating must not be lower than either A2 or P2; the issuer’s long-term debt must be rated not lower than A by Standard & Poor’s or A2 by Moody’s; and the issuer cannot be on negative credit watch.  Investments in commercial paper rated A2 by Standard & Poor’s or P2 by Moody’s may be made if approved by the appropriate level of management.  

Treasury Rate Lock

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance.  The notional amount of the treasury rate lock is $150.0 million, with a pricing date of November 14, 2011, or the date of issuance of the debt, whichever is earlier.  The treasury rate lock meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging.  The 3.77% rate lock was based on the 30-year treasury note yield as of August 12, 2011.  The fair market value of the treasury rate lock is based on the difference in the lock rate and the reference rate at the end of the period multiplied by the dollar value of a basis point.  At September 30, 2011, the 30-year treasury note yield was 2.89%, which resulted in Cleco Power recognizing a $30.0 million unrealized mark-to-market loss in other comprehensive income for the three and nine months ended September 30, 2011.  The offsetting liability was recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as an interest rate risk management liability.  There was no impact to earnings due to ineffectiveness for the three and nine months ended September 30, 2011.

Fair Value Measurements and Disclosures

The authoritative guidance on fair value measurements requires entities to classify assets and liabilities measured at their fair value according to three different levels depending on the inputs used in determining fair value.

The tables below disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis and within the scope of the authoritative guidance for fair value measurements and disclosures.

Cleco

	CLECO CONSOLIDATED FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		182,603		-		182,603		-		229,748		-		229,748		-
Total assets	$	182,603	$	-	$	182,603	$	-	$	229,845	$	-	$	229,845	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

Cleco Power

	CLECO POWER FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT SEPTEMBER 30, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DECEMBER 31, 2010		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Energy market derivatives	$	-	$	-	$	-	$	-	$	97	$	-	$	97	$	-
Institutional money market funds		168,307		-		168,307		-		224,451		-		224,451		-
Total assets	$	168,307	$	-	$	168,307	$	-	$	224,548	$	-	$	224,548	$	-
Liability Description
Energy market derivatives	$	5,685	$	381	$	5,304	$	-	$	15,245	$	3,317	$	11,928	$	-
Treasury rate lock		29,962		-		29,962		-		-		-		-		-
Total liabilities	$	35,647	$	381	$	35,266	$	-	$	15,245	$	3,317	$	11,928	$	-

The derivative assets and liabilities are classified as either current or non-current depending on when the positions close.  All energy market derivative current assets and current liabilities are reported as a net current energy risk management asset or liability.  All energy market derivative non-current assets and non-current liabilities are reported net in other deferred charges or other deferred credits.  Net presentation is appropriate due to the right of offset included in the master netting agreements.  On the balance sheet, the net current and net non-current derivative positions are netted with the applicable margin deposits.  At September 30, 2011, a net current energy risk management liability of $5.2 million represented the current derivative positions of $5.7 million reduced by current margin deposits of $0.5 million and option premiums that were less than $0.1 million.  The institutional money market funds were reported on the Cleco Condensed Consolidated Balance Sheet in cash and cash equivalents, current restricted cash, and non-current restricted cash of $153.7 million, $3.6 million, and $25.3 million, respectively.  At Cleco Power, cash and cash equivalents, current restricted cash, and non-current restricted cash were $139.5 million, $3.6 million, and $25.2 million, respectively, as of September 30, 2011.  The treasury rate lock was reported on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as a current liability in the line item interest rate risk management liability as of September 30, 2011.

Cleco utilizes different valuation techniques for fair value calculations.  In order to measure the fair value for Level 1 assets and liabilities, Cleco obtains the closing price from published indices in active markets for the various instruments and multiplies this price by the appropriate number of instruments held.  Level 2 fair values for assets and liabilities are determined by obtaining the closing price from published indices in active markets for instruments that are similar to Cleco’s assets and liabilities.  The fair value obtained is then discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return.  For some options, Cleco uses the Black-Scholes model using observable and available inputs to calculate the fair value, consistent with the income approach.  These techniques have been applied consistently from fiscal period to fiscal period.  Level 3 fair values allow for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Cleco had no Level 3 assets or liabilities at September 30, 2011, or December 31, 2010.

The assets and liabilities reported at fair value are grouped into classes based on the underlying nature and risks associated with the individual asset or liability.  Level 1 of energy market derivative assets and liabilities consists of a single class that includes natural gas futures with quoted prices on a liquid, national exchange.  As the future price of natural gas is affected by market expectations, such as the supply of natural gas relative to demand, the fair value of Cleco’s natural gas futures fluctuates.

Level 2 of energy market derivative assets and liabilities consists of two classes.  The first class contains natural gas swaps which fluctuate in value as the underlying natural gas futures fair value changes, and as market interest rates change. Cleco records the natural gas swaps at the net present value.  The second class consists of natural gas options.  The fair value of natural gas options fluctuates with the volatility in the fair value of natural gas, the number of days until the options expire, the underlying natural gas futures price fluctuations, and market interest rates.  Cleco records natural gas options at the net present value.  Both of these energy market derivative classes also contain counterparty execution risk because the transactions are entered into with a direct counterparty and are not traded through an exchange.

The Level 2 institutional money market funds asset consists of a single class.  In order to capture interest income and minimize risk, cash is invested in money market funds that invest primarily in short-term securities issued by the U.S. Treasury in order to maintain liquidity and achieve the goal of a net asset value of a dollar.  The risks associated with this class are counterparty risk of the fund manager and risk of price volatility associated with the underlying securities of the fund.

The Level 2 treasury rate lock liability consisted of a single class that only contains one instrument.  The risks are changes in the reference treasury yield rate and counterparty risk.  This instrument is with a direct counterparty and not traded through an exchange.

Cleco has a policy which states that transfers between Levels 1, 2, and 3 are recognized at the end of a reporting period.  During the nine months ended September 30, 2011, and the year ended December 31, 2010, Cleco did not experience any transfers between levels.

Derivatives and Hedging

The authoritative guidance on derivatives and hedging requires entities to provide transparent disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance, and cash flows.  Cleco is required to provide qualitative disclosures about derivative fair value, gains and losses, and credit-risk-related contingent features in derivative agreements.  

The following table presents the fair values of derivative instruments and their respective line items as recorded on Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets as of September 30, 2011, and December 31, 2010:

	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
	LIABILITY DERIVATIVES
(THOUSANDS) FAIR VALUE	BALANCE SHEET LINE ITEM	AT SEPTEMBER 30, 2011			DECEMBER 31, 2010
Commodity contracts
Fuel cost hedges:
Current	Energy risk management liability, net	$	(5,685	)	$	(13,497	)
Long-term	Other deferred credits		-			(1,651	)
Total		$	(5,685	)	$	(15,148	)

The following table presents the effect of derivatives not designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

		FOR THE THREE MONTHS ENDED							FOR THE NINE MONTHS ENDED
		SEPTEMBER 30, 2011			SEPTEMBER 30, 2010				SEPTEMBER 30, 2011			SEPTEMBER 30, 2010
(THOUSANDS)	GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			GAIN (LOSS) IN INCOME OF DERIVATIVES LINE ITEM	AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES			AMOUNT OF LOSS RECOGNIZED IN INCOME ON DERIVATIVES
Commodity contracts
Economic hedges	Other operations revenue	$	-		$	(157	) (1)	Other operations revenue	$	-		$	(648	) (2)
Fuel cost hedges(3)	Fuel used for electric generation		(5,678	)		(10,182	)	Fuel used for electric generation		(14,675	)		(32,397	)
Total		$	(5,678	)	$	(10,339	)		$	(14,675	)	$	(33,045	)
(1)For the three months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(2)For the nine months ended September 30, 2010, Cleco recognized $0.2 million of mark-to-market gains related to economic hedges.
(3)In accordance with the authoritative guidance for regulated operations, an additional $5.7 million of unrealized losses and $1.3 million of deferred losses associated with fuel cost hedges are reported in Accumulated Deferred Fuel on the balance sheet as of September 30, 2011, compared to $15.1 million of unrealized losses and $1.6 million of deferred losses associated with fuel cost hedges as of December 31, 2010. As gains and losses are realized in future periods, they will be recorded as Fuel Used for Electric Generation on the Income Statement.

At September 30, 2011, Cleco Power had 3.3 million MMBtus hedged for natural gas fuel costs, which is approximately 4% of the estimated natural gas requirements for a two-year period.  At December 31, 2010, Cleco Power had 9.4 million MMBtus hedged or approximately 11% of gas requirements for a two-year period.  

The following table presents the effect of derivatives designated as hedging instruments on Cleco Corporation and Cleco Power’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011, and 2010:

	FOR THE THREE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(376	)	$	(194	)*
Treasury rate locks	$	(29,962	)	$	89	*	$	-		$	41	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

	FOR THE NINE MONTHS ENDED  SEPTEMBER 30, 2011						FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
(THOUSANDS)	AMOUNT OF LOSS  RECOGNIZED IN OCI			AMOUNT OF GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)			AMOUNT OF LOSS RECOGNIZED IN OCI			AMOUNT OF (LOSS) GAIN RECLASSIFIED FROM ACCUMULATED OCI INTO INCOME (EFFECTIVE PORTION)
Interest rate swap(1)	$	-		$	-		$	(717	)	$	(592	)*
Treasury rate locks	$	(29,962	)	$	267	*	$	-		$	125	*
* The (loss) gain reclassified from accumulated OCI into income (effective portion) is reflected in interest charges.
(1) In November 2010, the interest rate swap was terminated. All remaining losses in accumulated OCI were reclassified to other expense.

At September 30, 2011, Cleco Power expected $0.5 million of the effective portion of treasury rate locks cash flow hedges to be reclassed from accumulated OCI to an increase in interest charges over the next 12 months.  

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Evangeline Transactions

9 Months Ended

Sep. 30, 2011

Restructuring Agreement [Abstract]

Evangeline Transactions

Note 14 — Evangeline Transactions

On February 22, 2010, Evangeline and JPMVEC entered into the Evangeline Restructuring Agreement whereby the parties agreed to terminate the existing Evangeline Tolling Agreement and entered into the Evangeline 2010 Tolling Agreement, effective March 1, 2010.  The other significant terms of the Evangeline Restructuring Agreement are:

§   The tolling agreement is a market-based tolling agreement, for Coughlin Units 6 and 7, ending December 31, 2011, with an option for JPMVEC to extend the term through December 31, 2012.  The agreement also gives Evangeline the right to terminate its Coughlin Unit 6 obligations prior to the expiration of the term.  JPMVEC did not exercise the option to extend the tolling agreement;

§   $126.6 million of Evangeline’s 8.82% Senior Secured bonds due 2019, owned by JPMVEC, were transferred to Evangeline and subsequently retired; and $5.3 million of accrued interest associated with the bonds transferred to Evangeline was eliminated;

§   JPMVEC paid Evangeline $56.7 million;

§   JPMVEC returned Cleco Corporation’s $15.0 million letter of credit issued under the Evangeline Tolling Agreement and the letter of credit was cancelled; and

§   Evangeline recorded a gain of $148.4 million.

The termination of the Evangeline Tolling Agreement was considered a termination of an operating lease and a triggering event requiring an asset impairment analysis.  Management made assumptions about expected future cash flows, long-term interest rates, estimates about the probability of the occurrence of future events, and estimates of market values of assets without a readily observable market price.  An impairment charge was not recorded since the undiscounted expected future net cash flows exceeded the carrying value of Evangeline’s property, plant and equipment.  Due to the lack of a long-term agreement, the expected future net cash flows of Evangeline are subject to an increased potential for variability as compared to prior years.  Consequently, future impairment tests could occur more frequently and might result in an impairment charge.

Under the terms of the Evangeline Restructuring Agreement, Evangeline issued an irrevocable redemption notice to redeem the remaining $35.2 million of 8.82% Senior Secured bonds outstanding pursuant to their terms on February 25, 2010, and paid the debtholders $1.5 million of accrued interest and a $10.2 million make-whole payment.  As a result of the debt retirement, Evangeline expensed $2.1 million in unamortized debt issuance costs associated with the Evangeline bonds.  The Evangeline bonds were non-recourse to Cleco Corporation and redemption of the bonds was permitted under Cleco Corporation’s revolving credit facility.  Upon the redemption of the bonds, $30.1 million of restricted cash was released to Evangeline.  

The impacts of these transactions are reflected in the Midstream segment, which includes Evangeline.  In accordance with the authoritative guidance, effective January 1, 2010, the financial results for Evangeline are no longer presented as equity income (loss), but presented in the corresponding line items in the consolidated financials of Midstream.

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Fair Value Accounting, Effect of Derivatives on Consolidated Statements of Income (Details) (USD $)			3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2010 Interest Rate Swap [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2010 Interest Rate Swap [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2010 Interest Rate Swap [Member] Derivatives Designated as Hedging Instruments [Member] OCI [Member]	Sep. 30, 2010 Interest Rate Swap [Member] Derivatives Designated as Hedging Instruments [Member] OCI [Member]	Sep. 30, 2011 Treasury Rate Locks [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2010 Treasury Rate Locks [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2011 Treasury Rate Locks [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2010 Treasury Rate Locks [Member] Interest Expense [Member] Derivatives Designated as Hedging Instruments [Member]	Sep. 30, 2011 Treasury Rate Locks [Member] Derivatives Designated as Hedging Instruments [Member] OCI [Member]	Sep. 30, 2011 Treasury Rate Locks [Member] Derivatives Designated as Hedging Instruments [Member] OCI [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member]	Dec. 31, 2010 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member] Fuel Used For Electric Generation [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member] Fuel Used For Electric Generation [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member] Fuel Used For Electric Generation [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member] Fuel Used For Electric Generation [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Economic Hedges [Member] Other Operations Revenue [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Economic Hedges [Member] Other Operations Revenue [Member]
Derivative, gain (loss) recognized in income [Abstract]
Amount of gain (loss) recognized in income on derivatives													$ (5,678,000)	$ (10,339,000)	$ (14,675,000)	$ (33,045,000)			$ (5,678,000)	$ (10,182,000)	$ (14,675,000)	$ (32,397,000)	$ (157,000)	$ (648,000)
Mark-to-market gains (losses)																							200,000	200,000
Unrealized gains (losses)																	(5,700,000)	(15,100,000)
Deferred gains (losses)																	(1,300,000)	(1,600,000)
Amount of (loss) gain recognized in OCI					(376,000)	(717,000)					(29,962,000)	(29,962,000)
Amount of (loss) gain reclassified from accumulated OCI into income (effective portion)			(194,000)	(592,000)			89,000	41,000	267,000	125,000
Cash flow hedge gain (loss) expected to be reclassed from accumulated OCI over the next 12 months									$ (500,000)
Natural gas requirements hedged [Abstract]
Millions MMBtus hedged for natural gas fuel costs	3.3	9.4
Estimated natural gas requirements covered (in hundredths)	4.00%	11.00%
Estimated natural gas requirements period (in years)	two year period	two-year period

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Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets and Liabilities

The following chart summarizes Cleco Power’s regulatory assets and liabilities at September 30, 2011, and December 31, 2010:

	AT SEPTEMBER 30,			AT DECEMBER 31,
(THOUSANDS)	2011			2010
Regulatory assets – deferred taxes, net	$	213,847		$	203,696
Deferred mining costs	$	19,755		$	21,666
Deferred interest costs		6,758			7,033
Deferred asset removal costs		814			768
Deferred postretirement plan costs		113,538			117,651
Deferred tree trimming costs		9,057			11,086
Deferred training costs		7,525			7,642
Deferred storm surcredits, net		9,080			10,633
Deferred construction carrying costs		12,416			18,830
Lignite mining agreement contingency		3,781			3,781
AFUDC equity gross-up		74,496			74,859
Deferred rate case costs		1,252			1,654
Deferred Acadia Unit 1 acquisition costs		2,997			3,076
Deferred IRP/RFP costs		625			977
Deferred AMI pilot costs		185			283
Total regulatory assets – other	$	262,279		$	279,939
Deferred construction carrying costs		(40,298	)		(87,875	)
Deferred fuel and purchased power		9,162			10,348
Total regulatory assets, net	$	444,990		$	406,108

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Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 158,232	$ 191,128
Restricted cash	3,554	14,959
Customer accounts receivable, less allowance for doubtful accounts	52,299	38,820
Accounts receivable - affiliate	0	831
Other accounts receivable, less allowance for doubtful accounts	49,290	52,546
Taxes receivable	36,705	50,104
Unbilled revenue	33,112	44,649
Fuel inventory, at average cost	38,070	82,737
Material and supplies inventory, at average cost	52,257	48,265
Accumulated deferred federal and state income taxes, net	25,057	4,106
Accumulated deferred fuel	9,162	10,348
Cash surrender value of company-/trust-owned life insurance policies	50,628	49,789
Prepayments	5,004	6,399
Regulatory assets - other	12,869	13,508
Other current assets	4,745	661
Total current assets	530,984	608,850
Property, plant and equipment
Property, plant and equipment	3,859,621	3,810,896
Accumulated depreciation	(1,218,818)	(1,162,456)
Net property, plant and equipment	2,640,803	2,648,440
Construction work in progress	223,640	135,785
Total property, plant and equipment, net	2,864,443	2,784,225
Equity investment in investees	13,081	86,732
Prepayments	4,580	5,274
Restricted cash, less current portion	25,349	26,089
Regulatory assets and liabilities - deferred taxes, net	213,847	203,696
Regulatory assets - other	249,410	266,431
Net investment in direct financing lease	13,676	13,817
Intangible asset	136,393	145,374
Other deferred charges	19,778	20,922
Total assets	4,071,541	4,161,410
Current liabilities
Short-term debt	0	150,000
Long-term debt due within one year	13,108	12,269
Accounts payable	93,186	123,042
Retainage	3,231	2,726
Accounts payable - affiliate	0	155
Customer deposits	42,181	38,934
Provision for rate refund	3,917	9,598
Interest accrued	62,377	34,462
Energy risk management liabilities, net	5,159	9,027
Interest rate risk management liability	29,962	0
Regulatory liabilities - other	33,272	43,562
Deferred compensation	7,562	7,751
Uncertain tax positions	42,674	31,853
Other current liabilities	14,784	14,302
Total current liabilities	351,413	477,681
Deferred credits
Accumulated deferred federal and state income taxes, net	624,429	553,211
Accumulated deferred investment tax credits	7,741	8,669
Post-retirement benefit obligations	109,865	166,387
Regulatory liabilities - other	7,026	44,313
Restricted storm reserve	24,656	25,993
Uncertain tax positions	47,715	60,395
Tax credit fund investment, net	48,494	44,514
Contingent sale obligations	29,443	4,714
Other deferred credits	44,070	57,617
Total deferred credits	943,439	965,813
Long-term debt, net	1,370,576	1,399,709
Total liabilities	2,665,428	2,843,203
Shareholders' equity
Preferred stock Not subject to mandatory redemption	0	1,029
Common shareholders' equity
Common stock	60,684	60,540
Premium on common stock	409,040	405,313
Retained earnings	978,942	863,237
Treasury stock	(13,228)	(274)
Accumulated other comprehensive loss	(29,325)	(11,638)
Total common shareholders' equity	1,406,113	1,317,178
Total shareholders' equity	1,406,113	1,318,207
Total liabilities and shareholders' equity	4,071,541	4,161,410
CLECO POWER [Member]
Current assets
Cash and cash equivalents	143,015	184,912
Restricted cash	3,554	14,959
Customer accounts receivable, less allowance for doubtful accounts	52,299	38,820
Accounts receivable - affiliate	2,802	2,738
Other accounts receivable, less allowance for doubtful accounts	29,323	47,992
Taxes receivable	0	4,123
Unbilled revenue	33,112	44,649
Fuel inventory, at average cost	38,070	82,737
Material and supplies inventory, at average cost	49,634	45,913
Accumulated deferred federal and state income taxes, net	38,248	2,811
Accumulated deferred fuel	9,162	10,348
Cash surrender value of company-/trust-owned life insurance policies	20,328	20,051
Prepayments	3,782	4,944
Regulatory assets - other	12,869	13,508
Other current assets	597	412
Total current assets	436,795	518,917
Property, plant and equipment
Property, plant and equipment	3,604,938	3,552,779
Accumulated depreciation	(1,142,414)	(1,085,945)
Net property, plant and equipment	2,462,524	2,466,834
Construction work in progress	214,071	130,396
Total property, plant and equipment, net	2,676,595	2,597,230
Equity investment in investees	13,073	13,073
Prepayments	4,580	5,274
Restricted cash, less current portion	25,253	25,992
Regulatory assets and liabilities - deferred taxes, net	213,847	203,696
Regulatory assets - other	249,410	266,431
Intangible asset	136,393	145,374
Other deferred charges	18,439	19,218
Total assets	3,774,385	3,795,205
Current liabilities
Long-term debt due within one year	13,108	12,269
Accounts payable	85,382	112,487
Retainage	3,231	2,726
Accounts payable - affiliate	7,332	7,945
Customer deposits	42,181	38,934
Provision for rate refund	3,917	9,598
Taxes payable	17,558	0
Interest accrued	31,825	13,450
Energy risk management liabilities, net	5,159	9,027
Interest rate risk management liability	29,962	0
Regulatory liabilities - other	33,272	43,562
Uncertain tax positions	2,602	0
Other current liabilities	12,080	9,862
Total current liabilities	287,609	259,860
Deferred credits
Accumulated deferred federal and state income taxes, net	680,287	601,574
Accumulated deferred investment tax credits	7,741	8,669
Post-retirement benefit obligations	72,466	130,757
Regulatory liabilities - other	7,026	44,313
Restricted storm reserve	24,656	25,993
Uncertain tax positions	45,014	54,835
Other deferred credits	43,608	50,572
Total deferred credits	880,798	916,713
Member's equity	1,235,402	1,233,923
Long-term debt, net	1,370,576	1,384,709
Total capitalization	2,605,978	2,618,632
Common shareholders' equity
Total liabilities and shareholders' equity	$ 3,774,385	$ 3,795,205

XML

Acadia Transactions

9 Months Ended

Sep. 30, 2011

Acadia Transactions [Abstract]

Acadia Transactions

Note 15 — Acadia Transactions

Acadia Unit 1

In February 2010, Cleco Power completed the acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities.  Cleco Power and the parties executed the definitive agreements in 2009, and received LPSC and FERC approvals for the transaction in January 2010 and February 2010, respectively.  The significant terms of the transaction were:

§   Cleco Power acquired Acadia Unit 1 and half of the common facilities for $304.0 million;

§   Cleco Power recognized $78.4 million of deferred taxes on the transaction;  

§   Acadia recognized a gain of $82.0 million;

§   APH received $6.8 million from third-parties in return for APH’s indemnification against the third parties’ 50% share of Acadia’s liabilities and other obligations related to the Cleco Power transaction; and

§   Cleco Power owns and operates Acadia Unit 1.  Prior to April 29, 2011, Cleco Power operated Acadia Unit 2 on behalf of Acadia.  On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 to Entergy Louisiana.  Cleco Power now operates Acadia Unit 2 on behalf of Entergy Louisiana.  

Acadia Unit 2

On April 29, 2011, Acadia completed its disposition of Acadia Unit 2 and Acadia Power Station’s remaining common facilities to Entergy Louisiana.  The significant terms of the transaction were:

§   Entergy Louisiana acquired Acadia Unit 2 for $298.8 million;

§   In exchange for $10.9 million, APH indemnified the third-party owners of Cajun and their affiliates against 50% of Acadia’s liabilities and other obligations related to the Acadia Unit 2 transaction;

§   APH recognized a gain of $62.0 million, which included $26.2 million of equity income that represents the 2007 investment impairment charge of $45.9 million, partially offset by $19.7 million of capitalized interest during the construction of Acadia;

§   APH received 100% ownership in Acadia in exchange for its 50% interest in Cajun, and Acadia became a consolidated subsidiary of APH; and

§   Cleco Power operates Acadia Unit 2 on behalf of Entergy Louisiana.

Following the transaction, ongoing operations at Acadia are minimal, relating only to the previously established accounts receivable and accounts payable and servicing of indemnities.  Therefore, Acadia does not meet the definition of a business.

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Electric Customer Credits (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2011	Jun. 30, 2011	Dec. 31, 2010	Sep. 30, 2010
Electric Customer Credits [Abstract]
Target return on equity allowed by FRP (in hundredths)	10.70%
Percentage of retail earnings due to customers (in hundredths)	60.00%
Return on equity for customer credit, low range (in hundredths)	11.30%
Return on equity for customer credit, high range (in hundredths)	12.30%
Provision of rate refund	$ 3,917	$ 3,800	$ 9,598	$ 9,000

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Prior to April 30, 2011, Cleco reported its investment in Cajun on the equity method of accounting.  In conjunction with the disposition of Acadia Unit 2 to Entergy Louisiana, APH received 100% ownership in Acadia in exchange for its 50% ownership interest in Cajun, and Acadia became a consolidated subsidiary of APH.  Following the disposition, Acadia’s assets, liabilities, revenues, expenses, and cash flows are presented on the corresponding line items of Cleco’s Condensed Consolidated Financial Statements, prospectively.  For additional information on the Acadia Unit 2 transaction, see Note 15 — “Acadia Transactions — Acadia Unit 2.”

Cleco and Cleco Power report the investment in Oxbow on the equity method of accounting.  Under the equity method, the assets and liabilities of this entity are reported as equity investment in investees on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets.  The revenue and expenses of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.  

Property, Plant and Equipment

Property, plant and equipment consist primarily of regulated utility generation and energy transmission assets.  Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction.  Jointly owned assets are reflected in property, plant and equipment at Cleco Power’s share of the cost to construct or purchase the assets.  

Restricted Cash

Various agreements to which Cleco is subject contain covenants that restrict its use of cash.  As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general corporate purposes. 

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values.  Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance.  Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes under GAAP.  Other financial assets and liabilities, such as long-term debt, are reported at their carrying values at their date of issuance on the condensed consolidated balance sheets with their fair values disclosed without regard to the three levels.  

Risk Management

Market risk inherent in Cleco Power’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas on different energy exchanges.  

Commodity Market Price Risk

Cleco’s Energy Market Risk Management Policy authorizes the use of various derivative instruments, including exchange traded futures and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations in the price of power and natural gas.  Cleco applies the authoritative guidance as it relates to derivatives and hedging to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market.  Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting because Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements.  Cleco Power entered into certain financial transactions it considered economic hedges to mitigate the risk associated with a contract for fixed-price power provided to a wholesale customer through December 2010.  These transactions were marked-to-market with the resulting gain or loss recorded on the income statement as a component of operating revenue.  

Cleco Power has entered into other positions to mitigate the volatility in customer fuel costs.  These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of energy risk management assets or liabilities.  Such gain or loss is deferred as a component of deferred fuel assets or liabilities.  When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers’ bills as a component of the fuel cost adjustment. 

Cleco and Cleco Power maintain a master netting agreement policy and monitor credit risk exposure through review of counterparty credit quality, counterparty credit exposure, and counterparty concentration levels.  Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and by requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Cleco Power has agreements in place with various counterparties that authorize the netting of financial buys and sells and contract payments to mitigate credit risk for transactions entered into for risk management purposes.  

Interest Rate Risk

In August 2011, Cleco Power entered into a treasury rate lock contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance. 

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating activities
Net income	$ 165,205	$ 234,768
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	114,104	124,144
Gain on forgiveness of debt	0	(129,870)
Return on equity investment in investee	58,665	0
Income from equity investments	(62,051)	(39,212)
Unearned compensation expense	6,065	3,947
Allowance for other funds used during construction	(3,757)	(11,052)
Net deferred income taxes	45,336	40,013
Deferred fuel costs	(6,422)	13,994
Cash surrender value of company-/trust-owned life insurance	1,055	(1,481)
Changes in assets and liabilities:
Accounts receivable	(18,274)	(30,329)
Accounts and notes receivable, affiliate	1,074	894
Unbilled revenue	11,538	(23,359)
Fuel, materials and supplies inventory	40,675	(11,979)
Prepayments	2,089	1,047
Accounts payable	(34,986)	(13,277)
Accounts and notes payable, affiliate	(552)	(2,364)
Customer deposits	9,718	9,490
Long-term receivable	0	27,976
Post-retirement benefit obligations	(56,743)	503
Regulatory assets and liabilities, net	(40,204)	(77,331)
Contingent sale obligations	10,900	4,800
Other deferred accounts	(2,184)	7,363
Retainage payable	(2,481)	0
Taxes accrued	12,946	51,597
Interest accrued	10,738	9,606
Energy risk management assets and liabilities, net	3,880	6,340
Other operating	(3,692)	(3,860)
Net cash provided by (used in) operating activities	262,642	192,368
Investing activities
Additions to property, plant and equipment	(145,669)	(252,711)
Allowance for other funds used during construction	3,757	11,052
Cash from reconsolidation of VIEs	3,879	812
Return of equity investment in investee	89,654	0
Equity investment in investees	0	(8,700)
Return of investment tax credit fund	244	0
Contributions to tax credit fund	(18,479)	(28,837)
Transfer of cash from restricted accounts	12,144	45,243
Other investing	373	(1,678)
Net cash used in investing activities	(54,097)	(234,819)
Financing activities
Issuance of short-term debt	0	150,000
Retirement of short-term debt	(150,000)	0
Draws on credit facility	10,000	255,000
Payments on credit facility	(25,000)	(350,000)
Retirement of long-term debt	(12,269)	(46,696)
Repurchase of common stock	13,009	0
Redemption of preferred stock	(1,039)	0
Dividends paid on preferred stock	(26)	(35)
Dividends paid on common stock	(49,170)	(43,848)
Other financing	(928)	673
Net cash (used in) provided by financing activities	(241,441)	(34,906)
Net increase (decrease) in cash and cash equivalents	(32,896)	(77,357)
Cash and cash equivalents at beginning of period	191,128	145,193
Cash and cash equivalents at end of period	158,232	67,836
Supplementary cash flow information
Interest paid (net of amount capitalized)	53,936	55,623
Income taxes paid (refunded)	18,241	17,047
Supplementary non-cash investing and financing activities
Accrued additions to property, plant and equipment	11,491	5,314
Issuance of treasury stock - LTICP	55	74
Issuance of common stock - LTICP/ESPP	241	222
Non-cash additions to property, plant and equipment	4,074	152,067
Non-cash return of investment	0	152,067
Non-cash contribution to subsidiary, net of tax	0	225,732
CLECO POWER [Member]
Operating activities
Net income	119,557	123,584
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	95,482	88,607
Unearned compensation expense	1,768	1,303
Allowance for other funds used during construction	(3,757)	(11,052)
Net deferred income taxes	35,174	20,628
Deferred fuel costs	(6,422)	13,994
Cash surrender value of company-/trust-owned life insurance	(277)	(236)
Changes in assets and liabilities:
Accounts receivable	(20,442)	(31,579)
Accounts and notes receivable, affiliate	68	(1,977)
Unbilled revenue	11,538	(23,359)
Fuel, materials and supplies inventory	40,946	(11,707)
Prepayments	1,858	974
Accounts payable	(30,345)	(12,137)
Accounts and notes payable, affiliate	(1,386)	(18,524)
Customer deposits	9,718	9,490
Post-retirement benefit obligations	(58,259)	(1,020)
Regulatory assets and liabilities, net	(40,204)	(77,331)
Other deferred accounts	(6,361)	(4,021)
Retainage payable	(2,481)	0
Taxes accrued	21,680	20,858
Interest accrued	11,075	9,297
Energy risk management assets and liabilities, net	3,880	6,340
Other operating	1,878	(2,444)
Net cash provided by (used in) operating activities	184,688	99,688
Investing activities
Additions to property, plant and equipment	(131,014)	(98,399)
Allowance for other funds used during construction	3,757	11,052
Equity investment in investees	0	(200)
Transfer of cash from restricted accounts	12,144	15,111
Other investing	2,257	(83)
Net cash used in investing activities	(112,856)	(72,519)
Financing activities
Retirement of long-term debt	(12,269)	(11,533)
Distribution to parent	(100,000)	(125,000)
Other financing	(1,460)	(1,365)
Net cash (used in) provided by financing activities	(113,729)	(137,898)
Net increase (decrease) in cash and cash equivalents	(41,897)	(110,729)
Cash and cash equivalents at beginning of period	184,912	138,113
Cash and cash equivalents at end of period	143,015	27,384
Supplementary cash flow information
Interest paid (net of amount capitalized)	52,220	48,155
Income taxes paid (refunded)	2,233	(5,425)
Supplementary non-cash investing and financing activities
Accrued additions to property, plant and equipment	20,088	4,757
Non-cash additions to property, plant and equipment	4,074	304,134
Non-cash assumption of deferred tax liability	$ 0	$ 78,402

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Electric Customer Credits

9 Months Ended

Sep. 30, 2011

Electric Customer Credits [Abstract]

Electric Customer Credits

Note 9 — Electric Customer Credits

Beginning in 2010, the amount of Cleco Power’s yearly retail earnings is subject to the terms of a FRP established by the LPSC.  The new rates and the FRP became effective upon commencement of commercial operations at Madison Unit 3 on February 12, 2010.  The 2010 FRP establishes a target return on equity and requires all or a portion of regulated earnings for each yearly review period above the targeted regulatory rate of return on equity to be credited to Cleco Power’s customers. The 2010 FRP allows Cleco Power the opportunity to earn a target return on equity of 10.7%, including returning to retail customers 60% of retail earnings between 11.3% and 12.3% and all retail earnings over 12.3%. The amount of credits due customers, if any, is determined by Cleco Power and the LPSC annually. The 2010 FRP established that Cleco Power file monitoring reports for both the 12 months ended June 30, 2010, and September 30, 2010, on or before October 31, 2010, and January 31, 2011, respectively. Beginning in 2011, Cleco Power will file annual monitoring reports no later than October 31 for the 12-month period ending June 30.

On October 29, 2010, Cleco Power filed its report for the 12 months ended June 30, 2010, which indicated that no refund was due for this period.  On January 28, 2011, Cleco Power filed its report for the 12 months ended September 30, 2010, which indicated that $9.0 million was due to be returned to customers.  On June 23, 2011, the LPSC Staff completed its review of this report and determined that the results presented by Cleco Power in the September 30, 2010 filing were consistent with the terms of the 2010 FRP and that no changes were necessary.  Cleco Power issued refunds for this filing on customers’ bills in the third quarter of 2011.  On October 31, 2011, Cleco Power filed its report for the 12 months ended June 30, 2011, which indicated that $3.8 million was due to be returned to customers.  The ultimate amount of any customer refund is subject to LPSC approval.

The accrual for estimated electric customer credits reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at September 30, 2011, and December 31, 2010, was $3.9 million and $9.6 million, respectively.

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2011

Variable Interest Entities [Abstract]

Equity Income (Loss) from Investments Accounted for Using the Equity Method

The following table presents the equity income (loss) from each investment accounted for using the equity method.   

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	-		$	2,494
Subsidiaries less than 100% owned by Cleco Innovations		(1	)		-
Total equity (loss) income	$	(1	)	$	2,494

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011			2010
Cajun	$	62,053		$	39,211
Subsidiaries less than 100% owned by Cleco Innovations		(2	)		1
Total equity income	$	62,051		$	39,212

Components of Equity Investments

The table below presents the components of Cleco Power’s equity investment in Oxbow.

INCEPTION TO DATE (THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Purchase price	$	12,873	$	12,873
Cash contributions		200		200
Total equity investment in investee	$	13,073	$	13,073

Comparison of Investee's Assets and Liabilities with Maximum Exposure to Loss

The following table compares the carrying amount of Oxbow’s assets and liabilities with Cleco’s maximum exposure to loss related to its investment in Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Oxbow’s net assets/liabilities	$	26,146	$	26,146
Cleco Power’s 50% equity	$	13,073	$	13,073
Cleco’s maximum exposure to loss	$	13,073	$	13,073

Summarized Financial Information for Equity Method Investments

The following tables contain summarized financial information for Cajun prior to the disposition of Acadia Unit 2.

(THOUSANDS)	AT DECEMBER 31, 2010
Current assets	$	7,133
Property, plant and equipment, net		203,793
Total assets	$	210,926
Current liabilities	$	1,950
Other liabilities		9,429
Partners’ capital		199,547
Total liabilities and partners’ capital	$	210,926

(THOUSANDS)	FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
Operating revenue		$	31,883
Operating expenses			30,566
Other income			3,671
Income before taxes		$	4,988

	FOR THE NINE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)		2011	*		2010
Operating revenue	$	5,227		$	46,508
Operating expenses		5,914			54,011
Gain on sale of assets		71,422			82,023
Other income		929			3,902
Income before taxes	$	71,664		$	78,422
* The 2011 income statement includes only activity prior to the April 29, 2011, reconsolidation.

The following tables contain summarized financial information for Oxbow.

(THOUSANDS)	AT SEPTEMBER 30, 2011		AT DECEMBER 31, 2010
Current assets	$	685	$	583
Property, plant and equipment, net		23,422		23,597
Other assets		2,148		2,141
Total assets	$	26,255	$	26,321
Current liabilities	$	36	$	175
Other liabilities		73		-
Partners’ capital		26,146		26,146
Total liabilities and partners’ capital	$	26,255	$	26,321

	FOR THE THREE MONTHS ENDED SEPTEMBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	382	$	245
Operating expenses		382		245
Income before taxes	$	-	$	-

	FOR THE NINE MONTHS ENDED SEPTEMBBER 30,
(THOUSANDS)	2011		2010
Operating revenue	$	880	$	564
Operating expenses		880		564
Income before taxes	$	-	$	-

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Affiliate Transactions

9 Months Ended

Sep. 30, 2011

Affiliate Transactions [Abstract]

Affiliate Transactions

Note 13 — Affiliate Transactions

At September 30, 2011, Cleco Corporation had no affiliate balances that were payable to or due from its non-consolidated affiliates.

Cleco Power has affiliate balances that are payable to or due from its affiliates.  At September 30, 2011, the payable to Support Group was $6.4 million, the payable to Cleco Corporation was $0.9 million, and the payable to other affiliates was less than $0.1 million.  Also, at September 30, 2011, the receivable from Support Group was $2.7 million, the receivable from Midstream was $0.1 million, and the receivable from other affiliates was less than $0.1 million.

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Condensed Consolidated Statements of Income (Unaudited) (USD $) In Thousands, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating revenue
Electric operations	$ 324,532	$ 325,629	$ 823,484	$ 839,528
Tolling operations	9,133	11,153	16,137	23,016
Other operations	16,064	13,305	41,775	34,425
Affiliate revenue	0	119	202	1,426
Gross operating revenue	349,729	350,206	881,598	898,395
Electric customer credits	1,852	(6,314)	(3,405)	(6,314)
Operating revenue, net	351,581	343,892	878,193	892,081
Operating expenses
Fuel used for electric generation	122,774	100,587	298,009	276,727
Power purchased for utility customers	24,739	51,678	58,665	124,404
Other operations	32,872	30,288	92,206	86,786
Maintenance	14,587	23,362	59,666	58,832
Depreciation	30,557	28,847	89,641	82,899
Taxes other than income taxes	9,845	9,123	28,770	26,490
(Gain) loss on sales of assets	27	20	(468)	(37)
Total operating expenses	235,401	243,905	626,489	656,101
Operating income	116,180	99,987	251,704	235,980
Interest income	509	128	794	369
Allowance for other funds used during construction	902	887	3,757	11,052
Equity income (loss) from investees, before tax	(1)	2,494	62,051	39,212
Gain on toll settlement			0	148,402
Other income	2,128	2,755	3,330	3,563
Other expense	(3,360)	(1,416)	(4,969)	(4,379)
Interest charges
Interest charges, including amortization of debt expenses, premium, and discount	26,105	25,404	79,368	76,074
Allowance for borrowed funds used during construction	(326)	(336)	(1,357)	(4,054)
Total interest charges	25,779	25,068	78,011	72,020
Income before income taxes	90,579	79,767	238,656	362,179
Federal and state income tax expense	24,737	30,155	73,451	127,411
Net income	65,842	49,612	165,205	234,768
Preferred dividends requirements, net of tax	0	12	26	35
Preferred stock redemption costs, net of tax			112	0
Net income applicable to common stock	65,842	49,600	165,067	234,733
Average number of basic common shares outstanding (in shares)	60,467,595	60,471,183	60,549,860	60,405,388
Average number of diluted common shares outstanding (in shares)	60,873,311	60,825,298	60,830,251	60,632,138
Basic earnings per share
Net income applicable to common stock (in dollars per share)	$ 1.09	$ 0.82	$ 2.73	$ 3.89
Diluted earnings per share
Net income applicable to common stock (in dollars per share)	$ 1.08	$ 0.82	$ 2.71	$ 3.87
Cash dividends paid per share of common stock (in dollars per share)	$ 0.28	$ 0.25	$ 0.81	$ 0.725
CLECO POWER [Member]
Operating revenue
Electric operations	324,532	325,629	823,484	839,528
Other operations	15,565	12,819	40,261	32,959
Affiliate revenue	347	343	1,041	1,029
Gross operating revenue	340,444	338,791	864,786	873,516
Electric customer credits	1,852	(6,314)	(3,405)	(6,314)
Operating revenue, net	342,296	332,477	861,381	867,202
Operating expenses
Fuel used for electric generation	122,774	100,587	298,009	276,727
Power purchased for utility customers	24,739	51,678	58,665	124,404
Other operations	31,185	28,650	87,086	81,111
Maintenance	15,768	20,272	53,962	51,697
Depreciation	28,859	27,133	84,543	77,941
Taxes other than income taxes	8,802	9,161	25,585	25,110
(Gain) loss on sales of assets	(6)	7	(7)	47
Total operating expenses	232,121	237,488	607,843	637,037
Operating income	110,175	94,989	253,538	230,165
Interest income	276	117	557	351
Allowance for other funds used during construction	902	887	3,757	11,052
Other income	1,323	293	2,168	1,038
Other expense	(1,881)	(1,339)	(4,499)	(3,619)
Interest charges
Interest charges, including amortization of debt expenses, premium, and discount	25,632	16,380	75,386	61,158
Allowance for borrowed funds used during construction	(326)	(336)	(1,357)	(4,054)
Total interest charges	25,306	16,044	74,029	57,104
Income before income taxes	85,489	78,903	181,492	181,883
Federal and state income tax expense	31,656	26,568	61,935	58,299
Net income	$ 53,833	$ 52,335	$ 119,557	$ 123,584

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Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended		9 Months Ended										3 Months Ended		9 Months Ended					3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Jul. 05, 2011	Jan. 28, 2011	Dec. 31, 2010	Sep. 30, 2011 Diversified Lands Mitigation Escrow Agreement [Member]	Dec. 31, 2010 Diversified Lands Mitigation Escrow Agreement [Member]	Dec. 31, 2010 GO Zone Project Costs [Member]	Sep. 30, 2011 Future Storm Restoration Costs [Member]	Dec. 31, 2010 Future Storm Restoration Costs [Member]	Sep. 30, 2011 Katrina/Rita Bond Payments [Member]	Mar. 31, 2011 Katrina/Rita Bond Payments [Member]	Sep. 30, 2011 Katrina/Rita Bond Payments [Member]	Dec. 31, 2010 Katrina/Rita Bond Payments [Member]	Sep. 30, 2011 Renewable Energy Grant [Member]	Sep. 30, 2011 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member]	Dec. 31, 2010 Derivatives Not Designated As Hedging Instruments [Member] Fuel Cost Hedges [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Economic Hedges [Member] Other Operations Revenue [Member]	Sep. 30, 2010 Derivatives Not Designated As Hedging Instruments [Member] Economic Hedges [Member] Other Operations Revenue [Member]	Sep. 30, 2011 Treasury Rate Locks [Member]	Sep. 30, 2011 Cleco Power [Member]	Sep. 30, 2010 Cleco Power [Member]	Sep. 30, 2011 Cleco Power [Member]	Sep. 30, 2010 Cleco Power [Member]	Dec. 31, 2010 Cleco Power [Member]	Sep. 30, 2010 Cleco Power [Member] Cash Flows Related To Accruals for Property, Plant and Equipment [Member] As Reported [Member]	Sep. 30, 2010 Cash Flows Related To Accruals for Property, Plant and Equipment [Member] As Reported [Member]
Property, Plant and Equipment [Abstract]
Regulated utility plants	$ 3,604,938,000		$ 3,604,938,000				$ 3,552,054,000
Other	254,683,000		254,683,000				258,842,000
Total property, plant and equipment	3,859,621,000		3,859,621,000				3,810,896,000																3,604,938,000		3,604,938,000		3,552,779,000
Accumulated depreciation	(1,218,818,000)		(1,218,818,000)				(1,162,456,000)																(1,142,414,000)		(1,142,414,000)		(1,085,945,000)
Net property, plant and equipment	2,640,803,000		2,640,803,000				2,648,440,000																2,462,524,000		2,462,524,000		2,466,834,000
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	28,903,000		28,903,000				41,048,000	97,000	97,000	6,137,000	24,652,000	25,992,000	3,554,000		3,554,000	8,822,000	600,000
Decrease in restricted cash due to bond principal payment													6,000,000	6,300,000
Decrease in restricted cash due to bond interest payment													3,700,000	3,800,000
Increase in restricted cash due to collections															14,500,000
Risk Management [Abstract]
Realized gains (losses)																				(300,000)	(800,000)
Mark-to-market gains (losses)																				200,000	200,000
Unrealized gains (losses)																		(5,700,000)	(15,100,000)
Deferred gains (losses)																		(1,300,000)	(1,600,000)
Net collateral deposited	500,000		500,000				4,300,000
Interest rate cash flow hedge [Abstract]
Description of hedged item																						interest rate exposure on coupon payments related to a forecasted debt issuance.
Reference Rate As Of Period End																						2.89%
Notional amount of Treasury rate lock																						150,000,000
Unrealized mark-to-market gain (loss) on treasury rate lock																						(30,000,000)
Reference Rate As Of Contract Date																						3.77%
Reclassifications [Abstract]
Accounts receivable			(18,274,000)	(30,329,000)																					(20,442,000)	(31,579,000)		(50,579,000)	(49,329,000)
Accounts payable			(34,986,000)	(13,277,000)																					(30,345,000)	(12,137,000)		(16,621,000)	(17,248,000)
Retainage payable			(2,481,000)	0																					(2,481,000)	0		745,000	745,000
Net cash provided by operating activities			262,642,000	192,368,000																					184,688,000	99,688,000		76,949,000	170,141,000
Additions to property, plant and equipment			(145,669,000)	(252,711,000)																					(131,014,000)	(98,399,000)		75,660,000	230,485,000
Net cash used in investing activities			(54,097,000)	(234,819,000)																					(112,856,000)	(72,519,000)		(49,780,000)	(212,592,000)
Net decrease in cash and cash equivalents			(32,896,000)	(77,357,000)																					(41,897,000)	(110,729,000)		(110,729,000)	(77,357,000)
Cash and cash equivalents at beginning of period			191,128,000	145,193,000																					184,912,000	138,113,000		138,113,000	145,193,000
Cash and cash equivalents at end of period	158,232,000	67,836,000	158,232,000	67,836,000																			143,015,000	27,384,000	143,015,000	27,384,000		27,384,000	67,836,000
Accrued additions to property, plant and equipment			11,491,000	5,314,000																					20,088,000	4,757,000		17,506,000	17,506,000
Calculation of basic and diluted earnings per share [Abstract]
Income from continuing operations	65,842,000	49,612,000	165,205,000	234,768,000																			53,833,000	52,335,000	119,557,000	123,584,000
Deduct: non-participating stock dividends (4.5% preferred stock)		12,000	26,000	35,000
Deduct: non-participating stock redemption costs (4.5% preferred stock)			112,000	0
Basic net income applicable to common stock	65,842,000	49,600,000	165,067,000	234,733,000
Diluted net income applicable to common stock	65,842,000	49,600,000	165,067,000	234,733,000
Shares [Abstract]
Average number of basic common shares outstanding (in shares)	60,467,595	60,471,183	60,549,860	60,405,388
Effect of dilutive securities
Add: stock option grants (in shares)	20,441	26,680	20,965	29,771
Add: restricted stock (LTICP) (in shares)	385,275	327,435	259,426	196,979
Average number of diluted common shares outstanding (in shares)	60,873,311	60,825,298	60,830,251	60,632,138
Per Share Amount [Abstract]
Basic net income applicable to common stock (in dollars per share)	$ 1.09	$ 0.82	$ 2.73	$ 3.89
Diluted net income applicable to common stock (in dollars per share)	$ 1.08	$ 0.82	$ 2.71	$ 3.87
Preferred Stock Redemption [Abstract]
Outstanding shares of preferred stock (in shares)	0		0				10,288
Dividend rate (in hundredths)			4.50%
Redemption date			Jun. 24, 2011
Redemption price (in dollars per share)	$ 101		$ 101
Redemption price, plus accrued and unpaid dividends to the redemption date (in dollars per share)	$ 101.296		$ 101.296
Stock-Based Compensation [Abstract]
Non-vested stock granted (in shares)					40,000	145,002
Equity classification
Non-vested stock	1,095,000	573,000	3,042,000	1,703,000																			225,000	150,000	748,000	418,000
Stock options	69,000	13,000	105,000	38,000
Total equity classification	1,164,000	586,000	3,147,000	1,741,000																			225,000	150,000	748,000	418,000
Liability classification
Common stock equivalent units	1,024,000	1,237,000	2,583,000	1,867,000																			435,000	537,000	1,020,000	885,000
Total pre-tax compensation expense	2,188,000	1,823,000	5,730,000	3,608,000																			660,000	687,000	1,768,000	1,303,000
Tax benefit (excluding income tax gross-up)	$ 842,000	$ 702,000	$ 2,205,000	$ 1,388,000																			$ 254,000	$ 264,000	$ 680,000	$ 501,000

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Evangeline Transactions (Details) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Mar. 02, 2010	Feb. 26, 2010	Feb. 25, 2010	Feb. 22, 2010
Bonds Transferred from JPMVEC to Evangeline [Abstract]
Senior Secured bonds transferred and retired					$ 126,600,000
Stated interest rate of bonds transferred and retired (in hundredths)					8.82%
Accrued interest on transferred bonds eliminated					5,300,000
Payment by JPMVEC to Evangeline						56,700,000
Cancellation of letter of credit			15,000,000
Gain recorded on termination of operating lease	0	148,402,000
Redemption of remaining bonds [Abstract]
Face amount of remaining Senior Secured bonds					35,200,000
Accrued interest paid to debtholders					1,500,000
Make-whole payment on bond redemption					10,200,000
Unamortized debt issuance costs expensed					2,100,000
Restricted cash released upon redemption of bonds				$ 30,100,000

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Variable Interest Entities (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010	Dec. 31, 2010
Variable Interest Entity Equity Method [Abstract]
Total equity income	$ (1,000)	$ 2,494,000	$ 62,051,000		$ 39,212,000
Components of equity method investments [Abstract]
Total equity investment in investee	13,081,000		13,081,000			86,732,000
Oxbow [Member]
Variable Interest Entity [Line Items]
Variable interest entity, ownership percentage (in hundredths)			50.00%
Summarized financial information [Abstract]
Current assets	685,000		685,000			583,000
Property, plant and equipment, net	23,422,000		23,422,000			23,597,000
Other assets	2,148,000		2,148,000			2,141,000
Total assets	26,255,000		26,255,000			26,321,000
Current liabilities	36,000		36,000			175,000
Other liabilities	73,000		73,000
Partners' capital	26,146,000		26,146,000			26,146,000
Total liabilities and partners' capital	26,255,000		26,255,000			26,321,000
Operating revenue	382,000	245,000	880,000		564,000
Operating expenses	382,000	245,000	880,000		564,000
Components of equity method investments [Abstract]
Purchase price	12,873,000		12,873,000			12,873,000
Contributed assets (cash and land)	200,000		200,000			200,000
Total equity investment in investee	13,073,000		13,073,000			13,073,000
Comparison of carrying amount of assets and liabilities to maximum loss exposure [Abstract]
Net assets/liabilities	26,146,000		26,146,000			26,146,000
Entity's 50% equity	13,073,000		13,073,000			13,073,000
Cleco's maximum exposure to loss	13,073,000		13,073,000			13,073,000
Subsidiaries less than 100% owned by Cleco Innovations [Member]
Variable Interest Entity Equity Method [Abstract]
Total equity income	(1,000)		(2,000)		1,000
Cajun [Member]
Variable Interest Entity [Line Items]
Variable interest entity, ownership percentage (in hundredths)			50.00%	[1]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	298,800,000		298,800,000
Summarized financial information [Abstract]
Current assets						7,133,000
Property, plant and equipment, net						203,793,000
Total assets						210,926,000
Current liabilities						1,950,000
Other liabilities						9,429,000
Partners' capital						199,547,000
Total liabilities and partners' capital						210,926,000
Operating revenue		31,883,000	5,227,000	[2]	46,508,000
Operating expenses		30,566,000	5,914,000	[2]	54,011,000
Gain on sales of assets			71,422,000	[2]	82,023,000
Other income		3,671,000	929,000	[2]	3,902,000
Income (loss) before taxes		4,988,000	71,664,000	[2]	78,422,000
Entity's share of income tax expense (benefit)		1,000,000	24,000,000	[2]	14,800,000
Variable Interest Entity Equity Method [Abstract]
Total equity income		2,494,000	62,053,000		39,211,000
Net adjustment to equity income	26,200,000		26,200,000
Impairment of investment	45,900,000		45,900,000
Capitalized interest and other	$ 19,700,000		$ 19,700,000

[1] Investment interest ceased at the April 29, 2011 sale of Acadia Unit 2.

[2] The 2011 income statement includes only activity prior to the April 29, 2011 reconsolidation.

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Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees (Details) (USD $)	9 Months Ended		12 Months Ended			9 Months Ended							9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011 Discrimination Complaint [Member]	Dec. 31, 2010 Discrimination Complaint [Member]	Sep. 30, 2011 City of Opelousas Litigation [Member]	Sep. 30, 2011 Other Litigation Matters [Member]	Sep. 30, 2011 Madison Unit 3 Commitments [Member]	Sep. 30, 2011 Cleco Corporation [Member] Guarantee Issued to Entergy Louisiana and Entergy Gulf States for Performance Obligations of Perryville [Member]	Sep. 30, 2011 Cleco Corporation [Member] Guarantee Issued to Entergy Mississippi on behalf of Attala [Member]	Sep. 30, 2011 Cleco Corporation [Member] Guarantee Issued to Cleco Power on behalf of Acadia [Member]	Sep. 30, 2011 Cleco Corporation [Member] Guarantee Issued to Entergy Louisiana on behalf of Acadia [Member]	Sep. 30, 2011 Cleco Power [Member] Obligations Under Standby Letter of Credit Issued to the Louisiana Department of Labor [Member]	Sep. 30, 2011 Cleco Power [Member] Lignite Mining Agreement Guarantee [Member]	Sep. 30, 2011 APH [Member] Acadia Unit 1 Transaction [Member]	Sep. 30, 2011 APH [Member] Acadia Unit 2 Transaction [Member]	Sep. 30, 2011 Acadia Power Partners [Member] Acadia Unit 1 Transaction [Member]	Sep. 30, 2011 Acadia Power Partners [Member] Acadia Unit 1 Transaction [Member]
Loss Contingencies [Line Items]
Number of current employees who filed complaint		8
Number of former employees who filed complaint		4
Minimum amount sought by plaintiffs		$ 35,000,000				$ 32,000,000
Minimum amount sought by additional plaintiff		2,500,000
Number of claims settled and dismissed		1
Number of pending claims		12		252
Settlement agreement with charging party	1
Threshold of claims exceeded as a result of demand for arbitration						1,000,000
Associated payment demanded upon excess of claims threshold						19,000,000
Range of possible loss, maximum					6,000,000	32,500,000
Range of possible loss, minimum					2,000,000	4,000,000
Fuel Expenses Included in Audit	3,200,000,000
Risks and uncertainties [Abstract]
Letter of credit required if senior unsecured credit rating is not maintained						20,000,000
Additional letter of credit required in the event of further downgrade						15,000,000
Settlement amount with charging party			100,000			32,500,000
Guarantor Obligations [Line Items]
Face amount	4,225,000						42,400,000	500,000		10,000,000	3,725,000
Net amount	4,225,000						42,400,000	500,000			3,725,000
Liability recognized on the balance sheets	33,449,000						200,000					3,800,000	6,800,000	10,900,000
Percentage of ownership by affiliate (in hundredths)															100.00%	100.00%
Percentage of average losses on which letter of credit is based (in hundredths)											110.00%
Period (in years) over which average losses are determined											3Y
Fair value of indemnification liability recorded													13,500,000	21,800,000
Percentage of affiliate's indemnification liability accepted by entity (in hundredths)													50.00%	50.00%
Indemnification received from third parties													6,800,000	10,900,000
Term of indemnification obligation													3Y	3Y
Maximum residual value of indemnification obligation													0	200,000
Indemnification liability representing risk of payment													7,600,000	21,800,000
Income from contractual expiration of indemnification													500,000		1,000,000	1,100,000
Estimated maximum projected payment									10,000,000	298,800,000		72,500,000			30,000,000	30,000,000
Off-balance sheet commitments, expected termination dates [Abstract]
NET AMOUNT COMMITTED	4,225,000						42,400,000	500,000			3,725,000
LESS THAN ONE YEAR	3,725,000
MORE THAN 5 YEARS	500,000
On-balance sheet guarantees, expected termination dates [Abstract]
NET AMOUNT COMMITTED	33,449,000						200,000					3,800,000	6,800,000	10,900,000
1-3 YEARS	29,443,000
MORE THAN 5 YEARS	4,006,000
Total off-balance sheet commitments and on-balance sheet guarantees, expected termination dates [Abstract]
Total NET AMOUNT COMMITTED	37,674,000
Total LESS THAN ONE YEAR	3,725,000
Total 1-3 YEARS	29,443,000
Total MORE THAN 5 YEARS	4,506,000
New Markets Tax Credits [Abstract]
Equity contributions to be made to the fund	286,300,000
Net tax benefits and cash to be received from the fund	304,600,000
Excess net tax benefits to be received from the fund	18,300,000
Future equity contributions [Abstract]
Future equity contributions - 2011	11,508,000
Future equity contributions - 2012	76,629,000
Future equity contributions - 2013	36,225,000
Future equity contributions - 2014	22,927,000
Future equity contributions - 2015	21,904,000
Future equity contributions - Thereafter	20,808,000
Future equity contributions - Total	190,001,000
Due to be paid within the next twelve months	69,600,000
Tax benefits in excess of capital contributions	78,000,000
Tax benefits not utilized	63,600,000
Equity investments, imputed interest rate 6% [Abstract]
Principal payment schedule above:	190,001,000
Less: unamortized discount	22,098,000
Total	$ 167,903,000
Imputed interest rate (in hundredths)	6.00%
Period of recognition of gross investment amortization expense (in years)	10Y

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Regulatory Assets and Liabilities (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Dec. 31, 2010	Mar. 15, 2010	Feb. 12, 2010
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Total regulatory assets and liabilities, net	$ 444,990,000	$ 444,990,000	$ 406,108,000
Deferred construction carrying costs [Abstract]
Percentage of jurisdictional portion of construction carrying costs authorized to be collected from customers (in hundredths)		75.00%
Maximum percentage of projected retail revenues collected from customers (in hundredths)		6.50%
Amount of construction carrying costs to be returned to customers					183,200,000
Period over which construction carrying costs would be returned to customers (in years)		five
Revised period over which construction carrying costs would be returned to customers (in years)		four
Revised amount of construction carrying costs to be returned to customers				166,400,000
Amount of construction carrying costs returned to customers	126,100,000	126,100,000
Amount of construction carrying costs to be returned to customers within one year	33,300,000	33,300,000
Deferred fuel and purchased power costs [Abstract]
Percentage of total fuel cost regulated by LPSC (in hundredths)	94.00%
Change in under-recovered fuel costs		(1,200,000)
Deferral of additional fuel and purchased power costs		8,500,000
Change in mark-to-market losses on gas positions		(9,500,000)
Regulatory assets and liabilities - deferred taxes, net [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Total regulatory assets and liabilities, net	213,847,000	213,847,000	203,696,000
Deferred mining costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	19,755,000	19,755,000	21,666,000
Deferred interest costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	6,758,000	6,758,000	7,033,000
Deferred asset removal costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	814,000	814,000	768,000
Deferred postretirement plan costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	113,538,000	113,538,000	117,651,000
Deferred tree trimming costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	9,057,000	9,057,000	11,086,000
Deferred training costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	7,525,000	7,525,000	7,642,000
Deferred storm surcredits, net [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	9,080,000	9,080,000	10,633,000
Deferred construction carrying costs - assets [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	12,416,000	12,416,000	18,830,000
Lignite mining agreement contingency [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	3,781,000	3,781,000	3,781,000
AFUDC equity gross-up [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	74,496,000	74,496,000	74,859,000
Deferred rate case costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	1,252,000	1,252,000	1,654,000
Deferred Acadia Unit 1 acquisition costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	2,997,000	2,997,000	3,076,000
Deferred IRP/RFP costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	625,000	625,000	977,000
Deferred AMI pilot costs [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	185,000	185,000	283,000
Total regulatory assets - other [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	262,279,000	262,279,000	279,939,000
Deferred construction carrying costs - liability [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory Liabilities	40,298,000	40,298,000	87,875,000
Deferred fuel and purchased power [Member]
Schedule of Regulatory Assets and Liabilities, Net [Line Items]
Regulatory assets	$ 9,162,000	$ 9,162,000	$ 10,348,000