CNL-12.31.2012-10K

(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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
6.50% Senior Notes due 2035		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:

Title of each class
Membership Interests

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

Indicate by check mark if Cleco Corporation is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if Cleco Power LLC is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the Registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 the 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

References in this filing, including all items in Parts I, II, III, and IV, 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, II, III, and IV are defined below:



ABBREVIATION OR ACRONYM	DEFINITION
401(k) Plan	Cleco Power 401(k) Savings and Investment Plan
ABR	Alternate Base Rate which is the greater of the prime rate, the federal funds effective rate plus 0.50%, or the LIBOR plus 1.0%
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. Prior to February 2010, Acadia Unit 1 was owned by Acadia.
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
ARO	Asset Retirement Obligation
Attala	Attala Transmission LLC, a wholly owned subsidiary of Cleco Corporation
Brame Energy Center	A facility consisting of Nesbitt Unit 1, Rodemacher Unit 2, and Madison Unit 3. On June 11, 2010, Rodemacher Power Station was renamed Brame Energy Center.
CAA	Clean Air Act
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.
CERCLA	The Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CCN	Certificate of Public Convenience and Necessity
CLE Intrastate	CLE Intrastate Pipeline Company LLC, a wholly owned subsidiary of Evangeline
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
CO₂	Carbon dioxide
Coughlin	Coughlin Power Station, a combined-cycle, natural gas-fired power plant located in Evangeline Parish, Louisiana
CSAPR	The Cross-State Air Pollution Rule
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
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act, signed into law on July 21, 2010.
DOE	United States Department of Energy
EAC	Environmental Adjustment Clause
Entergy	Entergy Corporation
Entergy Arkansas	Entergy Arkansas, Inc.
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
ERO	Electric Reliability Organization
ESPP	Cleco Corporation Employee Stock Purchase Plan
Evangeline	Cleco Evangeline LLC, a wholly owned subsidiary of Midstream
Evangeline 2010 Tolling Agreement	Capacity Sale and Tolling Agreement between Evangeline and JPMVEC, which was executed in February 2010 and expired on December 31, 2011
Evangeline Restructuring Agreement	Purchase, Sale and Restructuring Agreement entered into on February 22, 2010, by Evangeline and JPMVEC



ABBREVIATION OR ACRONYM	DEFINITION
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.
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FRP	Formula Rate Plan
GAAP	Generally Accepted Accounting Principles in the United States
GDP-IPD	Gross Domestic Product – Implicit Price Deflator
Generation Services	Cleco Generation Services LLC, a wholly owned subsidiary of Midstream
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
ISO	Independent System Operator
JPMVEC	J.P. Morgan Ventures Energy Corporation. In September 2008, BE Louisiana LLC (an indirect wholly owned subsidiary of JPMorgan Chase & Co.) was merged into JPMVEC.
kWh	Kilowatt-hour(s) as applicable
LDEQ	Louisiana Department of Environmental Quality
LIBOR	London Inter-Bank Offer Rate
Lignite Mining Agreement	Dolet Hills Mine Lignite Mining Agreement, dated as of May 31, 2001
LPSC	Louisiana Public Service Commission
LTICP	Cleco Corporation Long-Term Incentive Compensation Plans
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.
MATS	Mercury and Air Toxics Standards
Midstream	Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Corporation
MISO	Midwest Independent Transmission System Operator
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service
MW	Megawatt(s) as applicable
MWh	Megawatt-hour(s) as applicable
NAC	North American Coal Corporation
NERC	North American Electric Reliability Corporation
NMTC Fund	USB NMTC Fund 2008-1 LLC was formed to invest in projects qualifying for New Markets Tax Credits and Solar Projects
Not Meaningful	A percentage comparison of these items is not statistically meaningful because the percentage difference is greater than 1,000%
NO₂	Nitrogen dioxide
NO_x	Nitrogen oxides
OATT	Open Access Transmission Tariff
OCI	Other Comprehensive Income
Oxbow	Oxbow Lignite Company, LLC, 50% owned by Cleco Power and 50% owned by SWEPCO
PCAOB	Public Company Accounting Oversight Board
PCB	Polychlorinated biphenyl
PEH	Perryville Energy Holdings LLC, a wholly owned subsidiary of Midstream
Perryville	Perryville Energy Partners, L.L.C., a wholly owned subsidiary of Cleco Corporation
Perryville and PEH Bankruptcy Court	U.S. Bankruptcy Court for the Western District of Louisiana, Alexandria Division
PLR	Private Letter Ruling
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
RTO	Regional Transmission Organization
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

This Annual Report on Form 10-K includes “forward-looking statements” about future events, circumstances, and results. All statements other than statements of historical fact included in this Annual Report are forward-looking statements, including, without limitation, 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 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 cost, 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 maintain its right to sell wholesale generation at market-based rates within its control area,


•	dependence of Cleco Power for energy from sources other than its facilities and future sources of such additional energy,


•	nonperformance by and creditworthiness of counterparties under power purchase agreements, or the restructuring of those agreements, including possible termination,


•	nonperformance by and creditworthiness of the guarantor counterparty of the NMTC Fund,


•	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 and LPSC audits, the formation of ICTs, including participation in an RTO and Cleco Power’s ability to recover related transmission upgrade costs, and the compliance with the ERO reliability standards for bulk power systems by Cleco Power and Evangeline,


•	reliance on third parties for determination of Cleco Power’s commitments and obligations to markets for generation resources and reliance on third party transmission services,


•	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 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,


•	changing 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 increased conservation efforts of customers,


•	reliability of Cleco Power’s and Midstream’s generating facilities,


•	acts of terrorism, cyber attacks, data security breaches or other attempts to disrupt Cleco’s business or the business of third parties, 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,


•	changes in tax laws or disallowances of uncertain tax positions that may result in a change to tax benefits or expenses,


•	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 AMI project,


•	costs and other effects of legal and administrative proceedings, settlements, investigations, claims and other matters,


•	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 that could limit or terminate the operation of certain generating units, increase costs, or reduce customer demand for electricity,


•	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 more discussion of these factors and other factors that could cause actual results to differ materially from those contemplated in the Registrants’ forward-looking statements, see Item 1A, “Risk Factors” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Cleco Power — Significant Factors Affecting Cleco Power” and “— Results of Operations — Midstream — Significant Factors Affecting Midstream,” in this Annual Report.

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.



GENERAL

Cleco Corporation was incorporated on October 30, 1998, under the laws of the State of Louisiana. Cleco Corporation is a public utility holding company which holds investments in several subsidiaries, including Cleco Power and Midstream, which are its operating business segments. Cleco Corporation, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to provisions of the Public Utility Holding Company Act of 2005.

Cleco Power’s predecessor was incorporated on January 2, 1935, under the laws of the State of Louisiana. Cleco Power was organized on December 12, 2000. Cleco Power is an electric utility engaged principally in the generation, transmission, distribution and sale of electricity within Louisiana. Cleco Power is regulated by the LPSC and FERC, along with other governmental authorities, which determine the rates Cleco Power can charge its customers. Cleco Power serves approximately 283,000 customers in Louisiana through its retail business and 10 communities across Louisiana and Mississippi through wholesale power contracts. Cleco Power’s operations are described below in the consolidated description of Cleco’s business segments.

Midstream, which was organized on September 1, 1998, under the laws of the State of Louisiana, is a merchant energy subsidiary that owns and operates a merchant power plant (Coughlin). Prior to April 29, 2011, Midstream also owned an indirect interest in a merchant power plant (Acadia). During 2009, Cleco Power and Entergy Louisiana executed definitive agreements whereby Cleco Power and Entergy Louisiana would each acquire one 580-MW unit of the Acadia Power Station. The transaction with Cleco Power was completed in February 2010, and the transaction with Entergy Louisiana was completed in April 2011. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. For more information on Acadia, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Other Commitments — Acadia Transactions” and Note 18 — “Acadia Transactions.” For more information on Evangeline, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Generation RFP.”

At December 31, 2012, Cleco had 1,259 employees.

Cleco’s mailing address is P.O. Box 5000, Pineville, Louisiana 71361-5000, and its telephone number is (318) 484-7400.

Cleco’s homepage on the Internet is located at http://www.cleco.com. Cleco Corporation’s and Cleco Power’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings with the SEC are available, free of charge, through Cleco’s website after those reports or filings are filed electronically with or furnished to the SEC. Cleco’s filings also can be obtained at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the

Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Cleco’s electronically filed reports also can be obtained on the SEC’s Internet site located at http://www.sec.gov. Cleco’s corporate governance guidelines, code of conduct for financial matters, ethics and business standards, and the charters of its board of directors’ audit, compensation, finance, and nominating/governance committees are available on its website and available in print to any shareholder upon request. Information on Cleco’s website or any other website is not incorporated by reference into this Report and does not constitute a part of this Report.

At December 31, 2012, Cleco Power had 992 employees. Cleco Power’s mailing address is P.O. Box 5000, Pineville, Louisiana, 71361-5000, and its telephone number is (318) 484-7400.

Cleco Power meets the conditions specified in General Instructions I(1)(a) and (b) to Form 10-K and therefore is 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 the following Part II items of Form 10-K: Item 6 (Selected Financial Data) and Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations); and the following Part III items of Form 10-K: Item 10 (Directors, Executive Officers, and Corporate Governance of the Registrants), Item 11 (Executive Compensation), Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters), and Item 13 (Certain Relationships and Related Transactions, and Director Independence).



OPERATIONS

Cleco Power

Segment Financial Information

Summary financial results of the Cleco Power segment for years 2012, 2011, and 2010 are presented in the following table.



(THOUSANDS)	2012			2011			2010
Revenue
Electric operations	$	944,169		$	1,051,956		$	1,086,102
Other operations	48,156			50,948			42,578
Electric customer credits	(630		)	(6,811		)	(9,596		)
Affiliate revenue	1,372			1,389			1,371
Operating revenue, net	$	993,067		$	1,097,482		$	1,120,455
Depreciation expense	$	125,486		$	115,634		$	107,966
Interest charges	$	80,502		$	97,090		$	78,731
Interest income	$	333		$	630		$	379
Federal and state income taxes	$	68,133		$	69,409		$	75,107
Segment profit	$	146,848		$	142,835		$	147,405
Additions to long-lived assets	$	222,104		$	201,980		$	449,052
Equity investment in investee	$	14,532		$	14,532		$	13,073
Segment assets	$	3,871,729		$	3,726,471		$	3,795,227

For more information on Cleco Power’s results of operations, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Cleco Power’s Results of Operations.”

Certain Factors Affecting Cleco Power

discussion of risk factors affecting Cleco Power’s business, see Item 1A, “Risk Factors — Transmission Constraints,” “— LPSC Audits,” “— Hedging and Risk Management Activities,” “— Commodity Prices,” “— Global Economic Environment and Uncertainty; Access to Capital,” “— Future Electricity Sales,” “— Cleco Power Generation Facilities,” “— MISO,” “— Reliability and Infrastructure Protection Standards Compliance,” “— Environmental Compliance,” “— Regulatory Compliance,” “— Cleco Power’s Rates,” “— Retail Electric Service,” “— Wholesale Electric Service,” “— Weather Sensitivity,” “— Cleco Credit Ratings,” “— Alternative Generation Technology,” “— Insurance,” “— Litigation,” “— Taxes,” “— Health Care Reform,” “— Technology and Terrorism Threats,” and “— Cleco Power Unsecured and Unsubordinated Obligations.”

Power Generation

As of December 31, 2012, Cleco Power’s aggregate net electric generating capacity was 2,436 MW. This amount reflects the maximum production capacity these units can sustain over a specified period of time. The following table sets forth certain information with respect to Cleco Power’s generating facilities:

Power Purchases

When the market price of power is more economical than self-generation of power or when Cleco Power needs power to supplement its own electric generation, and when transmission capacity is available, Cleco Power purchases power from energy marketing companies or neighboring utilities. These purchases are made from the wholesale power market. During 2012, power purchases were made at prevailing market prices. The lower cost per MWh of purchased power was primarily due to lower natural gas prices.

The following table sets forth the average cost and amounts of power purchased by Cleco Power on the wholesale market.



PERIOD	COST PER MWh		THOUSAND MWh	PERCENT OF TOTAL ENERGY REQUIREMENTS
2012	$	27.43	2,098	18.7
2011	$	38.94	1,569	13.5
2010	$	43.66	2,966	25.3
2009	$	34.57	5,712	53.6
2008	$	73.72	5,959	55.7

For information on Cleco Power’s ability to pass on to its customers substantially all of its fuel and purchased power expenses, see “— Regulatory Matters, Industry Developments, and Franchises — Rates.”

During 2012, Cleco Power met its capacity requirements with its owned generation, one long-term power purchase agreement, and the contracts with NRG Power Marketing LLC and Evangeline. The long-term contract, which expires in April 2018, is for the purchase of 20 MW of power from the Sabine River Authority, which operates a hydroelectric generating plant. The NRG Power Marketing LLC agreement provided 200 MW of capacity and energy from January 1, 2012, through April 30, 2012. The first agreement with Evangeline provided 250 MW of capacity and energy beginning January 1, 2012, through April 30, 2012. The second agreement was a three-year power purchase agreement providing 730 MW of capacity and energy with Evangeline for a delivery term beginning May 1, 2012, and ending April 30, 2015. Cleco expects to meet its native load demand in 2013 with Cleco Power’s own generation capacity and the contract with Evangeline. For more information on these contracts, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Generation RFP.”

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. Cleco Power’s power contracts, as well as spot market power purchases,

may be affected by these transmission constraints. For information on the Acadiana Load Pocket transmission project and how transmission constraints in this area have been reduced, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Cleco Power — Acadiana Load Pocket Transmission Project.”

Coal, Petroleum Coke, and Lignite Supply

Cleco Power uses coal for generation at Rodemacher Unit 2. Cleco Power has agreements with Cloud Peak Energy and Peabody Energy to provide the majority of coal needs through 2014. The coal supply agreements are fixed-priced for each year of the contract and together provide for the full requirements to support Cleco Power's minimum planned dispatch of Rodemacher Unit 2. Cleco Power actively manages its inventory levels throughout the year with spot purchases if necessary. With respect to transportation of coal, Cleco Power has an agreement with Union Pacific Railroad Company for transportation of coal from Wyoming's Powder River Basin to Rodemacher Unit 2 through December 31, 2016. Cleco Power leases approximately 241 railcars to transport its coal under two long-term leases, one expiring in March 2017, and the other expiring in March 2021.

Cleco Power uses a combination of petroleum coke and Illinois Basin Coal for generation at Madison Unit 3. Petroleum coke is a by-product of the oil refinery process and is not considered a fuel specifically produced for a market; however, more than adequate petroleum coke supplies are produced from refineries each year throughout the world, particularly in the Gulf Coast region. During 2012, Cleco received the majority of its petroleum coke supply from refineries located along the Lower Mississippi River. The majority of the petroleum coke purchases were in accordance with existing contracts ranging in terms of three to five years ending December 31, 2014. Petroleum coke spot purchases are typically short-term in nature ranging from one to three month terms. Each of the agreements are priced per the Jacobs Consultancy Petroleum Coke Quarterly Monthly Price Index or the “PACE” Monthly Index.

During 2012, Cleco purchased approximately 19,000 tons of Illinois Basin Coal from Peabody Energy and approximately 319,000 tons from Knight Hawk Coal, LLC. Cleco’s agreement with Knight Hawk Coal, LLC was for delivery of 400,000 tons during 2012 and 200,000 tons in 2013. The undelivered contract volume from 2012 will be purchased and delivered in 2013 at the original contract price along with the 2013 contracted volume. Cleco Power continues to use Louisiana waterways such as the Mississippi River and the Red River to deliver both petroleum coke and Illinois Basin Coal to the plant site. Savage Services is Cleco Power’s exclusive transportation provider. On December 28, 2012, Cleco Power entered into an amended agreement for 42 dedicated barges.

The initial term of this agreement is from the date of the amendment until August 31, 2017. The term of this agreement will automatically renew for successive periods of two years each unless written notice is provided by either party. After September 2014, Cleco Power has the option to purchase any or all of the dedicated barges. At December 31, 2012, Cleco Power’s petroleum coke inventory at Madison Unit 3 was approximately 244,000 tons and Cleco Power’s Illinois Basin Coal inventory at Madison Unit 3 was approximately 102,000 tons. The total fuel inventory is 346,000 tons (approximately a 69-day supply).

Cleco Power uses lignite for generation at the Dolet Hills Power Station. Cleco Power and SWEPCO each own an undivided 50% interest in the other’s leased and owned lignite reserves within the Dolet Hills mine in northwestern Louisiana. Additionally, through Oxbow, which is owned 50% by Cleco Power and 50% by SWEPCO, Cleco Power and SWEPCO control approximately 43 million tons of estimated recoverable lignite reserves also located in northwestern Louisiana. Cleco Power and SWEPCO have entered into a long-term agreement with DHLC for the mining and delivery of lignite reserves at both mines, the operations of which are conducted together by SWEPCO. The Amended Lignite Mining Agreement requires Cleco Power and SWEPCO to purchase the lignite mined and delivered by DHLC at cost plus a specified management fee. The term of this contract runs until all economically mineable lignite has been mined. The reserves from these mines are expected to be sufficient to fuel the Dolet Hills Power Station until at least 2026. At December 31, 2012, Cleco Power’s investment in Oxbow was $14.5 million. For information regarding deferred mining costs and obligations associated with this mining agreement see, Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 3 — Regulatory Assets and Liabilities — Mining Costs” and Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments.” For more information on Oxbow, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 12 — Variable Interest Entities — Equity Method VIEs — Oxbow.”

The continuous supply of coal and lignite may be subject to interruption due to adverse weather conditions or other factors that may disrupt mining operations or transportation to the plant site. At December 31, 2012, Cleco Power’s coal inventory at Rodemacher Unit 2 was approximately 194,000 tons (approximately an 88-day supply), and Cleco Power’s lignite inventory at Dolet Hills was approximately 227,000 tons (approximately a 36-day supply).

Natural Gas Supply

During 2012, Cleco Power purchased 36.8 million MMBtus of natural gas for the generation of electricity. The annual and average per-day quantities of gas purchased by Cleco Power from each supplier are shown in the following table.



NATURAL GAS SUPPLIER	2012 PURCHASES (MMBtu)	AVERAGE AMOUNT PURCHASED PER DAY (MMBtu)	PERCENT OF TOTAL NATURAL GAS USED
Gavilon, LLC	13,253,475	36,300	35.6	%
Shell Energy North America	7,205,000	19,700	19.3	%
ConocoPhillips Company	4,711,651	12,900	12.7	%
ChevronTexaco	3,528,286	9,700	9.5	%
Southwestern Energy Services	2,071,800	6,700	6.6	%
Citigroup Energy Inc.	1,720,732	4,700	4.6	%
Tauber Oil Company	783,703	2,100	2.1	%
Others	3,561,050	9,800	9.6	%
Total	36,835,697	101,900	100.0	%

Cleco Power owns natural gas pipelines and interconnections at all of its generating facilities which allow it to access various natural gas supply markets and maintain a more economical fuel supply for Cleco Power’s customers.

Natural gas was available without interruption throughout 2012. Cleco Power expects to continue to meet its natural gas requirements with purchases on the spot market through daily, monthly, and seasonal contracts with various natural gas suppliers. However, future supplies to Cleco Power remain vulnerable to disruptions due to weather events and transportation issues. Large industrial users of natural gas, including electric utilities, generally have low priority among gas users in the event pipeline suppliers are forced to curtail deliveries due to inadequate supplies. As a result, prices may increase rapidly in response to temporary supply interruptions. Partially addressing potential natural gas fuel curtailments and interruptions during 2012, Cleco contracted for natural gas storage with Pine Prairie Energy Center in 2010 for a period of five years ending in April 2015. Gas storage will be used to supply gas to Cleco Power’s generating facilities in the event of an interruption of supply due to events of force majeure and to operationally balance gas supply to the units. It will also be used to mitigate short-term natural gas price spikes that may occur. The storage volume is contracted by paying a capacity reservation charge at a fixed rate. There are also variable charges incurred to withdraw and inject gas from storage. To further address natural gas supply reliability, flexibility, and cost reduction, a capital project to connect Pine Prairie Energy Center to Acadia was approved in 2011. The new pipeline was completed in 2012 and is being used to supply fuel to Acadia. Currently, Cleco Power anticipates that its diverse supply options, gas storage, and alternative fuel capability, combined with its solid-fuel generation resources, are adequate to meet its fuel needs during any temporary interruption of natural gas supplies.

Sales

Cleco Power’s 2012 and 2011 system peak demands, which occurred on June 26, 2012, and August 3, 2011, were 2,282 MW and 2,355 MW, respectively. Sales and system peak demand are affected by weather and are typically highest during the summer air-conditioning season. In 2012, Cleco Power experienced above normal summer weather conditions and well below normal winter conditions. In 2011, Cleco Power experienced well above normal summer weather conditions and slightly below normal winter conditions. For information on the effects of future energy sales on Cleco Power’s results of operations, financial position, and cash flows, see Item 1A, “Risk Factors — Weather Sensitivity” and “— Future Electricity Sales.” For information on the financial

effects of seasonal demand on Cleco Power’s quarterly operating results, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 21 — Miscellaneous Financial Information (Unaudited).”

Capacity margin is the net capacity resources (either owned or purchased) less native load demand divided by net capacity resources. Each year, members of the SPP submit forecasted native load demand and the forecasted mix of net capacity resources to meet this demand. During 2012, Cleco Power’s capacity margin was 34.0%, which is above the SPP’s capacity margin benchmark of 12.0%, primarily due to the three-year power purchase agreement with Evangeline which provides 730 MW of capacity and energy. During 2011, Cleco Power’s capacity margin was 13.0%, primarily due to the addition of Acadia Unit 1 and Madison Unit 3 to Cleco Power’s capacity resources in 2010. Cleco Power expects to meet the SPP’s capacity benchmark of 12.0% in 2013.

Capital Investment Projects

For a discussion of Cleco Power’s capital investment projects, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Cleco Power — Acadiana Load Pocket Transmission Project,” and “— AMI Project.”

Midstream

Summary financial results of the Midstream segment for 2012, 2011, and 2010 are presented in the following table.



(THOUSANDS)	2012		2011			2010
Revenue
Tolling operations	$	25,559	$	19,004		$	26,067
Other operations	3		9			3
Affiliate revenue	—		45			960
Operating revenue, net	$	25,562	$	19,058		$	27,030
Depreciation expense	$	6,006	$	5,872		$	5,779
Interest charges	$	770	$	(28,996	)	$	7,140
Equity income from investees, before tax	$	—	$	62,053		$	38,848
Gain on toll settlement	$	—	$	—		$	148,402
Federal and state income tax expense	$	6,404	$	44,637		$	71,255
Segment profit	$	9,155	$	42,792		$	114,467
Additions to long-lived assets	$	8,759	$	8,437		$	2,113
Equity investment in investees	$	—	$	—		$	73,648
Total segment assets	$	215,342	$	233,891		$	316,166

As of December 31, 2012, Midstream wholly and directly owned three active limited liability companies that operated mainly in Louisiana.


•	Evangeline, which owns and operates Coughlin, a combined-cycle natural gas-fired power plant and owns a natural gas interconnection that allows for access to the natural gas supply market.


•	APH, which prior to April 29, 2011, owned a 50% indirect interest in Acadia, a combined-cycle natural gas-fired power plant.


•	Generation Services, which prior to December 24, 2011, offered power station operations and maintenance services. Its customers were Evangeline and Acadia. On December 24, 2011, Generation Services’ employees were transferred to Midstream.

The following table sets forth certain information with respect to Midstream’s operating generating facilities.



GENERATING STATION	COMMENCEMENT OF COMMERCIAL OPERATION	NAMEPLATE CAPACITY (MW)	NET CAPACITY (MW)		TYPE OF FUEL USED FOR GENERATION
Coughlin Unit 6	2000	264	259	⁽¹⁾	natural gas
Coughlin Unit 7	2000	511	494	⁽¹⁾	natural gas
Total capacity		775	753
⁽¹⁾ Based on capacity testing of generating units performed in December 2012.

Prior to December 31, 2011, Evangeline’s capacity was dedicated to one customer, JPMVEC. On February 22, 2010, Evangeline and JPMVEC entered into the Evangeline Restructuring Agreement whereby the parties agreed to terminate the Evangeline Tolling Agreement which was set to expire in 2020 and entered into the Evangeline 2010 Tolling Agreement, effective March 1, 2010. The Evangeline 2010 Tolling Agreement was an exclusive, market-based tolling agreement for Coughlin’s generating Units 6 and 7, expiring December 31, 2011, with an option for JPMVEC to extend the term of the agreement through December 31, 2012. The tolling agreement gave the tolling counterparty the right to own, dispatch, and market all of the electric generation capacity of the respective facility. Under the tolling agreement, the tolling counterparty was responsible for providing its own natural gas to the facility and paid a fixed fee and a variable fee for operating and maintaining the respective facility. JPMVEC did not exercise the option to extend the tolling agreement and as a result, Coughlin’s capacity and energy became available to Midstream beginning January 1, 2012. In January 2012, Evangeline began serving Cleco Power 250 MW of capacity and energy under an agreement through April 30, 2012, with the remaining output at Evangeline being marketed through an energy management services agreement with a third party marketer. In December 2011, Evangeline was notified that Cleco Power selected its proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power RFP for contractual resources beginning in May 2012. The proposal was for a 730-MW product beginning May 1, 2012, and ending April 30, 2015. The definitive agreement between Evangeline and Cleco Power was executed in January 2012 and was approved by the LPSC in March 2012 and FERC in April 2012. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. For information on the RFP, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Generation RFP.”

During 2009, Acadia executed definitive agreements with both Cleco Power and Entergy Louisiana whereby Cleco Power and Entergy Louisiana would each acquire one 580-MW unit of the Acadia plant. In February 2010, the transaction with Cleco Power was completed and in April 2011, the transaction with Entergy Louisiana was completed. Cleco Power assumed responsibility for operation of both units and continues to operate both units at the Acadia Power Station. For more information on these related transactions and risks and uncertainties, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Midstream — Significant Factors Affecting Midstream — Earnings are primarily affected by the

following factors.” For more information on Acadia’s transactions with Cleco Power and Entergy Louisiana, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Other Commitments — Acadia Transactions,” and Note 18 — “Acadia Transactions.”

In December 2011, Midstream contributed all of its ownership interests in CLE Intrastate to Evangeline. Prior to this transaction, CLE Intrastate’s revenue was generated primarily from a monthly reservation fee paid by Evangeline for access to the Columbia Gulf interconnect and from a transportation fee that varied depending on the amount of gas transported through the interconnect for use by Coughlin.

At December 31, 2012, Midstream had 32 employees. For more information on Midstream’s operations, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Midstream.”

Customers

No single customer accounted for 10% or more of Cleco’s consolidated revenue or Cleco Power’s consolidated revenue in 2012, 2011, or 2010. For more information regarding Cleco’s sales and revenue, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

Capital Expenditures and Financing

For information on Cleco’s capital expenditures, financing and related matters, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Cash Generation and Cash Requirements.”



REGULATORY MATTERS, INDUSTRY DEVELOPMENTS, AND FRANCHISES

Rates

Cleco Power’s electric operations are subject to the jurisdiction of the LPSC with respect to retail rates, standards of service, accounting, and other matters. Cleco Power also is subject to the jurisdiction of FERC with respect to rates for wholesale service, accounting, interconnections with other utilities, and the transmission of power and reliability. Periodically, Cleco Power has sought and received from both the LPSC and FERC increases in base rates to cover increases in operating costs and costs associated with additions to generation, transmission, and distribution facilities.

above the level included in base rates. The 2010 FRP allows Cleco Power to propose additional capital projects to the LPSC during its initial four-year term. Cleco Power anticipates requesting an extension of its current FRP in a second quarter 2013 filing with the LPSC. For more information on Cleco Power’s acquisition of Acadia Unit 1 and the Acadiana Load Pocket transmission project, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions — Acadia Unit 1” and Part II, Item 7, “Managements Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Acadiana Load Pocket Transmission Project.”

The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through an LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. The LPSC FAC General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit of FAC filings will be performed not less than every other year. In February 2012, after an audit of FAC filings, the LPSC Staff’s consultant issued a preliminary audit report recommending a cost disallowance of approximately $0.4 million plus interest for the years 2003 through 2008. There was no opposition from intervenors to the recommendations of the LPSC Staff’s consultant and the report was approved by the LPSC on July 18, 2012. Cleco Power made refunds of $0.4 million plus interest to customers during the September 2012 billing cycle. Cleco Power has FAC filings for the years 2009 through 2012 that remain subject to audit.

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for an EAC to recover certain costs of environmental compliance as an adder to customers’ bills. The costs eligible for recovery are prudently incurred air emissions credits associated with complying with federal, state, and local air emission regulations that apply to the generation of electricity reduced by the sale of such allowances. Variable emission mitigation costs, which are the cost of reagents such as ammonia and limestone that are used to reduce air emissions, are also eligible for recovery. In November 2011, the LPSC opened Docket No. X-32150 to audit the costs for the periods October 2009 through October 2010. The total amount of environmental expenses included in the audit was approximately $11.3 million. In April 2012, the LPSC Staff’s consultant issued an audit report recommending no cost disallowance for the review period. There was no opposition from intervenors to the recommendations of the LPSC Staff’s consultant and the report was approved by the LPSC on July 18, 2012. Cleco Power has EAC filings for the years 2010 through 2012 that remain subject to audit.

For more information on Cleco Power’s retail and wholesale rates, including Cleco Power’s FRP, see Item 1A, “Risk Factors — LPSC Audits,” “— Retail Electric Service,” “— Wholesale Electric Service,” and “— Cleco Power’s Rates” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Retail Rates of Cleco Power,” and — “Wholesale Rates of Cleco.”

Franchises

Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state regulation. These franchises are for fixed terms, which may vary from 10 years to 50 years or more. Historically, Cleco Power has been

substantially successful in the timely renewal of franchises as each neared the end of its term. Cleco Power’s next municipal franchise expires in July 2014.

Franchise Renewals

Cleco Power renewed the following franchise agreements during 2011 and 2012.



DATE	CITY	TERM	NUMBER OF CUSTOMERS
July 2011	Opelousas	10 years	10,000
July 2011	Colfax	30 years	800
November 2011	Keachi	30 years	60
November 2011	Patterson	22 years	2,760
December 2011	Baldwin	22 years	945
April 2012	Oakdale	27 years	3,300
April 2012	Slidell	33 years	15,900
May 2012	Berwick	22 years	2,600
October 2012	Basile	30 years	900
October 2012	Campti	30 years	600

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 alleged 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. On December 4, 2012, the Louisiana Supreme Court issued its opinion accepting Cleco’s jurisdictional arguments and dismissed the state court claims. The only matter remaining is before the 19th Judicial District Court to review the LPSC ruling in Cleco’s favor that it had properly charged the ratepayers of Opelousas. For more information regarding these complaints, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — City of Opelousas.”

Industry Developments

For information on industry developments, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Market Restructuring.”

Wholesale Electric Competition

For a discussion of wholesale electric competition, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Market Restructuring — Wholesale Electric Markets.”

Retail Electric Competition

For a discussion of retail electric competition, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Market Restructuring — Retail Electric Markets.”

Legislative and Regulatory Changes and Matters

Various federal and state legislative and regulatory bodies are considering a number of issues that could shape the future of the electric utility industry. Such issues include, among others:


•	the ability of electric utilities to recover stranded costs,


•	the role of electric utilities, independent power producers, and competitive bidding in the purchase, construction, and operation of new generating capacity,


•	the pricing of transmission service on an electric utility’s transmission system, or the cost of transmission services provided by an RTO/ISO,


•	FERC’s assessment of market power and utilities’ ability to buy generation assets,


•	mandatory transmission reliability standards,


•	FERC rulemakings encouraging migration of utility operations to RTOs,


•	the authority of FERC to grant utilities the power of eminent domain,


•	increasing requirements for renewable energy sources,


•	demand response and energy efficiency standards,


•	comprehensive multi-emissions environmental regulation in the areas of air, water, and waste,


•	regulation of greenhouse gas emissions,


•	FERC’s increased ability to impose financial penalties,


•	the American Recovery and Reinvestment Act of 2009,


•	the Dodd-Frank Act, and


•	the SEC’s requirement that financial statements be prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board by U.S. issuers for purposes of their filings with the SEC.

The Registrants are unable, at this time, to predict the outcome of such issues or effects on their results of operations, financial position, or cash flows.

For information on certain regulatory matters and regulatory accounting affecting Cleco, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters.”



ENVIRONMENTAL MATTERS

Environmental Quality

Cleco is subject to federal, state, and local laws and regulations governing the protection of the environment. Violations of these laws and regulations may result in substantial fines and penalties. Cleco has obtained the environmental permits necessary for its operations, and management believes Cleco is in compliance in all material respects with these permits, as well as all applicable environmental laws and regulations. Environmental requirements affecting electric power generation facilities are complex, change frequently, and have become more stringent over time as a result of new legislation, administrative actions, and judicial interpretations. Therefore, the capital costs and other expenditures necessary to comply with existing and new environmental requirements are difficult to determine. Cleco Power may request recovery from its retail customers of the

costs to comply with environmental laws and regulations. If revenue relief were to be approved by the LPSC, then Cleco Power’s retail rates could increase. If the LPSC were to deny Cleco Power’s request to recover all or part of its environmental compliance costs, then Cleco Power would bear those costs directly. Such a decision could negatively impact, perhaps significantly, the Registrants’ results of operations, financial condition, and cash flows. Cleco’s capital expenditures related to environmental compliance were $16.1 million during 2012 and are estimated to be $87.5 million in 2013. The following table lists capital expenditures, including AFUDC, for environmental matters by subsidiary.



SUBSIDIARY (THOUSANDS)	ENVIRONMENTAL CAPITAL EXPENDITURES FOR 2012		PROJECTED ENVIRONMENTAL CAPITAL EXPENDITURES FOR 2013
Cleco Power	$	16,096	$	87,474
Evangeline	7		—
Total	$	16,103	$	87,474

Projected environmental capital expenditures for 2013 include $85.0 million related to compliance with MATS and $2.0 million related to the selective non-catalytic reduction systems used to treat pollutants in order to comply with environmental regulations.

Air Quality

Air emissions from each of Cleco’s generating units are strictly regulated by the EPA and the LDEQ. The LDEQ has authority over and implements certain air quality programs established by the EPA under the federal CAA, as well as its own air quality regulations. The LDEQ establishes standards of performance and requires permits for electric generating units in Louisiana. All of Cleco’s generating units are subject to these requirements.

The EPA has proposed and adopted rules under the authority of the CAA relevant to the emissions of SO₂ and NO_xfrom Cleco’s generating units. The CAA established the Acid Rain Program to address the effects of acid rain and imposed restrictions on SO₂ emissions from certain generating units. The CAA requires these generating units to possess a regulatory “allowance” for each ton of SO₂ emitted beginning in the year 2000. The EPA allocates a set number of allowances to each affected unit based on its historic emissions. As of December 31, 2012, Cleco Power and Midstream had sufficient allowances for 2012 operations and expect to have sufficient allowances for 2013 operations under the Acid Rain Program.

The Acid Rain Program also established emission rate limits on NO_x emissions for certain generating units. Cleco Power is able to achieve compliance with the acid rain permit limits for NO_x at all of its affected facilities.

On July 6, 2011, the EPA finalized a rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” known as CSAPR that would require significant reductions in SO₂ and NO_x emissions from electric generating units (EGUs) in 28 states, including Louisiana. Under CSAPR, the EPA would set total emissions limits for each state allowing limited interstate trading (and unlimited intrastate trading) of emission allowances among power plants to comply with these limits beginning May 1, 2012. Specifically for Louisiana, CSAPR would limit NO_xemissions for the ozone season, which consists of the months of May through September.

On December 30, 2011, in response to numerous petitions by both state and industry participants, the D.C. Circuit Court of Appeals issued an order staying implementation of CSAPR pending resolution of legal challenges to the rule. The Court further ordered that the Clean Air Interstate Rule (CAIR), a predecessor rule to CSAPR, remain in place while CSAPR was stayed. On August 21, 2012, the D.C. Circuit Court of Appeals issued a 2-1 opinion vacating and remanding CSAPR. As such, CSAPR is vacated and CAIR is reinstated in its place for now. The D.C. Circuit Court ordered the EPA to rewrite the rule in an expeditious fashion to address the flaws of CSAPR. Early this year, the D.C Circuit Court denied a petition for rehearing by the EPA, leaving its only recourse filing a writ of certiorari seeking a Supreme Court review. If the EPA is unsuccessful in the appeals process and undertakes rewriting a new rule, it is uncertain what the new rule will entail. It is very likely that any compliance requirements of a new rule will be delayed for at least a year or more. Until then, CAIR remains in effect.

The EPA also has adopted rules under Section 112 of the CAA governing the emissions of mercury and other hazardous air pollutants from certain EGUs. The EPA established maximum achievable control technology (MACT) standards for coal-fired EGUs in late 2011, and signed a final rule setting forth national emissions standards for hazardous air pollutants (NESHAP) from coal- and oil-fired electric utility steam generating units on December 16, 2011. The final rule is now known as MATS. MATS requires affected EGUs to meet specific numeric emission standards and work practice standards to address hazardous air pollutants.

MATS imposes strict emission limits on new and existing coal- and liquid oil-fired EGUs for mercury, acid gases (hydrochloric acid, or HCI, as a surrogate), and non-mercury metallic pollutants (filterable particulate matter as a surrogate). Affected EGUs also have to comply with certain work practice standards to control the emission of organic air toxins.

MATS allows existing sources approximately three years to comply with the rule. The actual compliance deadline is April 16, 2015. A one-year compliance extension is available with approval from the relevant permitting authority, which in Cleco’s case is the LDEQ, if that facility is actively installing control equipment to comply with the rule.

Cleco completed its evaluation of control technology options for Dolet Hills, Madison Unit 3, and Rodemacher Unit 2. As noted previously, Cleco has identified capital expenditures that will be required to engineer, procure, and install pollution controls and emissions monitoring equipment to ensure Cleco will be in a position to comply with MATS in a timely manner.

Greenhouse gases (GHG) and their role in climate change have been the focus of recent study and legal action, including proposed federal legislation, final and proposed federal rulemakings, and civil actions. Fossil fuel-fired EGUs emit a significant amount of GHG in the combustion process. Congress has attempted to craft specific legislation that would reduce emissions of GHG by utilities, industrial facilities, and other manufacturing sectors of the economy. While Congressional attempts have not been successful, the possibility exists that federal GHG legislation may be enacted within the next several years.

In the absence of federal legislation, the EPA has recently adopted a series of rules under the CAA that, taken together, regulate GHG emissions from both mobile and stationary sources. As a result, beginning July 1, 2011, new major stationary sources of GHG emissions and major modifications

of existing stationary sources are required to obtain a permit for their GHG emissions. In its May 13, 2010, Prevention of Significant Deterioration (PSD) and Title V GHG “Tailoring Rule,” the EPA set the threshold for new major sources and major modifications of existing sources of GHG emissions at 100,000 tons per year and 75,000 tons per year of CO₂equivalents, respectively.

At this time, Cleco does not anticipate a modification at any of its existing sources that would trigger PSD and an associated Best Available Control Technology (BACT) demonstration for GHG.

In addition to its program for applying PSD and Title V permitting requirements to the largest stationary sources of GHG, the EPA has also committed to establish New Source Performance Standards (NSPS) for GHG emissions from fossil fuel power plants and refineries. On December 23, 2010, the EPA announced that it had settled litigation with states and environmental groups that sought to compel the EPA to establish NSPS. Under the settlement, the EPA committed to issue standards for new and modified facilities, and the power plant settlement also commits the EPA to issue standards for existing facilities. The EPA issued proposed NSPS rules for CO₂ on April 13, 2012. This proposal only affects new units and contains no requirements for modifications or for existing units. This rule has not yet been finalized. Cleco expects that the EPA will eventually issue guidelines to the states requiring them to adopt and submit to the EPA for approval standards for existing, unmodified facilities that conform to those guidelines. Once the state standards are approved by the EPA and become effective, existing unmodified facilities must be given a reasonable amount of time to comply with the standards. At this time, Cleco cannot predict what these standards will entail or what level of GHG controls the EPA and the state of Louisiana will require. However, any new rules that require significant reductions of GHG emissions from EGUs could require potentially significant expenditures or modification or curtailment of operations to maintain or achieve compliance.

The enactment of federal or state renewable portfolio standards (RPS) mandating the use of renewable and alternative fuel sources such as wind, solar, biomass, and geothermal could result in certain changes in Cleco’s business or its competitive position. These changes could include additional costs for renewable energy credits, alternate compliance payments, or capital expenditures for renewable generation resources. RPS legislation has been enacted in many states and Congress is considering various bills that would create a national RPS. Cleco continues to evaluate the impacts of potential RPS legislation on its businesses based on the RPS programs in other states. Cleco will continue to monitor developments related to RPS at the federal and state levels. For information on Cleco’s actions resulting from the LPSC’s Renewable Energy Order, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Generation RFP — Renewable Energy Pilot Program.”

As part of its periodic re-evaluation of the protectiveness of the National Ambient Air Quality Standards (NAAQS), the EPA has adopted rules that strengthen the NAAQS for specific criteria pollutants including ozone, NO₂, and SO₂. In 2008, the EPA issued a NAAQS for ozone of 75 parts per billion (ppb). The EPA subsequently proposed to lower that standard, but dropped its proposed reconsideration and is currently moving

ahead with states, including Louisiana, to implement the 75 ppb ozone under the 2008 NAAQS. The EPA has recommended the five-parish area around Baton Rouge as a non-attainment area for ozone under the 2008 NAAQS, which will require Louisiana to establish a state implementation plan to bring those areas back into attainment by 2015. Since NO_x emissions are a precursor to ozone formation, existing fossil fuel-fired EGUs located in or near ozone non-attainment areas could be targeted for installation of additional NO_x emission controls. Cleco cannot determine the potential impact of this rule on its generating units until Louisiana finalizes its state implementation plan for this rule.

A revised primary NAAQS for NO₂ promulgated by the EPA took effect on April 12, 2010. The EPA established a new one-hour standard at a level of 100 ppb to supplement the existing annual standard. In January 2012, the EPA determined that no area in the country was violating the standard. However, the LDEQ expects to operate new monitors at two portions of highway in the Baton Rouge and New Orleans areas. The EPA may redesignate areas based on new data it receives from states. Due to the fact that fossil fuel-fired EGUs are a significant source of NO₂ emissions in the country, a non-attainment designation could result in utilities such as Cleco being required to substantially reduce their NO₂ emissions. However, because no state implementation plan has been proposed, Cleco cannot predict the potential impacts of such a rule on its generating units at this time.

The EPA revised the NAAQS for SO₂on June 22, 2010. The new standard is now a one-hour health standard of 75 ppb, designed to reduce short-term exposures to SO₂ ranging from five minutes to 24 hours. An important aspect of the new SO₂ standard is a revised emission monitoring network combined with a new ambient air modeling approach to determine compliance with the new standard. The LDEQ has recommended St. Bernard and East Baton Rouge as non-attainment areas. The EPA expects to identify or designate areas not meeting the new standard by July 2013. Utilities could be required to substantially reduce their SO₂ emissions to comply with this NAAQS. However, because no state implementation plan has been proposed, Cleco is unable to determine the potential impacts of this rule on its generating units at this time.

In February 2005, Cleco Power received notices from the EPA requesting information relating to the Brame Energy Center and the Dolet Hills Power Station. The apparent purpose of the data request is to determine whether Cleco Power has complied with New Source Review and NSPS requirements under the CAA in connection with capital expenditures, modifications, or operational changes made at these facilities. Cleco Power has completed its response to the initial data request. It is unknown at this time whether the EPA will take further action as a result of the information provided by Cleco Power.

Water Quality

Cleco’s facilities also are subject to federal and state laws and regulations regarding wastewater discharges. Cleco has received from the EPA and the LDEQ permits required under the federal Clean Water Act (CWA) for wastewater discharges from its generating stations. Wastewater discharge permits have fixed dates of expiration, and Cleco applies for renewal of these permits within the applicable time periods.

On March 28, 2011, the EPA proposed regulations which would establish standards for cooling water intake structures at

existing power plants and other facilities pursuant to Section 316(b) of the CWA. The standards are intended to protect fish and other aquatic wildlife by minimizing capture both in screens attached to intake structures (impingement mortality), and in the actual intake structures themselves (entrainment mortality). For existing facilities that are designed to draw at least two million gallons per day of water from waters of the United States and use at least 25% of the water they withdraw exclusively for cooling, the proposed standards would (1) set a performance standard, measured as a fish mortality rate due to impingement, or reduce the flow velocity at cooling water intakes to less than 0.5 feet per second, and (2) require entrainment standards to be determined on a case-by-case basis by state delegated permitting authorities. Facilities subject to the proposed standards would have a maximum of eight years to comply with the impingement requirements, although state permitting authorities would have discretion to set a shorter deadline. Compliance with entrainment standards would be required “as soon as possible,” by a date to be determined by the same permitting authorities. As presently drafted, portions of the proposed rule could apply to all of Cleco’s fossil fuel steam electric generating stations. Until more thorough studies are conducted, including technical and economic evaluations of the control options available and a final rule is issued, Cleco remains uncertain which technology options or retrofits would be required to be installed on its affected facilities. However, the costs of required technology options and retrofits could be significant, especially if closed cycle cooling is required.

The CWA requires the EPA to periodically review and, if appropriate, revise technology based effluent limitations guidelines for categories of industrial facilities, including power generating facilities. The EPA is currently expected to issue proposed revised steam electric effluent limitations guidelines by May 2013 and final revised steam electric effluent limitations guidelines by June 2014. The revised effluent limitations guidelines could require costly technological upgrades at Cleco’s existing facilities, in particular if additional wastewater treatment systems are required to be installed. Since the revised regulations are yet to be proposed, Cleco is unable to predict what the new effluent limitations guidelines will be or how significant the costs may be for Cleco to comply.

Solid Waste Disposal

In the course of operations, Cleco’s facilities generate solid and hazardous waste materials requiring management or eventual disposal. The Solid Waste Division of the LDEQ has adopted a permitting system for the management and disposal of solid waste generated by power stations. Cleco has received all required permits from the LDEQ for the on-site disposal of solid waste from its generating stations.

On May 18, 2010, the EPA released a proposed rule for regulating the disposal and management of coal combustion by products or residuals (CCRs) from coal-fired power plants. Rather than offering a single approach, the EPA requested comments on two options for regulating CCRs. The first, known as the “Subtitle C” option, would regulate CCRs as a new special waste subject to many of the requirements for hazardous waste, while the second, known as the “Subtitle D” option, would regulate CCRs in a manner similar to industrial solid waste. Either of the EPA proposed options represents a shift toward more comprehensive and costly requirements for CCR disposal and management, but the Subtitle C option contains significantly more stringent requirements and will

require greater capital and operating costs to comply with that rule, if finalized. Both options seem to allow the continued use of ash for certain beneficial reuses. Depending upon the outcome of the final rule, this regulatory proposal could significantly impact the manner and cost in which Cleco Power manages its CCRs. The final CCR rule is expected to be issued by the EPA in late 2013 or by mid 2014. Any stricter requirements imposed on coal ash and associated ash management units by the EPA as a result of this new rule could significantly increase the cost of operating existing units or require them to be significantly upgraded. Until a final rule is promulgated, Cleco is unable to determine how significant the costs associated with potentially stricter requirements are likely to be.

Cleco produces certain wastes that are classified as hazardous at its electric generating stations and at other locations. Cleco does not treat, store long-term, or dispose of these wastes on-site; therefore, no permits are required. All hazardous wastes produced by Cleco are properly disposed of at permitted hazardous waste disposal sites.

Toxic Substances Control Act (TSCA)

The TSCA directs the EPA to regulate the marketing, disposal, manufacturing, processing, distribution in commerce, and use of PCBs. Cleco may continue to operate equipment containing PCBs under the TSCA. Once the equipment reaches the end of its usefulness, the EPA regulates handling and disposal of the equipment and fluids containing PCBs. Within these regulations, the handling and disposal is allowed only through the EPA approved and permitted facilities. Cleco properly disposes its PCB waste material at TSCA permitted disposal facilities.

Toxics Release Inventory (TRI)

The TRI requires an annual report from industrial facilities on about 650 substances that the facilities release into air, water, and land. The TRI ranks companies based on how much of a particular substance they release on a state and parish (county) level. Annual reports are due to the EPA on July 1 following the reporting year-end. Cleco has submitted required TRI reports on its activities, and the TRI rankings are available to the public. The rankings do not result in any federal or state penalties.

Electric and Magnetic Fields (EMFs)

The possibility that exposure to EMFs emanating from electric power lines, household appliances, and other electric devices may result in adverse health effects or damage to the environment has been a subject of some public attention. Lawsuits alleging that the presence of electric power transmission and distribution lines has an adverse effect on health and/or property values have arisen in several states. Cleco Power is not a party in any lawsuits related to EMFs.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

In October 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study (RI/FS) from the EPA pursuant to CERCLA (also known as the Superfund statute). CERCLA establishes several classes of PRPs for a contaminated site and imposes strict, joint and several liability on those PRPs for the cost of response to the contamination. The special notice requested that Cleco Corporation and Cleco Power, along with many other listed PRPs, enter into

The following risk factors could have a material adverse effect on results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Registrants.

Transmission Constraints

Transmission constraints could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Cleco Power relies on two main suppliers of electric transmission when accessing external power markets. At times, even after completion of the Acadiana Load Pocket transmission project, physical constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory, which in turn can affect capacity or power purchases under long-term contracts, as well as spot market power purchases. If the amount of purchased power actually delivered into Cleco’s transmission system were to be less than the amount of power contracted for delivery, Cleco Power may rely on its own generation facilities to meet customer demand. Cleco Power’s incremental generation cost at that time could be higher than the cost to purchase power from the wholesale power market, thereby increasing its customers’ ultimate cost. In addition, the LPSC may not allow Cleco Power to recover part or all of its generation cost, which could be substantial.

LPSC Audits

The LPSC conducts fuel audits that could result in Cleco Power making substantial refunds of previously recorded revenue.

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 expenses. Recovery of FAC costs is subject to a periodic fuel audit by the LPSC. The LPSC FAC General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit will be performed not less than every other year.

Cleco Power currently has FAC filings for 2009 through 2012 subject to audit. Management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. 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. The most recent fuel audit completed by the LPSC was for the years 2003 through 2008 and resulted in Cleco Power making refunds of $0.4 million plus interest to customers during the September 2012 billing cycle.

The LPSC conducts environmental audits that could result in Cleco Power making substantial refunds of previously recorded revenue.

Cleco Power has environmental adjustment clause filings for the years 2010 through 2012 that remain subject to audit. These variable emission mitigation costs were historically recovered through the FAC. Management is not able to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. However, if a disallowance of environmental 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.

Hedging and Risk Management Activities

Cleco Power is subject to market risk associated with fuel cost hedges relating to open natural gas contracts. Cleco has risk management policies which cannot eliminate all risk involved in its energy commodity activities.

Cleco Power may enter into fuel cost hedge positions to mitigate the volatility in fuel costs passed through to its retail customers. When these positions close, actual gains or losses are deferred and included in the FAC in the month the physical contract settles. However, recovery of any of these FAC costs is subject to, and may be disallowed as part of, a prudency review or a periodic fuel audit conducted by the LPSC.

Cleco Power manages its exposure to energy commodity activities by maintaining risk management policies and establishing and enforcing risk limits and risk management procedures. These risk limits and risk management procedures cannot eliminate all risk associated with these activities, particularly if intentional misconduct is involved.

Financial derivatives reforms could increase the liquidity needs and costs of Cleco Power’s commercial trading operations.

In July 2010, Congress enacted federal legislation to reform financial markets that significantly altered how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring

standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gave the CFTC authority to exempt end users of energy commodities. The end user exemption reduces, but does not eliminate, the applicability of these measures. Cleco Power qualifies for the end user exemption and intends to apply for it at the appropriate time. These requirements could cause Cleco Power’s future OTC transactions to be more costly and have an adverse effect on its liquidity due to additional capital requirements. In addition, by standardizing OTC products, these reforms could limit the effectiveness of Cleco Power’s hedging programs because Cleco Power would have less ability to tailor OTC derivatives to match the precise risk it is seeking to protect.

Commodity Prices

Cleco Power is subject to the fluctuation in the market prices of various commodities which may increase the cost of producing power.

Cleco Power purchases natural gas, petroleum coke, lignite, and coal under long-term contracts and on the spot market. Historically, the markets for natural gas, petroleum coke, and coal have been volatile and are likely to remain volatile in the future. Cleco Power’s retail and wholesale rates include a FAC that enables it to adjust rates for monthly fluctuations in the cost of fuel and purchased power. However, recovery of any of these FAC costs is subject to, and may be disallowed as part of, a prudency review or a periodic fuel audit conducted by the LPSC or FERC.

Global Economic Environment and Uncertainty; Access to Capital

The global economic environment and uncertainty may negatively impact Cleco’s business and financial condition, pension plan, lenders, and customers.

The global economic environment and uncertainty may have an impact on Cleco’s business and financial condition. Cleco’s pension plan portfolio has experienced significant volatility due to market conditions and may experience material losses in the future. The losses, in conjunction with plan funding requirements, could result in required pension plan contributions significantly higher and earlier than previously anticipated, which could have a material adverse impact on Cleco’s results of operations, financial condition, and cash flows. Further, the current economic environment and uncertainty could have a material adverse impact on Cleco’s lenders or its customers, causing them to fail to meet their obligations to Cleco or to delay payment of such obligations. Additionally, the current economic environment and uncertainty could lead to reduced electricity usage, which could have a material adverse impact on the Registrants’ results of operations, financial condition, and cash flows.

The Registrants depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in commodity prices. Disruptions in the capital and credit markets may adversely affect the Registrants’ ability to meet liquidity needs, access capital to operate and grow their businesses, and the cost of capital.

The Registrants’ business is capital intensive and dependent upon their respective ability to access capital at reasonable rates and other terms. At times there are spikes in the price for natural gas and other commodities that increase the Registrants' liquidity requirements. In addition, the Registrants' liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in the Registrants' service territory with Hurricanes Katrina and Rita in 2005. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel, purchased power, or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, or other unknown events, such as future storms, could cause the financing needs of the Registrants to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the Registrants' respective credit ratings, which in turn could negatively affect access to capital markets.

The global capital and credit markets have experienced extreme volatility and disruption in the recent past. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect the Registrants' ability to maintain and expand their business. Events beyond the Registrants' control, such as volatility and disruption in global capital and credit markets, may create uncertainty that could increase their cost of capital or impair their ability to access the capital markets, including the ability to draw on their respective bank credit facilities. The Registrants are unable to predict the degree of success they will have in renewing or replacing their respective credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If the Registrants are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could have a material adverse impact on the Registrants' ability to fund capital expenditures or debt service or on the Registrants' flexibility to react to changing economic and business conditions.

Future Electricity Sales

Cleco Power’s future electricity sales and corresponding base revenue and cash flows could be adversely affected by general economic conditions.

General economic conditions can negatively impact the businesses of Cleco Power’s industrial and commercial customers resulting in decreased power consumption, which causes a corresponding decrease in revenue. In the past, recessions have adversely affected MWh sales due to closures and reductions in load requirements across Cleco Power’s industrial customer base, particularly among manufacturers of wood and paper products. The paper industry continues to be vulnerable to decreasing demand for its products, and the downturn in residential home construction also has caused a significant reduction in the demand and prices for lumber and other wood products. Reduced production or the shut down of any of these customers’ facilities could substantially reduce Cleco Power’s base revenue.

Energy conservation and energy efficiency efforts could have a material adverse effect on Registrant's results of operations, financial condition, and cash flows.

Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand. Future electricity sales could be impacted by industrial customers switching to alternative sources of energy, including on-site power generation and retail customers purchasing less electricity due to increased conservation efforts or expanded energy efficiency measures. Unless there is a regulatory solution, declining usage will result in an under-recovery of fixed costs at Cleco Power's rate regulated business. A reduction in energy demand could have a material adverse effect on the Registrants' results of operations, financial condition, and cash flows.

Cleco Power Generation Facilities

Cleco Power’s generation facilities are susceptible to unplanned outages, significant maintenance requirements, and interruption of fuel deliveries.

The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel supply interruption, and performance below expected levels of output or efficiency. Almost one-third of Cleco Power’s net capacity is at facilities that were originally constructed before 1980. Older equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to operate at peak capacity or availability, or to comply with environmental permits. If Cleco Power fails to make adequate expenditures for equipment maintenance, Cleco Power risks incurring more frequent unplanned outages, higher than anticipated operating and maintenance expenditures, increased fuel or power purchase costs, and potentially the loss of revenue related to competitive opportunities. Newer equipment can be subject to premature failures.

Cleco Power’s generating facilities are fueled primarily by coal, natural gas, petroleum coke, and lignite. The deliverability of these fuel sources may be constrained due to such factors as higher demand, production shortages, weather-related disturbances, waterway levels, or lack of transportation capacity. If the suppliers are unable to deliver the contracted volume of fuel, Cleco Power would have to replace any deficiency with alternative sources, which may not be as favorable and could increase the ultimate cost of fuel to customers. Fuel and purchased power expenses are recovered from customers through the FAC, which is subject to refund until either a prudency review or a periodic fuel audit is conducted by the LPSC.

Competition for access to other natural resources, particularly oil and natural gas, could negatively impact Cleco Power’s ability to access its lignite reserves. Land owners may grant other parties access for oil and natural gas drilling in the same area to which Cleco has been granted access for lignite reserves. Placement of drilling rigs and pipelines for developing oil and gas reserves can preclude access to lignite in the same areas making the right of first access critical with respect to extracting lignite. Competition for the right of first access may need to be determined through legal processes. Additionally, Cleco Power could be indirectly liable for the impacts of other companies’ activities on lands that have been mined and reclaimed by Cleco Power. Loss of access to

lignite reserves or the liability for impacts on reclaimed lands could have material adverse effects to the Registrants’ results of operations, financial condition, and cash flows.

The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Cleco Power could be materially affected.

Cleco Power's ability to complete construction of, or capital improvements to, power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, engineering and project execution risk and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in laws or regulations, including environmental compliance requirements, and other events beyond the control of Cleco Power may occur that may materially affect the schedule, cost, and performance of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Cleco Power could incur additional costs and termination payments, face increased risk of potential write-off of the investment in the project, or may not be able to recover such costs.

MISO

MISO market operations could have a material adverse effect on

the Registrants' results of operations, production costs, financial condition, and cash flows.

On December 6, 2012, Cleco Power filed an application with the LPSC requesting a public interest determination to find in favor of the transfer of functional control of certain transmission assets to MISO, to create an accounting order deferring costs related to Cleco Power’s transition into the MISO organization, and to expedite treatment. Cleco Power anticipates joining the MISO RTO by January 2014.

The MISO market region that Cleco Power will be a part of is referred to as “MISO South,” which encompasses parts of Arkansas, Louisiana, Mississippi and Texas. Once integrated, Cleco Power will no longer make economic or routine dispatch decisions regarding its generating assets that affect reliability of the bulk transmission electric system. Commitment of generation resources to the market will be determined by MISO based on priced offers. All operational impacts and production cost projections have been based on analytical assumptions on how the region will operate with both Cleco Power and Entergy as members. Future energy costs will be heavily influenced by MISO's dispatch of the generating assets owned not only by Cleco Power, but all market participants in the new MISO South region. Also, the recovery of transition costs to join MISO and new MISO billing determinants is dependent on a favorable accounting order from the LPSC.

MISO will evaluate forced outage rates to assess each generating unit capacity for planning reserve functions. Should Cleco Power units not perform to MISO standards, Cleco Power may not possess sufficient planning reserves to

serve its needs and could be forced to purchase capacity from the market. The costs of such capacity may not be recoverable and could have a material adverse effect on the Registrants’ results of operations, production costs, financial condition, and cash flows.

Reliability and Infrastructure Protection Standards Compliance

Cleco is subject to mandatory reliability and critical infrastructure protection standards. Fines and civil penalties are imposed on those who fail to comply with these standards.

NERC serves as the ERO with authority to establish and enforce mandatory reliability and infrastructure protection standards, subject to FERC approval, for users of the nation’s transmission system. FERC enforces compliance with these standards. New standards are being developed and existing standards are continuously being modified.

As these standards continue to be adopted and modified, they may impose additional compliance requirements on Cleco Power and Midstream operations, which may result in an increase in capital expenditures and operating expenses. Failure to comply with these standards can result in the imposition of material fines and civil penalties.

In February 2010, the SPP RE notified Cleco that an audit would be conducted to determine Cleco’s compliance with the NERC Reliability Standard and Critical Infrastructure Protection cybersecurity standard requirements. The audit was conducted in April 2010. Cleco submitted mitigation plans and evidence of remedial efforts in connection with the SPP’s initial findings from the audit. Cleco and the SPP agreed to a financial settlement totaling less than $0.1 million, which has been approved by NERC. Cleco’s next scheduled NERC Critical Infrastructure Protection audit is expected to begin in March 2013. The next NERC Reliability audit is scheduled to begin in November 2013. Management is unable to predict the outcome of the future audit or whether it will have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Environmental Compliance

Cleco’s costs of compliance with environmental laws and regulations are significant. The costs of compliance with new environmental laws and regulations, as well as the incurrence of incremental environmental liabilities, could be significant to the Registrants.

Cleco is subject to extensive environmental oversight by federal, state, and local authorities and is required to comply with numerous environmental laws and regulations related to air quality, water quality, waste management, natural resources, and health and safety. Cleco also is required to obtain and comply with numerous governmental permits in operating its facilities. Existing environmental laws, regulations, and permits could be revised or reinterpreted, and new laws and regulations could be adopted or become applicable to Cleco. For example, the EPA has announced rules that it will regulate CO₂ and hazardous air pollutants from electric generating units. Cleco may incur significant capital expenditures or additional operating costs to comply with these revisions, reinterpretations, and new requirements. If Cleco fails to comply, it could be subject to civil or criminal liabilities and fines or may be forced to shut down or reduce production from its facilities. Cleco cannot predict the

outcome of pending or future legislative and rulemaking proposals.

Environmental advocacy groups, states, other organizations, some government agencies, and the presidential administration are focusing considerable attention on the potential role in climate change from power generation facilities emissions, including CO₂ emissions. Future changes in environmental regulations governing power plant emissions could make some of Cleco’s electric generating units uneconomical to maintain or operate. In addition, any legal obligation that would require Cleco to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and could raise uncertainty about the future viability of some fossil fuels as an energy source for new and existing electric generation facilities. Cleco cannot predict the outcome of pending or future legislative and rulemaking proposals.

Cleco Power may request recovery from its customers of its costs to comply with new environmental laws and regulations. If the LPSC were to deny Cleco Power’s request to recover all or part of its environmental compliance costs, there could be a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Regulatory Compliance

Cleco operates in a highly regulated environment and adverse regulatory decisions or changes in applicable regulations could have a material adverse effect on the Registrants’ businesses or result in significant additional costs.

Cleco’s business is subject to extensive federal, state, and local laws and regulations. The LPSC regulates Cleco’s retail operations, and FERC regulates Cleco’s wholesale operations. The construction, planning, and siting of Cleco’s power plants and transmission lines also are subject to the jurisdiction of the LPSC and FERC. Additional regulatory authorities have jurisdiction over some of Cleco’s operations and construction projects including the EPA, the U.S. Bureau of Land Management, the U.S. Fish and Wildlife Services, the DOE, the U.S. Army Corps of Engineers, the U.S. Department of Homeland Security, the Occupational Safety and Health Administration, the U.S. Department of Transportation, the Federal Communications Commission, the LDEQ, the Louisiana Department of Health and Hospitals, the Louisiana Department of Natural Resources, the Louisiana Department of Public Safety, regional water quality boards, and various local regulatory districts.

Cleco must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should Cleco be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on Cleco, Cleco’s business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to Cleco or Cleco’s facilities in a manner that may have a detrimental effect on the Registrants’ business or result in significant additional costs because of Cleco’s need to comply with those requirements.

Cleco Power’s Rates

The LPSC and FERC regulate the rates that Cleco Power can charge its customers.

Cleco Power’s ongoing financial viability depends on its ability to recover its costs from its LPSC-jurisdictional customers in a timely manner through its LPSC-approved rates and its ability to pass to its FERC customers through rates its FERC-authorized revenue requirements. Cleco Power’s financial viability also depends on its ability to recover in rates an adequate return on capital, including long-term debt and equity. If Cleco Power is unable to recover any material amount of its costs in rates in a timely manner or recover an adequate return on capital, the Registrants’ results of operations, financial condition, and cash flows could be materially adversely affected.

Cleco Power’s revenues and earnings are substantially affected by regulatory proceedings known as rate cases. During those cases, the LPSC or FERC determines Cleco Power’s rate base, depreciation rates, operation and maintenance costs, and administrative and general costs that Cleco Power may recover from its retail or wholesale customers through its rates. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of subject expenditures, allowed rates of return, and previously incurred capital expenditures. The LPSC and FERC have the authority to disallow costs found not to have been prudently incurred. These regulatory proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or reducing rates. Rate cases generally have long timelines, which may be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty.

Retail Electric Service

Cleco Power’s retail electric rates and business practices are regulated by the LPSC, and reviews may result in refunds to customers.

Cleco Power’s retail rates for residential, commercial, and industrial customers and other retail sales are regulated by the LPSC, which conducts an annual review of Cleco Power’s earnings and regulatory return on equity. Cleco Power could be required to make a substantial refund of previously recorded revenue as a result of the LPSC review, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Wholesale Electric Service

Cleco Power’s wholesale electric rates and business practices are regulated by FERC, and Cleco could lose the right to sell at market-based rates.

Cleco Power’s wholesale rates are regulated by FERC, which conducts a review of Cleco Power’s generation market power every three years in addition to each time generation capacity changes. In January 2012, Cleco filed a Notice of Change of Status with FERC resulting from the termination of the Evangeline 2010 Tolling Agreement. In connection with such notice, Cleco included an analysis of Cleco's generation

market power. In June 2012, Cleco filed its triennial market power analysis with FERC. FERC has not yet issued any findings in connection with either filing. If FERC determines Cleco Power possesses generation market power in excess of certain thresholds, Cleco Power could lose the right to sell wholesale generation at market-based rates within its control area, which could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Weather Sensitivity

The operating results of Cleco Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.

Weather conditions directly influence the demand for electricity, particularly kWh sales to residential customers. In Cleco Power’s service territory, demand for power typically peaks during the hot summer months. As a result, Cleco Power’s financial results may fluctuate on a seasonal basis. In addition, Cleco Power has sold less power and, consequently, earned less income when weather conditions were milder. Unusually mild weather in the future could have a material adverse impact on the Registrants’ results of operations, financial condition, and cash flows.

Severe weather, including hurricanes and winter storms, can be destructive causing outages and property damage that can potentially result in additional expenses and lower revenue. Extreme drought conditions can impact the availability of cooling water to support the operations of generating plants, which can also result in additional expenses and lower revenue.

The physical risks associated with climate change could impact the Registrants’ results of operations, financial condition, and cash flows.

The physical risks from climate change, such as an increase in sea level, wetland and barrier island erosion, risks of flooding and changes in weather conditions, such as changes in temperature and precipitation patterns, and potential increased impacts of extreme weather conditions or storms, could affect the Registrants' operations. The Registrants’ assets are in and serve communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation's oil and gas infrastructure is located in these areas and is susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes.

These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on Cleco Power's ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on the Registrants' results of operations, financial condition, and cash flows.

Cleco Credit Ratings

A downgrade in Cleco Corporation’s or Cleco Power’s credit ratings could result in an increase in their respective borrowing costs and a reduced pool of potential investors and funding sources.

Neither Cleco Corporation nor Cleco Power can assure that its current debt ratings will remain in effect for any given period of time or that one or more of its debt ratings will not be lowered or withdrawn entirely by a rating agency. Credit ratings are not recommendations to buy, sell, or hold securities and each rating should be evaluated independently of any other rating. If Moody’s and Standard & Poor’s were to downgrade Cleco Corporation’s or Cleco Power’s long-term ratings, particularly below investment grade, the value of their debt securities would likely be adversely affected, and the borrowing cost of Cleco Corporation or Cleco Power, as the case may be, would likely increase. In addition, Cleco Corporation or Cleco Power, as the case may be, would likely be required to pay higher interest rates in future debt financings and be subject to more onerous debt covenants, and its pool of potential investors and funding sources could decrease.

Holding Company

Cleco Corporation is a holding company and its ability to meet its debt obligations and pay dividends on its common stock is dependent on the cash generated by its subsidiaries.

Cleco Corporation is a holding company and conducts its operations primarily through its subsidiaries. Substantially all of Cleco’s consolidated assets are held by its subsidiaries. Accordingly, Cleco Corporation’s ability to meet its debt obligations and to pay dividends on its common stock is largely dependent upon the cash generated by these subsidiaries. Cleco Corporation’s subsidiaries are separate and distinct entities and have no obligation to pay any amounts due on Cleco Corporation’s debt or to make any funds available for such payment. In addition, Cleco Corporation’s subsidiaries’ ability to make dividend payments or other distributions to Cleco Corporation may be restricted by their obligations to holders of their outstanding securities and to other general business creditors. Cleco Corporation’s right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if Cleco Corporation were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by Cleco Corporation. Moreover, Cleco Power, Cleco Corporation’s principal subsidiary, is subject to regulation by the LPSC, which may impose limits on the amount of dividends that Cleco Power may pay Cleco Corporation.

Midstream Generation Facility

Midstream’s generation facility is susceptible to unplanned outages, significant maintenance requirements, interruption of fuel deliveries, and transmission constraints.

The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. If adequate expenditures for equipment maintenance are not made, a facility may incur more frequent

unplanned outages, higher than anticipated operating and maintenance expenditures, increased fuel costs, and potentially the loss of revenue related to competitive opportunities.

Midstream’s generation facility is fueled by natural gas. The deliverability of this fuel source may be constrained due to such factors as higher demand, production shortages, weather-related disturbances, or lack of transportation capacity.

Due to Midstream’s generation facility’s location on the transmission grid, Midstream relies on one main supplier of electric transmission when accessing external power markets. However, at times, physical constraints limit the amount of power this transmission provider can deliver.

Alternative Generation Technology

Changes in technology may negatively impact the value of the Cleco Power and Midstream generation facilities.

A basic premise of Cleco’s business is that generating electricity at central power plants achieves economies of scale and produces electricity at a relatively low price. There are alternative technologies to produce electricity, most notably fuel cells, microturbines, wind turbines, and photovoltaic (solar) cells. Many companies and organizations conduct research and development activities to seek improvements in alternative technologies. It is possible that advances will reduce the cost of alternative methods of electricity production to a level that is equal to or below that of most central station production. Also, as new technologies are developed and become available, the quantity and pattern of electricity purchased by customers could decline, with a corresponding decline in revenues derived by generators. In addition, the current presidential administration and certain members of the U.S. Congress have voiced support for such alternative energy sources. As a result, the value of the Cleco Power and Midstream generation facilities could be significantly reduced.

Insurance

Cleco’s insurance coverage may not be sufficient.

Cleco currently has general liability and property insurance in place to cover certain of its facilities in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Cleco’s facilities may not be sufficient to restore the loss or damage without negative impact on Cleco’s results of operations, financial condition, and cash flows.

Like other utilities that serve coastal regions, Cleco does not have insurance covering its transmission and distribution system, other than substations, because it believes such insurance to be cost prohibitive. In the future, Cleco may not be able to recover the costs incurred in restoring transmission and distribution properties following hurricanes or other natural disasters through issuance of storm recovery bonds or a change in Cleco Power’s regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, Cleco may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition, and cash flows.

Litigation

The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on the Registrants’ financial condition.

The Registrants are party to various litigation matters arising out of their business operations. The ultimate outcome of these matters cannot presently be determined, nor, in many cases, can the liability that could potentially result from a negative outcome in each case presently be reasonably estimated. The liability that the Registrants may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters and, as a result, these matters may have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Taxes

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ financial condition.

The Registrants make judgments regarding the potential tax effects of various financial transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. Changes in federal, state, or local tax laws, adverse tax audit results, or adverse tax rulings on positions taken by the Registrants could negatively affect their results of operations, financial condition, and cash flows.

Health Care Reform

Cleco may experience increased costs arising from health care reform.

In March 2010, Congress passed, and the President signed, the PPACA. This law may have a significant impact on health care providers, insurers, and others associated with the health care industry. Cleco is continuing to evaluate the impact of this comprehensive law on its business and has made the required changes to its health plan for 2013. Federal and state governments may propose other health care initiatives and revisions to the health care and health insurance systems. It is uncertain what legislative programs, if any, will be adopted in the future, or what action Congress or state legislatures may take regarding other health care reform proposals or legislation. Although the law has passed, many regulations have yet to be written; therefore, management cannot quantify the impact of these regulations, including those relating to the establishment of exchanges and the applicability of excise taxes on excess health benefits. The new regulations may have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

Technology and Terrorism Threats

Man-made problems such as computer viruses or terrorism may negatively impact the Registrants’ operating results.

Man-made problems such as computer viruses or terrorism may disrupt the Registrants’ operations and harm the

Registrants’ operating results. The Registrants operate in a highly-regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite the implementation of security measures, all of the Registrants’ technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism, and other causes. If the Registrants’ technology systems were to fail and the Registrants were unable to recover in a timely way, the Registrants would be unable to fulfill critical business functions, which could have a material adverse effect on the Registrants’ business, operating results, financial condition, and cash flows. In addition, the Cleco Power and Midstream generation plants, fuel storage facilities, transmission, and distribution facilities may be targets of terrorist activities that could disrupt the Registrants’ ability to produce or distribute some portion of their energy products.

Any such disruption could result in a material decrease in revenues and significant additional costs to repair and insure the Registrants’ assets, which could have a material adverse effect on the Registrants’ business, operating results, financial condition, and cash flows. The continued threat of terrorism and heightened security and military action in response to this threat, or any future acts of terrorism, may cause further disruptions to the economies of the U.S. and other countries and create further uncertainties or otherwise materially harm the Registrants’ business, operating results, financial condition, and cash flows.

Cleco Power LLC’s Unsecured and Unsubordinated Obligations

Cleco Power LLC’s unsecured and unsubordinated obligations, including, without limitation, its senior notes, will be effectively subordinated to any secured debt of Cleco Power LLC and the debt and any preferred equity of any of Cleco Power’s subsidiaries.

Cleco Power LLC’s senior notes and its obligations under various loan agreements and refunding agreements with the Rapides Finance Authority, the Louisiana Public Facilities Authority, and other issuers of tax-exempt bonds for the benefit of Cleco Power LLC are unsecured and rank equally with all of Cleco Power LLC’s existing and future unsecured and unsubordinated indebtedness. As of December 31, 2012, Cleco Power LLC had an aggregate of $1.19 billion of unsecured and unsubordinated indebtedness. The unsecured and unsubordinated indebtedness of Cleco Power LLC will be

effectively subordinated to, and thus have a junior position to, any secured debt that Cleco Power LLC may have outstanding from time to time (including any mortgage bonds) with respect to the assets securing such debt. As of December 31, 2012, Cleco Power LLC had no secured indebtedness outstanding. Cleco Power LLC may issue mortgage bonds in the future under its Indenture of Mortgage and holders of mortgage bonds would have a prior claim on certain Cleco Power LLC

material assets upon dissolution, winding up, liquidation, or reorganization. Additionally, Cleco Power LLC’s ability (and the ability of Cleco Power LLC’s creditors, including holders of its senior notes) to participate in the assets of Cleco Power LLC’s subsidiary, Cleco Katrina/Rita, is subject to the prior claims of the subsidiary’s creditors. As of December 31, 2012, Cleco Katrina/Rita had $130.1 million of indebtedness outstanding, net of debt discount.



CLECO POWER

All of Cleco Power’s electric generating stations and all other electric operating properties are located in the state of Louisiana. Cleco Power considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Cleco Power’s generating facilities, see Item 1, “Business — Operations — Cleco Power — Power Generation.”

Electric Generating Stations

As of December 31, 2012, Cleco Power either owned or had an ownership interest in three steam electric generating stations, two gas turbines, and one combined cycle unit with a combined nameplate capacity of 2,565 MW, and a combined electric net generating capacity of 2,436 MW. The net generating capacity is the result of capacity tests and operational tests performed between January and August 2012, as required by SPP criteria. This amount reflects the maximum production capacity these units can sustain over a specified period of time. For more information on Cleco Power’s generating facilities, see Item 1, “Business — Operations — Cleco Power — Power Generation.”

Electric Substations

As of December 31, 2012, Cleco Power owned 74 active transmission substations and 222 active distribution substations.

Electric Lines

As of December 31, 2012, Cleco Power’s transmission system consisted of approximately 67 circuit miles of 500-kiloVolt (kV) lines; 534 circuit miles of 230-kV lines; 671 circuit miles of 138 kV lines; and 28 circuit miles of 69-kV lines. Cleco Power’s distribution system consisted of approximately 3,609 circuit miles of 34.5-kV lines and 8,221 circuit miles of other lines.

General Properties

Cleco Power owns various properties throughout Louisiana, which include a headquarters office building, regional offices, service centers, telecommunications equipment, and other general-purpose facilities.

Title

Cleco Power’s electric generating plants and certain other principal properties are owned in fee simple. Electric

transmission and distribution lines are located either on private rights-of-way or along streets or highways by public consent.

Substantially all of Cleco Power’s property, plant, and equipment are subject to a lien of Cleco Power’s Indenture of Mortgage, which does not impair the use of such properties in the operation of its business. As of December 31, 2012, no mortgage bonds were outstanding under the Indenture of Mortgage. Some of the unsecured and unsubordinated indebtedness of Cleco Power will be effectively subordinated to, and thus have a junior position to, any mortgage bonds that Cleco Power may have outstanding from time to time with respect to the assets subject to the lien of the Indenture of Mortgage. Cleco Power may issue mortgage bonds in the future under its Indenture of Mortgage, and holders of mortgage bonds would have a prior claim on certain Cleco Power material assets upon dissolution, winding up, liquidation, or reorganization.



MIDSTREAM

Midstream considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Midstream’s generating facilities, see Item 1, “Business — Operations — Midstream.”

Electric Generation

As of December 31, 2012, Midstream, through one wholly owned subsidiary, owned one electric generating station, with a nameplate capacity of 775 MW and an electric net generating capacity of 753 MW. For information on Midstream’s generating facilities, see Item 1, “Business — Operations — Midstream.”

Title

Midstream’s assets are owned in fee simple. In January 2012, Midstream began marketing Coughlin’s capacity. Evangeline was one of the successful bidders in Cleco Power’s RFP for short-term 2012 resources beginning January 1, 2012. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP, subject to further due diligence, the completion of definitive agreements, and regulatory approvals from the LPSC and FERC. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. The transaction is expected to close as early as the fourth quarter of 2013, after completion of regulatory approvals. For more information, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 17 — Evangeline Transactions” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Generation RFP.”



NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Bruce A. Williamson Cleco Corporation Cleco Power	President and Chief Executive Officer since July 2011; Chairman, President and Chief Executive Officer, Dynegy, Inc. from 2004 to 2011. Chief Executive Officer since July 2011. (Age 53; one year of service)
Darren J. Olagues Cleco Corporation Cleco Power Midstream	Senior Vice President, Chief Financial Officer since July 2012; Senior Vice President, Chief Financial Officer and Treasurer from November 2011 to July 2012; Senior Vice President and Chief Financial Officer from May 2009 to November 2011. Senior Vice President from July 2007 to May 2009. (Age 42; 5 years of service)
Wade A. Hoefling Cleco Corporation Cleco Power	Senior Vice President, General Counsel & Director - Regulatory Compliance since April 2008; Senior Vice President, General Counsel, Director - Regulatory Compliance and Assistant Corporate Secretary from January 2007 to April 2008. (Age 57; 6 years of service)
Judy P. Miller Cleco Corporation Cleco Power	Senior Vice President - Corporate Services and Internal Audit since November 2011; Corporate Secretary from January 2004 to November 2011. (Age 55; 28 years of service)
Keith D. Crump Cleco Power	Senior Vice President - Commercial Operations since March 2012; Group Vice President from March 2010 to March 2012; Vice President - Regulatory, Retail Operations and Resource Planning from March 2007 to March 2010. (Age 51; 23 years of service)
William G. Fontenot Cleco Power	Senior Vice President - Utility Operations since March 2012; Group Vice President from March 2010 to March 2012; Vice President - Regulated Generation Development from July 2005 to March 2010. (Age 50; 26 years of service)
Thomas R. Miller Cleco Corporation Cleco Power	Vice President - Treasurer since July 2012; Senior Vice President & Treasurer, Solar Trust of America LLC from October 2010 to July 2012; Vice President, Treasury, Exelon Corporation from June 2002 to August 2010. (Age 52; less than one year of service)
Anthony L. Bunting Cleco Power	Vice President - Transmission & Distribution Operations since October 2012; Vice President - Customer Services and Energy Delivery from October 2004 to October 2012. (Age 53; 21 years of service)
Robert R. LaBorde, Jr. Cleco Corporation Cleco Power	Vice President - Strategic Planning, Development and Environmental Policy from November 2011 to November 2012; General Manager - Environmental Services from August 2006 to November 2011. Vice President - Generation Operations since November 2012. (Age 45; 21 years of service)
Terry L. Taylor Cleco Corporation Cleco Power	Controller and Chief Accounting Officer since November 2011; Assistant Controller from August 2006 to November 2011. (Age 58; 12 years of service)
Julia E. Callis Cleco Corporation Cleco Power	Associate General Counsel and Corporate Secretary since November 2011; Senior Attorney from August 2007 to November 2011. (Age 44; 5 years of service)



CLECO CORPORATION

Cleco Corporation’s common stock is listed for trading on the New York Stock Exchange (NYSE). For information on the high and low sales prices for Cleco Corporation’s common stock as reported on the NYSE Composite Tape and dividends paid per share during each calendar quarter of 2012 and 2011, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 21 — Miscellaneous Financial Information (Unaudited).” During the years ended December 31, 2012 and 2011, Cleco Corporation repurchased 200,000 shares and 400,000 shares, respectively, of common stock. For information on Cleco Corporation’s common stock repurchase program, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 7 — Common and Preferred Stock — Common Stock Repurchase Program.”

Dividends, as determined by the Board of Directors of Cleco Corporation, may be declared and paid on the common stock from time to time out of funds legally available, subject to prior rights to dividends on any outstanding series of preferred stock. The provisions of Cleco Corporation’s amended and restated articles of incorporation applicable to preferred stock and certain provisions contained in the debt instruments of Cleco under certain circumstances restrict the amount of retained earnings available for the payment of dividends by Cleco Corporation. The most restrictive covenant, which is in Cleco Corporation’s credit facility, requires Cleco Corporation’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2012, approximately $758.3 million of retained earnings was unrestricted.

In January 2011, the Board of Directors of Cleco Corporation declared dividends of $0.25 per share of common stock. In April 2011 and July 2011, dividends of $0.28 per share of common stock were declared. In October 2011, January 2012, and April 2012, the Board of Directors declared dividends of $0.3125 per share of common stock.

In July and October 2012, the quarterly dividend declared by the Board of Directors increased to $0.3375 per share of common stock. On January 24, 2013, Cleco Corporation’s Board of Directors declared a quarterly dividend of $0.3375 per share payable on February 15, 2013, to common shareholders of record at the close of business on February 5, 2013. The declaration of dividend payments is at the Board of Directors’ sole discretion and future dividends are subject to numerous factors that ordinarily affect the dividend policy,

including the result of Cleco’s operations and its financial position, as well as general economic and business conditions.

As of February 1, 2013, there were 5,824 holders of record of Cleco Corporation’s common stock, and the closing price of Cleco Corporation’s common stock as reported on the NYSE Composite Tape was $42.65 per share.

In January 2011, Cleco Corporation’s Board of Directors authorized and approved the redemption of all outstanding shares of the 4.5% cumulative preferred stock not subject to mandatory redemption, provided that no shares of such preferred stock were redeemed prior to the repayment in full and termination of the $150.0 million bank term loan that matured on August 19, 2011. During 2011, the $150.0 million bank term loan was repaid and 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.



CLECO POWER

There is no market for Cleco Power’s membership interests. All of Cleco Power’s outstanding membership interests are owned by Cleco Corporation. Distributions on Cleco Power’s membership interests are paid when and if declared by Cleco Power’s Board of Managers. Any future distributions also may be restricted by any credit or loan agreements that Cleco Power may enter into from time to time.

Some provisions in Cleco Power’s debt instruments restrict the amount of equity available for distribution to Cleco Corporation by Cleco Power under specified circumstances. The most restrictive covenant requires Cleco Power’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2012, approximately $623.7 million of member’s equity was unrestricted.

During 2012, 2011, and 2010, Cleco Power made $58.0 million, $130.0 million, and $150.0 million of distribution payments to Cleco Corporation, respectively.

During 2010, Cleco Power received $225.7 million in non-cash equity contributions from Cleco Corporation relating to Acadia Unit 1. For more information regarding this transaction, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions — Acadia Unit 1.” Cleco Power received no equity contributions from Cleco Corporation in 2012 or 2011.



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 9 generating units with a total nameplate capacity of 2,565 MW and serves approximately 283,000 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 owns and 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. A key initiative Cleco Power completed during 2012 was the Acadiana Load Pocket transmission project. Key initiatives on which Cleco Power is currently working include completion of the AMI project, completion of the transfer of ownership and control of Coughlin from Evangeline, and integration into MISO by January 2014. These initiatives are discussed below.

Acadiana Load Pocket Transmission 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. At December 31, 2012, Cleco Power had spent $123.7 million, including AFUDC, on the project. A return on and recovery of the costs associated with the completed portions of the Acadiana Load Pocket transmission project are included in base rates. The project was completed in December 2012. For information on the impact the Acadiana Load Pocket transmission project is expected to have on base revenue, see “— Cleco Power’s Results of Operations — Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — Base.” For more information, see “— Financial Condition — Regulatory and Other Matters — Acadiana Load Pocket Transmission Project.”

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 advanced metering 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. Advanced metering technology includes the installation of electric meters that enable two-way communication capabilities between a home or business and a utility company. At December 31, 2012, Cleco Power had incurred $55.5 million in project costs, of which $20.0 million has been submitted to and reimbursed by the DOE. The project is expected to be completed in the third quarter of 2013. For

more information on the AMI Project, see “— Financial Condition — Regulatory and Other Matters — AMI Project.”

The risks associated with cybersecurity issues increase as Cleco moves toward more dependence on digital technology to conduct its daily operations, such as, but not limited to, AMI. Cleco has security measures in place to protect its technology systems from hacking, viruses, and other causes. In addition, Cleco is under the jurisdiction of the NERC Critical Infrastructure Protection cybersecurity standards and has implemented mechanisms, policies, and procedures to meet those standards. If Cleco’s security measures were to fail, revenues could decrease and costs to repair the assets could have a material adverse effect on the Registrants’ business, operating results, financial condition, and cash flows. For more information on cybersecurity, see Part 1, Item 1A, “Risk Factors — Technology and Terrorism Threats.”

Power Supply Options/Coughlin Transfer from Midstream

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. In August 2011, Cleco Power issued an RFP for resources to enhance reliability for January through April 2012 and selected and negotiated two agreements from the RFP, a power purchase agreement with NRG Power Marketing LLC and a tolling agreement with Evangeline. Both agreements began on January 1, 2012 and ended on April 30, 2012. In October 2011, a second RFP, seeking up to approximately 750 MW of capacity and energy, for a three- or five-year period was issued for supply starting May 1, 2012. Cleco Power selected Evangeline’s proposal for a 730-MW product beginning May 1, 2012, and ending April 30, 2015. The definitive agreement between Evangeline and Cleco Power was executed in January 2012 and approved by the LPSC in March 2012 and FERC in April 2012. In May 2012, Cleco Power issued a draft RFP seeking long-term resources beyond April 2015. The final RFP was issued in July 2012 and proposals were received from potential suppliers in August 2012. On October 30, 2012, Cleco Power announced Evangeline as the winning bidder in Cleco Power’s 2012 Long-Term RFP. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. For more information on the RFP, see “— Financial Condition — Regulatory and Other Matters — Generation RFP.”

MISO

Cleco Power’s transmission system is heavily interconnected with Entergy’s system; therefore, Cleco Power plans to follow Entergy and join MISO by January 2014. On December 6, 2012, Cleco Power filed an application with the LPSC indicating Cleco’s intent to join MISO, asking the commission to find that transferring control of certain transmission assets to MISO is in the public interest, to create an accounting order deferring costs related to Cleco Power’s transition into the MISO market, and to expedite treatment. For more information on MISO, see “— Financial Condition — Regulatory and Other Matters — Market Restructuring” and Part 1, Item 1A, “Risk Factors — MISO.”

Cleco Midstream

Evangeline

In March 2010, Evangeline restructured its tolling agreement with JPMVEC and entered into the Evangeline 2010 Tolling Agreement whereby the parties 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 Evangeline 2010 Tolling Agreement and as a result, Coughlin’s capacity and energy became available to Midstream beginning January 1, 2012. Evangeline was one of the successful bidders in Cleco Power’s RFP for short-term 2012 resources beginning January 1, 2012, and began providing 250 MW of capacity and energy to Cleco Power under a tolling agreement through April 30, 2012. In addition, in December 2011, Evangeline also was notified that Cleco Power selected its proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power RFP for contractual resources beginning in 2012. The proposal was for a 730-MW product beginning May 1, 2012, and ending April 30, 2015. The definitive agreement between Evangeline and Cleco Power was executed in January 2012 and was approved by the LPSC in March 2012 and FERC in April 2012. Midstream had been marketing Coughlin’s capacity for periods beginning after April 30, 2015, and had been evaluating various options to optimize Coughlin’s value. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. For more information, see “— Financial Condition — Regulatory and Other 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 more information on the Acadia Unit 2 transaction, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions — Acadia Unit 2.”



RESULTS OF OPERATIONS

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ materially from those estimates.



Cleco Consolidated Results of Operations — Year ended December 31, 2012, Compared to Year ended December 31, 2011
			FOR THE YEAR ENDED DEC. 31,
					FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2012		2011		VARIANCE			CHANGE
Operating revenue, net	$	993,697	$	1,117,313	$	(123,616	)	(11.1	)%
Operating expenses	712,046		819,066		107,020			13.1	%
Operating income	$	281,651	$	298,247	$	(16,596	)	(5.6	)%
Allowance for other funds used during construction	$	6,711	$	4,947	$	1,764		35.7	%
Equity income from investees, before tax	$	—	$	62,050	$	(62,050	)	(100.0	)%
Other income	$	29,117	$	8,914	$	20,203		226.6	%
Interest charges	$	84,156	$	70,658	$	(13,498	)	(19.1	)%
Federal and state income taxes	$	65,327	$	102,897	$	37,570		36.5	%
Net income applicable to common stock	$	163,648	$	195,710	$	(32,062	)	(16.4	)%

Consolidated net income applicable to common stock decreased $32.1 million, or 16.4%, in 2012 compared to 2011 primarily due to the absence of the gain from the disposition of Acadia Unit 2 during 2011, partially offset by the contractual expiration of underlying indemnifications resulting from the disposition of Acadia Units 1 and 2. Also contributing to the decrease were lower corporate earnings. Partially offsetting these decreases were higher Cleco Power earnings.

Operating revenue, net decreased $123.6 million, or 11.1%, in 2012 compared to 2011 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 power purchased for utility customers and lower volumes of fuel used for electric generation.

Operating expenses decreased $107.0 million, or 13.1%, in 2012 compared to 2011 primarily due to lower per unit costs and volumes of fuel used for electric generation.

Allowance for other funds used during construction increased $1.8 million, or 35.7%, in 2012 compared to 2011, primarily due to higher AFUDC accruals related to the AMI Project and miscellaneous transmission projects, partially offset by lower amounts from the Acadiana Load Pocket transmission project and the absence of accruals related to the completion of Teche Unit 4.

Equity income from investees decreased $62.1 million, or 100.0%, in 2012 compared to 2011 primarily due to the absence of the gain from the disposition of Acadia Unit 2 during 2011. For more information on the Acadia Unit 2 transaction, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions.”

Other income increased $20.2 million, or 226.6%, in 2012 compared to 2011 primarily due to the contractual expiration of underlying indemnifications resulting from the disposition of Acadia Units 1 and 2 and higher royalty payments.

Interest charges increased $13.5 million, or 19.1%, in 2012 compared to 2011 largely due to the absence of a favorable tax settlement recorded in 2011 relating to Evangeline. Partially offsetting this increase was lower interest charges at Cleco Power and lower corporate interest charges related to the repayment of a bank term loan in April 2011.

Federal and state income taxes decreased $37.6 million, or 36.5%, in 2012 compared to 2011. Tax expense decreased primarily due to the change in pre-tax income, excluding AFUDC equity, the settlement of legacy tax issues, and an increase in tax credits, partially offset by increases for the absence of a valuation allowance reversal recorded in 2011 and tax returns filed. The effective income tax rate is 28.5% which is different than the federal statutory rate primarily due to the effect of state income taxes, tax credits, and the effects of settlements of legacy tax issues.

On July 3, 2012, Cleco and Cleco Power filed a PLR request with the IRS in order to determine the appropriateness and timing of the special allowance for depreciation for Madison Unit 3. Subsequently, on December 28, 2012, Cleco received a favorable PLR from the IRS, consistent with the request allowing for the additional first year depreciation deduction in the amount of $411.0 million as reflected on Cleco Corporation’s 2011 federal income tax return. Cleco and Cleco Power consider it more likely than not that these income tax losses generated on the 2011 income tax return will be utilized to reduce future payments of income taxes and both Cleco and Cleco Power expect to utilize the entire net operating loss carryforward within the statuatory deadlines.

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

CLECO POWER

Significant Factors Affecting Cleco Power

Revenue is primarily affected by the following factors:

As an electric utility, Cleco Power is affected, to varying degrees, by a number of factors influencing the electric utility industry in general. These factors include, among others, an increasingly competitive business environment, the cost of compliance with environmental and reliability regulations, conditions in the credit markets and global economy, and changes in the federal and state regulation of generation, transmission, and the sale of electricity. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see Part I, Item 1 “Business — Regulatory Matters, Industry Developments, and Franchises — Franchises” and “— Financial Condition — Regulatory and Other Matters — Market Restructuring.” For a discussion of risk factors affecting Cleco Power’s business, see Item 1A, “Risk Factors — Transmission Constraints,” “— LPSC Audits,” “— Hedging and Risk Management Activities,” “— Commodity Prices,” “— Global Economic Environment and Uncertainty; Access to Capital,” “— Future Electricity Sales,” “— Cleco Power Generation Facilities,” “— MISO,” “— Reliability and Infrastructure Protection Standards Compliance,” “— Environmental Compliance,” “— Regulatory Compliance,” “— Cleco Power’s Rates,” “— Retail Electric Service,” “— Wholesale Electric Service,” “— Weather Sensitivity,” “— Cleco Credit Ratings,” “— Alternative Generation Technology,” “— Insurance,” “— Litigation,” “— Taxes,” “— Health Care Reform,” “— Technology and Terrorism Threats,” and “— Cleco Power Unsecured and Unsubordinated Obligations.”

Cleco Power’s residential customers’ demand for electricity is largely 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.

Cleco Power has experienced over the last five years, and anticipates over the next five years, moderate growth in retail non-industrial sales volume. For the retail industrial class, Cleco Power expects new industrial load to be added in 2013, 2014, and 2015, principally driven by expected development in northwestern Louisiana associated with the development of Haynesville shale gas discovered in that area. In addition, Cleco Power also expects to begin providing service to expansions of current retail customers’ operations, as well as service to a new retail customer. These expansions of service to current customers and service to a new customer are expected to contribute additional base revenue of $2.0 million in 2013, an additional $1.0 million in 2014, and an additional $2.8 million in 2015. Cleco Power’s expectations and projections regarding retail sales are dependent upon factors such as weather conditions, natural gas prices, customer conservation efforts, retail marketing and business development programs, and the economy of Cleco Power’s service area. For more information, see “Cautionary Note Regarding Forward-Looking Statements.”

Other issues facing the electric utility industry that could affect sales include:


•	imposition of federal and/or state renewable portfolio standards,


•	imposition of energy efficiency mandates,


•	legislative and regulatory changes,


•	increases in environmental regulations and compliance costs,


•	cost of power impacted by the price movement of natural gas, the addition of solid-fuel plants which could increase or decrease costs depending on environmental regulations and commodity costs, and the addition of new generation capacity,


•	increase in capital and operations and maintenance costs due to higher construction and labor costs,


•	changes in electric rates compared to customers’ ability to pay,


•	access to transmission systems,


•	need for additional transmission capacity for reliability purposes,


•	changes in the credit markets and global economy,


•	implementation of automated metering initiatives or advanced metering technologies, and


•	integration into MISO.

For more information on energy legislation in regulatory matters that could affect Cleco, see “— Financial Condition — Regulatory and Other Matters — Market Restructuring — Wholesale Electric Markets.”

Cleco Power’s revenues and earnings also are substantially affected by regulatory proceedings known as rate cases. During those cases, the LPSC and FERC determine Cleco Power’s rate base, depreciation rates, operation and

maintenance costs, and administrative and general costs that Cleco Power may recover from its customers through the rates charged for electric service. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of subject expenditures, allowed rates of return, and previously incurred capital expenditures. The LPSC has the authority to disallow costs found not to have been prudently incurred. These regulatory proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or reducing rates. Rate cases generally have long timelines which may be limited by statute. Decisions are typically subject to appeal, leading to additional uncertainty.

Other expenses are primarily affected by the following factors:

The majority of Cleco Power’s non-fuel cost recovery expenses consist of other operations, maintenance, depreciation, and taxes other than income taxes. Other operations expenses are affected by, among other things, the cost of employee benefits, insurance expenses, and the costs associated with energy delivery and customer service. Maintenance expenses associated with Cleco Power’s plants generally depend upon their physical characteristics, as well as the effectiveness of their preventive maintenance programs. Transmission and distribution maintenance expenses are generally affected by the level of repair and rehabilitation of lines to maintain reliability. Depreciation expense primarily is affected by the cost of the facilities in service, the time the facilities were placed in service, and the estimated useful life of the facilities. Taxes other than income taxes generally include payroll taxes, franchise taxes, and ad valorem taxes. Cleco Power anticipates certain non-fuel cost recovery expenses to be higher in 2013 compared to 2012. These expenses include higher plant maintenance expenses, higher taxes other than income taxes, and higher depreciation expense. In addition, Cleco Power expects its postretirement benefit expenses to be affected by changes in discount rates, actual returns on plan assets, level of benefits provided, and actuarial assumptions used in the calculations.



Cleco Power’s Results of Operations — Year ended December 31, 2012, Compared to Year ended December 31, 2011
	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2012			2011			VARIANCE			CHANGE
Operating revenue
Base	$	606,577		$	605,024		$	1,553		0.3	%
Fuel cost recovery	337,592			446,932			(109,340		)	(24.5	)%
Electric customer credits	(630		)	(6,811		)	6,181			90.8	%
Other operations	48,156			50,948			(2,792		)	(5.5	)%
Affiliate revenue	1,372			1,389			(17		)	(1.2	)%
Operating revenue, net	$	993,067		$	1,097,482		$	(104,415	)	(9.5	)%
Operating expenses
Fuel used for electric generation – recoverable	277,605			379,771			102,166			26.9	%
Power purchased for utility customers – recoverable	59,989			67,167			7,178			10.7	%
FAC non-recoverable fuel and power purchased	21,338			6,778			(14,560		)	(214.8	)%
Other operations	115,072			116,988			1,916			1.6	%
Maintenance	72,386			74,603			2,217			3.0	%
Depreciation	125,486			115,634			(9,852		)	(8.5	)%
Taxes other than income taxes	33,999			32,157			(1,842		)	(5.7	)%
Gain on sale of assets	(2		)	(9		)	(7		)	77.8	%
Total operating expenses	$	705,873		$	793,089		$	87,216		11.0	%
Operating income	$	287,194		$	304,393		$	(17,199	)	(5.7	)%
Allowance for other funds used during construction	$	6,711		$	4,947		$	1,764		35.7	%
Other income	$	5,847		$	3,163		$	2,684		84.9	%
Interest charges	$	80,502		$	97,090		$	16,588		17.1	%
Federal and state income taxes	$	68,133		$	69,409		$	1,276		1.8	%
Net income	$	146,848		$	142,835		$	4,013		2.8	%

Cleco Power’s net income for 2012 increased $4.0 million, or 2.8%, compared to 2011. Contributing factors include:


•	lower interest charges,


•	lower electric customer credits,


•	lower other operations and maintenance expenses,


•	higher other income,


•	higher allowance for other funds used during construction,


•	higher base revenue, and


•	lower income taxes.

These were partially offset by:


•	higher FAC non-recoverable fuel and power purchased,


•	higher depreciation expense,


•	lower other operations revenue, and


•	higher taxes other than income taxes.



	FOR THE YEAR ENDED DEC. 31,
					FAVORABLE/
(MILLION kWh)	2012		2011		(UNFAVORABLE)
Electric sales
Residential	3,624		3,877		(6.5	)%
Commercial	2,655		2,650		0.2	%
Industrial	2,311		2,366		(2.3	)%
Other retail	133		134		(0.7	)%
Total retail	8,723		9,027		(3.4	)%
Sales for resale	1,934		1,888		2.4	%
Unbilled	(43	)	(139	)	69.1	%
Total retail and wholesale customer sales	10,614		10,776		(1.5	)%



	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/
(THOUSANDS)	2012			2011			(UNFAVORABLE)
Electric sales
Residential	$	281,378		$	294,076		(4.3	)%
Commercial	181,093			179,786			0.7	%
Industrial	85,675			85,965			(0.3	)%
Other retail	9,908			9,815			0.9	%
Surcharge	9,133			10,695			(14.6	)%
Other	(6,252		)	(6,426		)	2.7	%
Total retail	$	560,935		$	573,911		(2.3	)%
Sales for resale	47,767			45,633			4.7	%
Unbilled	(2,125		)	(14,520		)	85.4	%
Total retail and wholesale customer sales	$	606,577		$	605,024		0.3	%

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



			FOR THE YEAR ENDED DEC. 31,
				2012 CHANGE
	2012	2011	NORMAL	PRIOR YEAR		NORMAL
Cooling degree-days	3,189	3,255	2,779	(2.0	)%	14.8	%
Heating degree-days	1,018	1,510	1,545	(32.6	)%	(34.1	)%

Base

Base revenue increased $1.6 million, or 0.3%, during 2012 compared to 2011 primarily due to an annual rate adjustment associated with Cleco’s FRP which resulted in an $11.2 million increase to base revenue. Partially offsetting this increase was $9.6 million primarily due to milder weather.

Cleco Power expects to begin providing service to expansions of current retail customers’ operations, as well as service to a new retail customer. These expansions of service to current customers and service to a new customer are expected to contribute additional base revenue of $2.0 million in 2013, an additional $1.0 million in 2014, and an additional $2.8 million in 2015. In 2013, Cleco Power also anticipates additional base revenue of $9.0 million annually associated with the adoption of a FERC formula rate methodology for transmission delivery and ancillary services, $2.0 million associated with the Acadiana Load Pocket transmission project, and $1.9 million associated with the recovery of expenditures for compliance of anticipated environmental laws. In January 2012, Cleco Power signed a new 10-year

wholesale power contract with service to begin in April 2014. The contract was approved by the LPSC in December 2012. Cleco Power’s load is expected to grow by more than 20%. For information on other effects of future energy sales on Cleco Power’s financial condition, results of operations, and cash flows, see “— Significant Factors Affecting Cleco Power” and Part I, Item 1A, “Risk Factors — Future Electricity Sales.”

Fuel Cost Recovery

Fuel cost recovery revenue billed to customers during 2012 compared to 2011 decreased $109.3 million, or 24.5%, primarily due to decreases in the per-unit costs of fuel used for electric generation and power purchased for utility customers, and lower volumes of fuel used for electric generation. Partially offsetting the decrease were higher volumes of power purchased for utility customers.

Electric Customer Credits

Electric customer credits decreased $6.2 million, or 90.8%, in 2012 compared to 2011 primarily due to a change in rate refunds due to customers, partially offset by new transmission rates subject to refund. For more information on the accrual of electric customer credits, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 11 — Electric Customer Credits.”

Other Operations

Other operations revenue decreased $2.8 million, or 5.5%, in 2012 compared to 2011, primarily due to $5.9 million related to lower mineral lease payments and $4.9 million related to the absence of a gain on the sale of Cleco Power’s fuel oil supply. Partially offsetting these amounts were $7.0 million related to an increase in wholesale power sales and $1.0 million related to other miscellaneous revenue.

Operating Expenses

Operating expenses decreased $87.2 million, or 11.0%, in 2012 compared to 2011. Fuel used for electric generation (recoverable) decreased $102.2 million, or 26.9%, primarily due to lower per unit costs and volumes of fuel used for electric generation as compared to 2011. Power purchased for utility customers (recoverable) decreased $7.2 million, or 10.7%, largely due to lower per-unit costs of purchased power. Partially offsetting this decrease was higher volumes 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. FAC non-recoverable fuel and power purchased increased $14.6 million, or 214.8%, primarily due to higher non-recoverable wholesale power purchases and other capacity payments. Other operations expense decreased $1.9 million, or 1.6%, primarily due to lower customer service, administrative, and distribution expenses, partially offset by higher generating station and transmission expenses. Maintenance expenses decreased $2.2 million, or 3.0%, during 2012 compared to 2011 primarily due to lower generating station and distribution maintenance work performed during 2012. Depreciation expense increased $9.9 million, or 8.5%, largely due to portions of the Acadiana Load Pocket transmission project being placed in service, other normal recurring additions to fixed assets, and the

reclassification of the Acadia acquisition adjustment amortization. Taxes other than income taxes increased $1.8 million, or 5.7%, primarily due to higher property taxes.

Allowance for Other Funds Used During Construction

Allowance for other funds used during construction increased $1.8 million, or 35.7%, during 2012 compared to 2011 primarily due to higher AFUDC accruals related to the AMI Project and miscellaneous transmission projects, partially offset by lower amounts from the Acadiana Load Pocket transmission project and the absence of accruals related to the completion of Teche Unit 4.

Other Income

Other income increased $2.7 million, or 84.9%, during 2012 compared to 2011 primarily due to higher royalty payments.

Interest Charges

Interest charges decreased $16.6 million, or 17.1%, during 2012 compared to 2011 primarily due to $12.1 million related to uncertain tax positions, $7.8 million related to reacquired debt in October and December 2011, $2.5 million related to the retirement of pollution control bonds in January and May 2012, and $0.5 million of lower other net miscellaneous interest charges. Partially offsetting these decreases was $6.3 million related to the issuance of private placement notes in December 2011 and May 2012.

Income Taxes

Federal and state income taxes decreased $1.3 million, or 1.8%, during 2012 compared to 2011. Tax expense decreased primarily due to the settlement of legacy tax issues, tax returns as filed, and an increase in tax credits, partially offset by the absence of a valuation allowance reversal recorded in 2011 and a decrease in state income tax benefits. The effective income tax rate is 31.7% which is different than the federal statutory rate primarily due to the effects of state income taxes, tax credits, and the settlement of legacy tax issues.

On July 3, 2012, Cleco and Cleco Power filed a PLR request with the IRS in order to determine the appropriateness and timing of the special allowance for depreciation for Madison Unit 3 Generating Station. Subsequently, on December 28, 2012, Cleco received a favorable PLR from the IRS, consistent with the request allowing for the additional first year depreciation deduction in the amount of $411.0 million as reflected on Cleco Corporation’s 2011 federal income tax return. Cleco and Cleco Power consider it more likely than not that these income tax losses generated on the 2011 income tax return will be utilized to reduce future payments of income taxes and both Cleco and Cleco Power expect to utilize the entire net operating loss carryforward within the statutory deadlines.

MIDSTREAM

Significant Factors Affecting Midstream

Earnings primarily are affected by the following factors:

Midstream’s 2012 earnings were derived primarily from the power purchase agreement with Cleco Power for Unit 6 for the period of January 2012 through April 2012 and the new power purchase agreement with Cleco Power for Units 6 and 7 that began in May 2012. On April 29, 2011, Acadia completed its

disposition of Acadia Unit 2 to Entergy Louisiana. In 2011, Acadia’s revenues were derived primarily from a short-term capacity agreement with Entergy Louisiana. The expiration of the Evangeline 2010 Tolling Agreement was 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 became available to Midstream beginning January 1, 2012. Evangeline was one of the successful bidders in Cleco Power’s RFP for short-term 2012 resources beginning January 1, 2012, and began providing 250 MW of capacity and energy to Cleco Power under a tolling agreement through April 30, 2012. In addition, in December 2011, Evangeline was also notified that Cleco Power selected its proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power RFP for contractual resources beginning in 2012. The proposal was for a 730-MW product beginning May 1, 2012, and ending April 30, 2015. The definitive agreement between Evangeline and Cleco Power was executed in January 2012 and was approved by the LPSC in March 2012 and FERC in April 2012. Midstream had been marketing Coughlin’s capacity for periods beginning after April 30, 2015 and had been evaluating various options to optimize Coughlin’s value. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. For more information, see “— Financial Condition — Regulatory and Other Matters — Generation RFP.”

For more information on the factors affecting Midstream, see Part I, Item 1A, “Risk Factors — Midstream Generation Facility.”

Expenses primarily are affected by the following factors:

Midstream’s expenses include depreciation, maintenance, and other operations expenses. Depreciation expense is affected by the cost of the facility in service, the time the facility was placed in service, and the estimated useful life of the facility. Maintenance expenses generally depend on the physical characteristics of the facility, the frequency and duration of the facility’s operations, and the effectiveness of preventive maintenance. Other operating expenses mainly relate to administrative expenses, employee benefits, and generation operating expenses.



Midstream’s Results of Operations — Year ended December 31, 2012, Compared to Year ended December 31, 2011
	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2012			2011			VARIANCE			CHANGE
Operating revenue
Tolling operations	$	25,559		$	19,004		$	6,555		34.5	%
Other operations	3			9			(6		)	(66.7	)%
Affiliate revenue	—			45			(45		)	(100.0	)%
Total operating revenue	$	25,562		$	19,058		$	6,504		34.1	%
Operating expenses
Fuel used for electric generation	$	304		$	—		$	(304	)	—
Power purchased for utility customers	9			—			(9		)	—
Other operations	7,786			8,408			622			7.4	%
Maintenance	13,693			7,204			(6,489		)	(90.1	)%
Depreciation	6,006			5,872			(134		)	(2.3	)%
Taxes other than income taxes	2,559			2,399			(160		)	(6.7	)%
Loss on sales of assets	64			404			340			84.2	%
Total operating expenses	$	30,421		$	24,287		$	(6,134	)	(25.3	)%
Operating loss	$	(4,859	)	$	(5,229	)	$	370		7.1	%
Equity income from investees, before tax	$	—		$	62,053		$	(62,053	)	(100.0	)%
Other income	$	21,216		$	1,619		$	19,597		*
Interest charges (income)	$	770		$	(28,996	)	$	(29,766	)	(102.7	)%
Federal and state income tax expense	$	6,404		$	44,637		$	38,233		85.7	%
Net income	$	9,155		$	42,792		$	(33,637	)	(78.6	)%
* Not meaningful

Factors affecting Midstream during 2012 are described below.

Operating Revenue

Operating revenue increased $6.5 million, or 34.1%, in 2012 compared to 2011, largely as a result of higher tolling revenue at Evangeline resulting from the new power purchase agreement with Cleco Power for Units 6 and 7 that began in May 2012 as compared to the Evangeline 2010 Tolling Agreement with JPMVEC for Unit 7.

Operating Expenses

Operating expenses increased $6.1 million, or 25.3% in 2012 compared to 2011 primarily due to higher maintenance expenses. Maintenance expenses increased $6.5 million, or 90.1%, largely as a result of higher turbine maintenance expenses, higher routine maintenance expenses, and higher fall outage expenses at the Coughlin facility. For more information on Evangeline, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 12 — Variable Interest Entities — Consolidated VIEs — Evangeline.”

Equity Income from Investees

Equity income from investees decreased $62.1 million, or 100.0%, in 2012 compared to 2011 due to the absence of the gain from the disposition of Acadia Unit 2 during 2011. For more information on the Acadia Unit 2 transactions, see Item 8,

“Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions.”

Other Income

Other income increased $19.6 million in 2012 compared to 2011 primarily due to the contractual expiration of underlying indemnifications resulting from the disposition of Acadia Units 1 and 2.

Interest Charges

Interest charges increased $29.8 million, or 102.7%, during 2012 compared to 2011 largely as a result of the absence of a favorable tax settlement recorded in 2011 relating to legacy tax issues. For more information on the IRS settlement, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 9 — Income Taxes.”

Income Taxes

Federal and state income taxes decreased $38.2 million, or 85.7%, during 2012 compared to 2011. Tax expense decreased primarily due to the change in pre-tax income and the settlement of legacy tax issues, partially offset by tax returns as filed. The effective income tax rate is 41.2% which is different than the federal statutory rate primarily due to the effects of state income taxes and the settlement of legacy tax issues.



Cleco Consolidated Results of Operations — Year ended December 31, 2011, Compared to Year ended December 31, 2010
				FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010			VARIANCE			CHANGE
Operating revenue, net	$	1,117,313		$	1,148,666		$	(31,353	)	(2.7	)%
Operating expenses	819,066			855,707			36,641			4.3	%
Operating income	$	298,247		$	292,959		$	5,288		1.8	%
Allowance for other funds used during construction	$	4,947		$	12,413		$	(7,466	)	(60.1	)%
Equity income from investees, before tax	$	62,050		$	38,849		$	23,201		59.7	%
Gain on toll settlement	$	—		$	148,402		$	(148,402	)	(100.0	)%
Other income	$	8,914		$	5,242		$	3,672		70.0	%
Other expense	$	(5,646	)	$	(4,609	)	$	(1,037	)	(22.5	)%
Interest charges	$	70,658		$	95,776		$	25,118		26.2	%
Federal and state income taxes	$	102,897		$	142,498		$	39,601		27.8	%
Net income applicable to common stock	$	195,710		$	255,345		$	(59,635	)	(23.4	)%

Consolidated net income applicable to common stock decreased $59.6 million, or 23.4%, in 2011 compared to 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 $31.4 million, or 2.7%, in 2011 compared to 2010 largely as a result of higher base revenue at Cleco Power.

Operating expenses decreased $36.6 million, or 4.3%, in 2011 compared to 2010 primarily due to lower per unit costs and volumes of power purchased for utility customers.

Allowance for other funds used during construction decreased $7.5 million, or 60.1%, in 2011 compared to 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 $23.2 million, or 59.7%, in 2011 compared to 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 $41.0 million gain from Cleco Power’s acquisition of Acadia Unit 1 and half of Acadia Power Station’s related common facilities during 2010. For more information on the Acadia Unit 1 and 2 transactions, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions.”

Gain on toll settlement was $148.4 million in 2010 due to transactions related to the termination of the existing Evangeline Tolling Agreement and the execution of the Evangeline 2010 Tolling Agreement. For more information, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 17 — Evangeline Transactions.”

Other income increased $3.7 million, or 70.0%, in 2011 compared to 2010 primarily due to death benefits paid on life insurance policies at Cleco Corporation and higher royalty payments and higher revenue from mutual assistance to other utilities for restoration efforts at Cleco Power.

Other expense increased $1.0 million, or 22.5%, in 2011 compared to 2010 primarily due to a decrease in the cash surrender value of life insurance policies at Cleco Corporation.

Interest charges decreased $25.1 million, or 26.2%, in 2011 compared to 2010 largely due to the settlement of legacy tax issues and the retirement of Evangeline’s debt in 2010. Also contributing to the decrease were lower corporate interest charges related to the repayment of a bank term loan in April 2011. Partially offsetting these decreases was higher interest charges at Cleco Power.

Federal and state income taxes decreased $39.6 million in 2011 compared to 2010 primarily due to a decrease in pre-tax income excluding AFUDC equity, partially offset by the settlement of legacy tax issues. The effective income tax rate is 34.4% which is different than the federal statutory rate primarily due to the settlement of legacy tax issues and state tax expense.

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



Cleco Power’s Results of Operations — Year ended December 31, 2011, Compared to Year ended December 31, 2010
	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010			VARIANCE			CHANGE
Operating revenue
Base	$	605,024		$	592,676		$	12,348		2.1	%
Fuel cost recovery	446,932			493,426			(46,494		)	(9.4	)%
Electric customer credits	(6,811		)	(9,596		)	2,785			29.0	%
Other operations	50,948			42,578			8,370			19.7	%
Affiliate revenue	1,389			1,371			18			1.3	%
Operating revenue, net	$	1,097,482		$	1,120,455		$	(22,973	)	(2.1	)%
Operating expenses
Fuel used for electric generation – recoverable	$	379,771		$	355,425		$	(24,346	)	(6.8	)%
Power purchased for utility customers – recoverable	67,167			138,051			70,884			51.3	%
FAC non-recoverable fuel and power purchased	6,778			14,226			7,448			52.4	%
Other operations	116,988			109,678			(7,310		)	(6.7	)%
Maintenance	74,603			72,048			(2,555		)	(3.5	)%
Depreciation	115,634			107,966			(7,668		)	(7.1	)%
Taxes other than income taxes	32,157			32,744			587			1.8	%
(Gain) loss on sale of assets	(9		)	47			56			119.1	%
Total operating expenses	$	793,089		$	830,185		$	37,096		4.5	%
Operating income	$	304,393		$	290,270		$	14,123		4.9	%
Allowance for other funds used during construction	$	4,947		$	12,413		$	(7,466	)	(60.1	)%
Other income	$	3,163		$	2,007		$	1,156		57.6	%
Interest charges	$	97,090		$	78,731		$	(18,359	)	(23.3	)%
Federal and state income taxes	$	69,409		$	75,107		$	5,698		7.6	%
Net income	$	142,835		$	147,405		$	(4,570	)	(3.1	)%

Cleco Power’s net income for 2011 decreased $4.6 million, or 3.1%, compared to 2010. Contributing factors include:


•	higher interest charges,


•	higher other operations and maintenance expenses,


•	lower allowance for other funds used during construction, and


•	higher depreciation expense.

These were partially offset by:


•	higher base revenue,


•	higher other operations revenue,


•	lower FAC non-recoverable fuel and power purchased,


•	lower electric customer credits, and


•	lower income taxes.



	FOR THE YEAR ENDED DEC. 31,
				FAVORABLE/
(MILLION kWh)	2011		2010	(UNFAVORABLE)
Electric sales
Residential	3,877		3,978	(2.5	)%
Commercial	2,650		2,605	1.7	%
Industrial	2,366		2,271	4.2	%
Other retail	134		138	(2.9	)%
Total retail	9,027		8,992	0.4	%
Sales for resale	1,888		1,983	(4.8	)%
Unbilled	(139	)	46	(402.2	)%
Total retail and wholesale customer sales	10,776		11,021	(2.2	)%



	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/
(THOUSANDS)	2011			2010			(UNFAVORABLE)
Electric sales
Residential	$	294,076		$	271,781		8.2	%
Commercial	179,786			160,039			12.3	%
Industrial	85,965			78,158			10.0	%
Other retail	9,815			9,186			6.8	%
Storm surcharge	10,695			8,888			20.3	%
Other	(6,426		)	(6,005		)	(7.0	)%
Total retail	$	573,911		$	522,047		9.9	%
Sales for resale	45,633			47,954			(4.8	)%
Unbilled	(14,520		)	22,675			(164.0	)%
Total retail and wholesale customer sales	$	605,024		$	592,676		2.1	%



	FOR THE YEAR ENDED DEC. 31,
				2011 CHANGE
	2011	2010	NORMAL	PRIOR YEAR		NORMAL
Cooling degree-days	3,255	3,150	2,689	3.3	%	21.0	%
Heating degree-days	1,510	1,967	1,620	(23.2	)%	(6.8	)%

Base

Base revenue increased $12.3 million, or 2.1%, during 2011 compared to 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 2011.

Fuel Cost Recovery

Fuel cost recovery revenue billed to customers during 2011 compared to 2010 decreased $46.5 million, or 9.4%, primarily due to decreases in the per-unit costs of fuel used for electric generation and power purchased for utility customers, and lower volumes of power purchased for utility customers. Partially offsetting the decreases were higher volumes of fuel used for electric generation and lower volumes of power purchased, primarily due to Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1 during 2010.

Electric Customer Credits

Electric customer credits decreased $2.8 million, or 29.0%, in 2011 compared to 2010 as a result of a lower estimated accrual for a rate refund. For more information on the accrual of electric customer credits, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 11 — Electric Customer Credits.”

Other Operations

Other operations revenue increased $8.4 million, or 19.7%, in 2011 compared to 2010, primarily due to a $4.1 million gain on the sale of Cleco Power’s fuel oil supply, $2.5 million of higher mineral lease payments, $0.7 million of higher transmission revenue, $0.7 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 $0.4 million of higher customer fees.

Operating Expenses

Operating expenses decreased $37.1 million, or 4.5%, in 2011 compared to 2010. Fuel used for electric generation (recoverable) increased $24.3 million, or 6.8%, primarily due to higher volumes of fuel used as compared to 2010. Partially offsetting this increase were lower per unit costs of fuel used for electric generation. Power purchased for utility customers (recoverable) decreased $70.9 million, or 51.3%, 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. FAC non-recoverable fuel and power purchased decreased $7.4 million, or 52.4%, 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 2011. Other operations expense increased $7.3 million, or 6.7%, primarily due to higher generating station, transmission, and distribution expenses and higher employee benefit costs and administrative expenses. Partially offsetting these increases were lower professional fees. Maintenance expenses increased $2.6 million, or 3.5%, during 2011 compared to 2010 primarily due to higher generating station and distribution maintenance work performed during 2011. Other operations and maintenance expenses were impacted during 2011 as a result of Madison Unit 3 being placed in service and the acquisition of Acadia Unit 1. Depreciation expense increased $7.7 million, or 7.1%, 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 $7.5 million, or 60.1%, during 2011 compared to 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 $1.2 million, or 57.6%, during 2011 compared to 2010 primarily due to higher royalty payments and higher revenue from mutual assistance to other utilities for restoration efforts.

Interest Charges

Interest charges increased $18.4 million, or 23.3%, during 2011 compared to 2010 primarily due to $13.3 million related to the November 2010 issuance of $250.0 million of senior notes, $8.9 million related to uncertain tax positions, and $2.8 million of lower interest charges capitalized in 2011 compared to 2010 associated with Madison Unit 3. Partially offsetting this increase was $3.3 million from the repayment of insured quarterly notes and a bank term loan in October 2010 and November 2010, respectively, and $3.3 million of other miscellaneous interest charges.

Income Taxes

Federal and state income taxes decreased $5.7 million, or 7.6%, during 2011 compared to 2010, primarily due to a decrease in pre-tax income excluding AFUDC equity. The effective income tax rate is 32.7% which is different than the federal statutory rate due to the effects of state income taxes.



Midstream’s Results of Operations — Year ended December 31, 2011, Compared to Year ended December 31, 2010
	FOR THE YEAR ENDED DEC. 31,
						FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2011			2010			VARIANCE			CHANGE
Operating revenue
Tolling operations	$	19,004		$	26,067		$	(7,063	)	(27.1	)%
Other operations	9			3			6			200.0	%
Affiliate revenue	45			960			(915		)	(95.3	)%
Total operating revenue	$	19,058		$	27,030		$	(7,972	)	(29.5	)%
Operating expenses
Other operations	$	8,408		$	8,082		$	(326	)	(4.0	)%
Maintenance	7,204			8,868			1,664			18.8	%
Depreciation	5,872			5,779			(93		)	(1.6	)%
Taxes other than income taxes	2,399			342			(2,057		)	(601.5	)%
Loss on sales of assets	404			387			(17		)	(4.4	)%
Total operating expenses	$	24,287		$	23,458		$	(829	)	(3.5	)%
Operating (loss) income	$	(5,229	)	$	3,572		$	(8,801	)	(246.4	)%
Equity income from investees, before tax	$	62,053		$	38,848		$	23,205		59.7	%
Gain on toll settlement	$	—		$	148,402		$	(148,402	)	(100.0	)%
Interest (income) charges	$	(28,996	)	$	7,140		$	36,136		506.1	%
Federal and state income tax expense	$	44,637		$	71,255		$	26,618		37.4	%
Net income	$	42,792		$	114,467		$	(71,675	)	(62.6	)%

Factors affecting Midstream during 2011 are described below.

Operating Revenue

Operating revenue decreased $8.0 million, or 29.5%, in 2011 compared to 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 95.3%, in 2011 compared to 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 $1.7 million, or 18.8%, in 2011 compared to 2010, largely as a result of lower turbine maintenance expenses at Evangeline. Taxes other than income taxes increased $2.1 million, or 601.5%, primarily due to higher property taxes at Evangeline as a result of the expiration of a 10-year property tax exemption.

Equity Income from Investees

Equity income from investees increased $23.2 million, or 59.7%, in 2011 compared to 2010 primarily due to increased equity earnings at APH primarily 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 more information on the Acadia Unit 1 and 2 transactions, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 18 — Acadia Transactions.”

Gain on Toll Settlement

Gain on toll settlement was $148.4 million in 2010 due to transactions related to the termination of the Evangeline Tolling Agreement and the execution of the Evangeline 2010 Tolling Agreement. For more information, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 17 — Evangeline Transactions.”

Interest Charges

Interest charges decreased $36.1 million, or 506.1%, during 2011 compared to 2010 primarily due to the settlement of legacy tax issues and the retirement of Evangeline’s debt in 2010. For more information on the IRS settlement, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 9 — Income Taxes.”

Income Taxes

Federal and state income taxes decreased $26.6 million, or 37.4%, during 2011 compared to 2010, primarily due to a decrease in pre-tax income, partially offset by adjustments related to the settlement of legacy tax issues. The effective income tax rate is 51.1% which is different than the federal statutory rate primarily due to prior year adjustments related to the settlement of legacy tax issues and the effects of state income taxes.



CLECO POWER LLC — NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2012, and the year ended December 31, 2011, see “Results of Operations — Cleco Power’s Results of Operations — Year ended December 31, 2012, Compared to Year ended December 31, 2011.”

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2011, and the year ended December 31, 2010, see “Results of Operations — Cleco Power’s Results of

Operations — Year ended December 31, 2011, Compared to Year ended December 31, 2010.”

The narrative analyses referenced above should be read in combination with Cleco Power’s Financial Statements and the Notes contained in this Form 10-K.



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 GAAP, 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. For more information on Cleco’s accounting policies, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 2 — Summary of Significant Accounting Policies.”

Cleco believes that the following are the most significant critical accounting policies:

•

Cleco accounts for pension and other postretirement benefits under applicable GAAP. To determine assets, liabilities, income, and expense relating to pension and other postretirement benefits, management must make assumptions about future trends. Assumptions and estimates include, but are not limited to, discount rate, expected return on plan assets, future rate of compensation increases, and medical inflation trend rates. These assumptions are reviewed and updated on an annual basis. Changes in the rates from year to year and newly-enacted laws could have a material effect on Cleco’s financial condition and results of operations by changing the recorded assets, liabilities, income, expense, or required funding of the pension plan obligation. One component of pension expense is the expected return on plan assets. It is an assumed percentage return on the market-related value of plan assets. The market-related value of plan assets differs from the fair value of plan assets by the amount of deferred asset gains or losses. Actual asset returns that differ from the expected return on plan assets are deferred and recognized in the market-related value of assets on a straight-line basis over a five-year period. The 2012 return on plan assets was 15.2% compared to an expected long-term return of 6.6%. For 2011, the return on plan assets was 8.7% compared to an expected long-term return of 7.8%. For the calculation of the 2013 periodic expense, Cleco is increasing the expected long-term return on plan

assets to 6.78%. This increase was caused by a slight shift to the upper target of international equity investments as allowed by the investment policy statement. The change in allocation is expected to decrease expense by approximately $0.6 million.

For the December 31, 2011, measurement of liabilities, management began using a theoretical bond portfolio in order to calculate the discount rate. As a result of the annual review of assumptions, the discount rate decreased from 5.08% to 4.19% for the December 31, 2012, measurement of liabilities.

A change in the assumed discount rate creates a deferred actuarial gain or loss. Generally, when the assumed discount rate decreases compared to the prior measurement date, a deferred actuarial loss is created. When the assumed discount rate increases compared to the prior measurement date, a deferred actuarial gain is created. Actuarial gains and losses also are created when actual results, such as compensation increases, differ from assumptions. Deferred actuarial gains and losses are recorded as a regulatory asset or liability. The net of the deferred gains and losses is amortized to pension expense over the average service life of the remaining plan participants, 11 years for Cleco’s plan, when it exceeds certain thresholds. This approach to amortization of gains and losses has the effect of reducing the volatility of pension expense attributable to investment returns. Over time, it is not expected to reduce or increase the pension expense relative to an approach that immediately recognizes losses and gains.

The decrease in the discount rate is expected to increase pension expense by approximately $5.0 million in 2013 compared to 2012. Since the assumption is evaluated yearly, the increase may not extend past 2013.

Cleco Power made no contributions to the pension plan during 2012 as compared to $60.0 million in discretionary contributions in 2011 and $5.0 million required contributions in 2010. In January 2013, Cleco Power made $34.0 million in discretionary contributions to the pension plan. Based on current funding assumptions, management estimates that no pension contributions will be required through 2017. Future discretionary contributions may be made depending on changes in assumptions, the ability to utilize the contribution as a tax deduction, and requirements concerning recognizing a minimum pension liability. Future required contributions are driven by liability funding target percentages set by law which could cause the required contributions to change from year to year. The ultimate amount and timing of the contributions will be affected by changes in the discount rate, changes in the funding regulations, and actual returns on fund assets. Adverse changes in assumptions, or adverse actual events could cause additional minimum contributions.

For more information on pension and other postretirement benefits, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 8 — Pension Plan and Employee Benefits.”

•

Income tax expense and related balance sheet amounts are comprised of a “current” portion and a “deferred” portion. The current portion represents Cleco’s estimate of the income taxes payable or receivable for the current year. The deferred portion represents Cleco’s estimate of the future income tax effects of events that have been recognized in the financial statements or income tax returns in the current or prior years. Cleco makes assumptions and estimates when it records income taxes, such as its ability to deduct items on its tax returns, the timing of the deduction, and the effect of regulation by the LPSC on income taxes. Cleco’s income tax expense and related assets and liabilities could be affected by changes in its assumptions and estimates and by ultimate resolution of assumptions and estimates with taxing authorities. The actual results may differ from the estimated results based on these assumptions and may have a material effect on Cleco’s results of operations. For more information about Cleco Corporation’s income taxes, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 9 — Income Taxes.”

The provisions of the authoritative guidance relating to uncertain tax positions require management to estimate the reliability of positions taken on tax returns. These estimates could differ significantly from the ultimate outcome. For more information on income taxes, see Item 8, “Financial Statements and Supplemental Data — Notes to the Financial Statements — Note 9 — Income Taxes.”

•

Cleco Corporation consolidates entities as required by GAAP. Generally, a parent consolidates entities in which it controls, either directly or indirectly, the majority of the voting interest. Additionally, a parent could be required to consolidate an entity in which it does not control a majority voting interest if the subsidiary is a variable interest entity and meets certain criteria making the parent the primary beneficiary of an entity. An entity is a variable interest entity if it lacks the ability to finance its activities without support from other parties, if its owners lack controlling financial interest in the entity, or if the entity either conducts substantially all of its activities with or on behalf of an investor or if voting rights are disproportional to risks and rewards. While consolidation or the equity method of accounting will not affect net income applicable to common shareholders, it may affect specific line items within the income statement, such as revenue, specific expense line items, and income from equity investees. Consolidation or the equity method of accounting of an entity will affect specific balance sheet items such as property, plant, and equipment, and long-term debt, which will cause changes in total assets and total liabilities. Shareholders’ equity should not be affected by consolidation or the equity method of accounting of entities. Effective January 1, 2010, the requirements for consolidation changed, requiring Cleco Corporation to consolidate Perryville, Attala, and Evangeline which had been previously accounted for using the equity method.

•

Part of the compensation employees and directors receive is in the form of equity instruments. The instruments may take the form of restricted stock, stock equivalent units, or other types of equity instruments as described in the compensatory plans. Cleco recognizes equity compensation at the grant date fair value for instruments settled in equity and reporting date fair value for equity compensation settled in cash. Estimates used in the calculation require management judgments and could cause volatility in earnings. For more information on stock-based compensation, see Item 8, “Financial Statements and Supplemental Data — Notes to the Financial Statements — Note 7 — Common and Preferred Stock — Common Stock — Stock-Based Compensation.”

Cleco Power

Cleco Power’s prices are regulated by the LPSC and FERC. By determining what costs can be recovered by Cleco Power through the price it charges its customers, regulatory assets and liabilities are recognized. Future changes made by the regulatory bodies could have a material impact on the operations and financial condition of Cleco Power. Three areas that could be materially impacted by future actions of regulators are:

•

The LPSC determines the ability of Cleco Power to recover prudent costs incurred in developing long-lived assets. If the LPSC were to rule that the cost of current or future long-lived assets was imprudent and not recoverable, Cleco Power could be required to write down the imprudent cost and incur a corresponding impairment loss. At December 31, 2012, the carrying value of Cleco Power’s long-lived assets was $2.64 billion. Currently, Cleco Power has concluded that none of its long-lived assets are impaired.

•

Cleco Power has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At December 31, 2012, Cleco Power had $510.7 million in regulatory assets, net of regulatory liabilities. Actions by the LPSC could limit the recovery of these regulatory assets, causing Cleco Power to record a loss on some or all of the regulatory assets. For more information on the LPSC and regulatory assets, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 2 — Summary of Significant Accounting Policies — Regulation,” Note 3 — “Regulatory Assets and Liabilities,” and “— Financial Condition — Regulatory and Other Matters — Lignite Deferral.”

•

The LPSC determines the amount and type of fuel and purchased power costs that Cleco Power can charge customers through the FAC. Changes in the determination of allowable costs already incurred by Cleco Power could cause material changes in fuel revenue. For the years ended December 31, 2012, 2011, and 2010, Cleco Power reported fuel revenue of $337.6 million, $446.9 million, and $493.4 million, respectively.

At December 31, 2012, Cleco Power had $12.4 million in losses in other comprehensive income and $7.3 million of losses and ineffectiveness deferred as a regulatory asset related to interest rate derivatives entered into in 2011. As a result of management’s assessment that it is probable that the losses and ineffectiveness will be recovered through the rate-making process, Cleco Power will amortize the regulatory asset over the 30-year term of the related debt. If management determines that the forecasted future interest payments will not occur and the LPSC determines the costs were imprudent, then any gain or loss on the interest rate derivatives will be required to be recognized in income immediately. For more information on these interest rate derivatives, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 5 — “Fair Value Accounting — Interest Rate Derivatives — Forward Starting Interest Rate Swap.”

Midstream

Generally, Midstream is most affected by market conditions and changes in contract counterparty credit ratings and financial condition. Currently, Cleco Power is Midstream’s only counterparty.

•

Certain triggering events could cause Midstream to determine that its long-lived assets may be impaired according to applicable accounting guidance. Triggering events which apply to long-lived assets include, but are not limited to, a significant decrease in the market value of long-lived assets, a significant change in legal factors, such as adverse changes in environmental laws, or a current operating or cash flow loss combined with a projection of continued losses in the future. Any impairment calculated is subject to many assumptions and estimations. Management must make assumptions about expected future cash flows, long-term interest rates, estimates about the probability of the occurrence of future events, and estimates of market value of assets without a readily observable market price. Differences between the estimate made at a particular balance sheet date and actual events could cause material adjustments to an impairment charge. In February 2010, a triggering event occurred at Evangeline when the long-term Evangeline Tolling Agreement was terminated. 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.

On October 30, 2012, Cleco Power announced Evangeline as the winning bidder in the Cleco Power 2012 Long-Term RFP, subject to further due diligence, the completion of definitive agreements, and regulatory approvals from the LPSC and FERC. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. The transaction is expected to close as early as the fourth quarter of 2013, after completion of regulatory approvals. If this transaction does not close and Evangeline does not obtain a long-term agreement for Coughlin’s capacity, the expected future net cash flows of Evangeline could be 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. At December 31, 2012, Midstream had $180.4 million in long-lived assets. For more information on the Evangeline transaction, see “— Financial Condition — Regulatory and Other Matters — Generation RFP — 2012 Long-Term RFP for Capacity and Energy Resources.”

•

At December 31, 2012, Midstream had $8.2 million in indemnification liabilities related to the Acadia Unit 1 and Acadia Unit 2 transactions. The indemnification liabilities contain management’s assumptions and estimates concerning the amount, timing, and probability of potential payments. If those assumptions and estimates do not reflect actual results, then certain triggering events could cause Midstream to make payments in excess of the liability, which could result in additional expenses. For more information regarding these transactions, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”



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 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 December 31, 2012:



	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.

At December 31, 2012, Moody’s outlooks for both Cleco Corporation and Cleco Power were stable and Standard & Poor’s outlooks for both Cleco Corporation and Cleco Power were positive. Cleco Corporation and Cleco Power pay fees

and interest under their bank credit agreements based on the highest rating held. If Cleco Corporation’s or Cleco Power’s credit ratings were to be downgraded by Moody’s or 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 Moody’s or Standard & Poor’s, Cleco Power would be required to post additional collateral for derivatives.

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 more information about fair value levels, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 5 — Fair Value Accounting.”

Cash Generation and Cash Requirements

Restricted Cash and Cash Equivalents

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 and cash equivalents consisted of:



	AT DEC. 31,
(THOUSANDS)	2012		2011
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Katrina/Rita’s storm recovery bonds	8,781		8,761
Cleco Power’s future storm restoration costs	5,343		24,876
Cleco Power’s renewable energy grant	—		381
Cleco Power’s NO_x allowance escrow	—		1,713
Total restricted cash and cash equivalents	$	14,221	$	35,828

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 2012, Cleco Katrina/Rita collected $20.1 million net of operating expenses. In March and September 2012, Cleco Katrina/Rita used $6.7 million and $6.4 million, respectively, for scheduled storm recovery bond principal payments and $3.6 million and $3.4 million, respectively for related interest. Cleco Power’s restricted cash and cash equivalents held for future storm restoration costs decreased $19.5 million from December 31, 2011, primarily due to the transfer of $10.9 million to restricted investments and the transfer of $10.0 million to cover expenses associated with Hurricane Isaac. These amounts were partially offset by $1.4 million of storm surcredits. Cleco Power’s restricted cash and cash equivalents NO_x allowance escrow decreased $1.7 million from December 31, 2011. The funds were transfered from restricted to non-restricted cash and cash equivalents due to the courts vacating CSAPR. For more information about the restricted investments, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 5 — Fair Value Accounting — Restricted Investments” and for more information about Hurricane Isaac, see Item 8, “Financial Statements and Supplemental Data — Notes to the Financial Statements — Note 19 — Storm Restoration.” For more information about CSAPR, see Part I, Item 1, “Business — Environmental Matters — Environmental Quality — Air Quality.”

At December 31, 2012 and 2011, Midstream had no restricted cash and cash equivalents.

Debt

Cleco Consolidated

Cleco had no short-term debt outstanding at December 31, 2012 or 2011.

At December 31, 2012, Cleco’s long-term debt outstanding was $1.35 billion, of which $91.1 million was due within one year, compared to $1.36 billion outstanding at December 31, 2011, which included $26.1 million due within one year. The long-term debt due within one year at December 31, 2012, represents $75.0 million in senior notes due May 1, 2013, $14.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds, and $2.1 million of capital lease payments.

For Cleco, long-term debt decreased $14.8 million from December 31, 2011, primarily due to redeeming $50.1 million of DeSoto Parish pollution control bonds in May 2012 and $13.1 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2012. Also contributing to the decrease was the redemption of $11.2 million of Rapides Parish pollution control bonds in January 2012 and a $6.2 million decrease in capital lease obligations. These decreases were partially offset by the issuance of $50.0 million senior unsecured notes in May 2012, a $15.0 million increase in credit facility draws outstanding, and debt premium amortizations of $0.8 million.

On January 25, 2012, Cleco Power redeemed at par $11.2 million of 5.875% Rapides Parish pollution control bonds due September 2029. As part of the redemption, Cleco Power paid $0.3 million of accrued interest on the redeemed notes.

On May 8, 2012, Cleco Power issued $50.0 million senior unsecured private placement notes at an interest rate of 4.33%. The maturity date of the notes is May 15, 2027. The proceeds were used primarily for the early redemption of $50.1 million of 5.875% DeSoto Parish pollution control bonds as described above.

On May 11, 2012, Cleco Power redeemed at par all $50.1 million of 5.875% DeSoto Parish pollution control bonds due September 2029. As part of the redemption, Cleco Power paid $0.6 million of accrued interest on the redeemed notes.

Cash and cash equivalents available at December 31, 2012, were $31.0 million combined with $525.0 million available credit facility capacity ($225.0 million from Cleco Corporation and $300.0 million from Cleco Power) for total liquidity of $556.0 million. Cash and cash equivalents available at December 31, 2012, decreased $62.6 million when compared to cash and cash equivalents available at December 31, 2011. This decrease is primarily due to additions to property, plant, and equipment, the net repayment of debt, the repurchase of common stock, and payment of common stock dividends.

At December 31, 2012, 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 more information on the concentration of credit risk through short-term investments classified as cash equivalents, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 5 — Fair Value Accounting.”

At December 31, 2012 and 2011, Cleco had a working capital surplus of $152.7 million and $135.8 million, respectively. The $16.9 million increase in working capital is primarily due to:


•	$75.4 million net decrease in current tax liabilities and uncertain tax positions and related interest charges expected to be settled in the next 12 months,


•	$24.8 million decrease in accounts payable,


•	$24.8 million decrease in regulatory liabilities,


•	$6.3 million increase in cash surrender value of company and trust-owned life insurance policies,


•	$5.7 million increase in accumulated deferred fuel,


•	$5.3 million decrease in energy risk management liabilities, and


•	$5.0 million increase in fuel inventories.

These increases in working capital were partially offset by:


•	$65.0 million increase in long-term debt due within one year and


•	$62.6 million decrease in cash and cash equivalents as discussed above.

At December 31, 2012, Cleco’s Consolidated Balance Sheet reflected $2.65 billion of total liabilities compared to $2.63 billion at December 31, 2011. The $17.8 million increase in total liabilities was primarily due to increases in accumulated deferred federal and state income taxes. These increases were partially offset by decreases in uncertain tax positions, regulatory liabilities, accounts payable, contingent sale obligations, and long-term debt. Accumulated deferred federal and state income taxes increased $113.1 million during 2012. During 2012, uncertain tax positions decreased $47.9 million, regulatory liabilities decreased $32.1 million, accounts payable decreased $24.8 million, and contingent sale obligations decreased $21.2 million. Long-term debt decreased $14.8 million during 2012, as discussed above.

Cleco Corporation (Holding Company Level)

Cleco Corporation had no short-term debt outstanding at December 31, 2012 or 2011.

At December 31, 2012, Cleco Corporation had $25.0 million draws outstanding under its $250.0 million credit facility compared to $10.0 million outstanding at December 31, 2011. The interest rate of outstanding borrowings under the credit facility at December 31, 2012, was 1.71%. The existing borrowings had 30-day terms. The $25.0 million draws outstanding consisted of a $15.0 million draw and a $10.0 million draw. The $15.0 million draw matured and was renewed on January 17, 2013, and was subsequently repaid on February 4, 2013. The $10.0 million draw matured and was repaid on January 28, 2013. 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 December 31, 2012, were $7.4 million. Cash and cash equivalents available at December 31, 2012, decreased $15.2 million when compared to cash and cash equivalents available at December 31, 2011, primarily due to routine working capital fluctuations. At December 31, 2012, outstanding credit facility borrowings reduced available borrowings by $25.0 million, leaving an available capacity of $225.0 million.

Cleco Power

There was no short-term debt outstanding at Cleco Power at December 31, 2012 or 2011.

At December 31, 2012, Cleco Power’s long-term debt outstanding was $1.32 billion, of which $91.1 million was due within one year, compared to $1.35 billion at December 31, 2011, of which $26.1 million was due within one year. The long-term debt due within one year at December 31, 2012, represents $75.0 million senior notes due May 1, 2013, $14.0 million principal payments for the Cleco Katrina/Rita storm recovery bonds, and $2.1 million of capital lease payments.

recovery bond principal payments made in March and September 2012. Also contributing to the decrease was the redemption of $11.2 million of Rapides Parish pollution control bonds in January 2012 and a $6.2 million decrease in capital lease obligations. These decreases were partially offset by the issuance of $50.0 million senior unsecured notes in May 2012 and debt premium amortization of $0.8 million.

At December 31, 2012 and 2011, there were no borrowings 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 December 31, 2012, were $23.4 million combined with $300.0 million credit facility capacity for total liquidity of $323.4 million. Cash and cash equivalents decreased $44.1 million, when compared to cash and cash equivalents at December 31, 2011, primarily due to additions to property, plant, and equipment, the payment of intercompany dividends, and the net repayment of debt.

At December 31, 2012 and 2011, Cleco Power had a working capital surplus of $96.3 million and $36.4 million, respectively. The $59.9 million increase in working capital is primarily due to:


•	$98.0 million net decrease in current tax liabilities and uncertain tax positions and related interest charges expected to be settled in the next 12 months,


•	$23.5 million decrease in accounts payable,


•	$24.8 million decrease in regulatory liabilities,


•	$5.7 million increase in accumulated deferred fuel,


•	$5.3 million decrease in energy risk management liabilities, and


•	$5.0 million increase in fuel inventories.

These increases in working capital were partially offset by:


•	$65.0 million increase in long-term debt due within one year and


•	$44.1 million decrease in cash and cash equivalents as discussed above.

In December 2011, Cleco Power issued $100.0 million aggregate principal amount of 5.12% senior unsecured notes in a private placement. The notes will mature on December 16, 2041. The net proceeds from the issuance, along with short-term liquidity, were used to finance the mandatory tender of $32.0 million and $100.0 million tax exempt bonds in

October 2011 and December 2011, respectively. The private placement bonds have a covenant requiring Cleco Power to maintain total indebtedness equal to or less than 65% of total capitalization. At December 31, 2012, approximately $623.7 million of Cleco Power’s member’s equity was unrestricted.

At December 31, 2012, Cleco Power’s Consolidated Balance Sheet reflected $2.55 billion of total liabilities compared to $2.50 billion at December 31, 2011. The $56.2 million increase in total liabilities during 2012 was primarily due to increases in accumulated deferred federal and state income taxes. These increases were partially offset by decreases in uncertain tax positions, long-term debt, regulatory liabilities, and accounts payable. Accumulated deferred federal and state income taxes increased $169.9 million during 2012. Long-term debt decreased $29.8 million during 2012, as discussed above. During 2012, uncertain tax positions decreased $47.1 million, regulatory liabilities decreased $32.1 million, and accounts payable decreased $23.5 million.

Credit Facilities

Cleco Corporation’s current credit facility agreement has a maximum capacity of $250.0 million and matures on October 7, 2016. The borrowing costs are LIBOR plus 1.50% or ABR, plus facility fees of 0.25%. 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 credit facility. At December 31, 2012, Cleco Corporation had $25.0 million borrowings outstanding under its existing credit facility, leaving an available borrowing capacity of $225.0 million.

Cleco Power’s current credit facility agreement has a maximum capacity of $300.0 million and matures on October 7, 2016. The borrowing costs are LIBOR plus 1.275% or ABR, plus facility fees of 0.225%. 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 credit facility.

At December 31, 2012, 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.

Midstream

Midstream had no debt outstanding at December 31, 2012 or 2011.

Cleco Consolidated Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities was $263.1 million during 2012, $310.1 million during 2011, and $216.9 million in 2010. Cash provided by operating activities during 2012 decreased $47.0 million from 2011, primarily due to the following items:


•	the absence of the return on equity investment in Acadia of $58.7 million,


•	the absence of 2011 fuel oil inventory sales of $31.5 million,


•	higher vendor payments of $29.2 million,


•	higher deferred fuel costs of $12.9 million,


•	higher expenditures for other fuel inventories and related transportation of $12.4 million,


•	the absence of $10.9 million cash received in exchange for accepting the contingent sale liability related to the Acadia Unit 2 transaction in 2011, and


•	lower collection of receivables of $5.4 million.

These decreases were partially offset by:


•	the absence of pension plan contributions of $60.0 million,


•	lower tax payments of $47.3 million, and


•	lower payments for gas and power purchases of $11.5 million.

Cash provided by operating activities during 2011 increased $93.2 million from 2010, primarily due to the following items:


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


•	absence of 2010 Madison Unit 3 construction carrying costs, Acadia Unit 1 acquisition costs, rate case costs, and IRP/FRP costs of $47.2 million,


•	higher collection of receivables of $30.6 million,


•	fuel oil inventory sales of $31.5 million,


•	lower income taxes paid of $28.9 million,


•	lower petroleum coke inventory purchases of $23.3 million due to the build-up of inventory in 2010,


•	lower natural gas purchases of $3.9 million due to the build-up of inventory in 2010, and


•	lower postretirement plan carrying costs of $2.4 million.

These were partially offset by:


•	higher pension plan contributions of $55.0 million,


•	absence of the 2010 collection of a $28.0 million long-term receivable related to the Evangeline Restructuring Agreement,


•	higher coal inventory purchases of $16.7 million,


•	absence of the 2010 cash portion of the gain related to the Evangeline Restructuring Agreement of $18.5 million, and


•	higher vendor payments of $9.3 million.

Net Investing Cash Flow

Net cash used in investing activities was $229.2 million during 2012, $103.7 million during 2011, and $308.6 million in 2010. Net cash used in investing activities in 2012 was higher than 2011, primarily due to the absence of the 2011 return of investment in Acadia, higher additions to property, plant, and equipment, higher contributions to the NMTC Fund, and purchases of restricted investments, partially offset by higher transfers of cash from restricted accounts, higher property, plant, and equipment grants received, and a higher return of investment in the NMTC Fund. Net cash used in investing activities in 2011 was lower than 2010, primarily due lower additions to property, plant, and equipment, the return of equity investment in Acadia, returns of investment in the NMTC Fund, the absence of a 2010 repayment of a company-owned life insurance loan, and lower investments in equity investees. These were partially offset by lower transfers of cash from

restricted accounts and higher contributions to the NMTC Fund.

During 2012, Cleco had additions to property, plant, and equipment, net of AFUDC of $238.3 million, a $59.6 million investment in the NMTC Fund, and purchases of restricted investments, net of premium and interest of $12.0 million. This was partially offset by a $37.7 million return of investment from the NMTC Fund, $21.6 million of cash transferred from restricted accounts, $16.6 million of grants received, and a $5.5 million property loss insurance reimbursement. The cash transferred from restricted accounts was primarily related to restricted investments and cash restricted for storm costs.

During 2011, Cleco had additions to property, plant, and equipment, net of AFUDC, of $197.5 million and a $43.9 million investment in the NMTC Fund. This was partially offset by an $89.7 million return of equity investment in Acadia, a $33.4 million return of investment from the NMTC Fund, the transfer of $5.2 million of cash from restricted accounts, primarily related to GO Zone bonds and cash restricted for storm costs, and a $4.5 million property loss insurance reimbursement.

During 2010, Cleco had additions to property, plant, and equipment, net of AFUDC of $294.5 million, primarily from the Acadia Unit 1 transaction, the Acadiana Load Pocket transmission project, and the Teche Unit 4 Blackstart project. For more information on these projects, see “— Regulatory and Other Matters — Acadiana Load Pocket Transmission Project” and “— Teche Unit 4 Blackstart Project.” Cleco also made investments in the NMTC Fund of $35.9 million, an $8.5 million investment in Acadia, and a $0.2 million investment in Oxbow. Cleco used $14.4 million to repay a loan on company-owned life insurance. These investments were partially offset by the transfer of $45.5 million of cash from restricted accounts, primarily related to the termination of the Evangeline Tolling Agreement and to GO Zone bonds.

Net Financing Cash Flow

Net cash used in financing activities was $96.5 million during 2012 and $303.9 million during 2011, compared to net cash provided by financing activities of $137.7 million in 2010. Net cash used in financing activities during 2012 was lower than 2011, primarily due to the absence of the 2011 repayment of a bank term loan, the absence of the repurchase of long-term debt, lower payments on the credit facility, the absence of the settlement of the treasury rate lock, and lower repurchases of common stock. This was partially offset by lower draws on the credit facility, higher retirements of long-term debt, lower issuance of long-term debt, and higher dividends paid on common stock. Net cash used in financing activities during 2011 was higher than 2010, primarily due to higher repayments of short-term debt, the absence of 2010 short-term debt issuances, lower issuances of long-term debt, the repurchase of long-term debt, higher settlement of treasury rate lock, the repurchase of common stock, and higher dividends paid on common stock. This was partially offset by lower retirements of long-term debt and higher draws on the credit facility.

During 2012, Cleco used $78.8 million for dividend payments, $74.4 million for retirement of long-term bonds, $10.0 million for payments on the credit facility, and $8.0 million for the repurchase of common stock. This was partially offset by the issuance of $50.0 million of long-term debt and $25.0 million of draws on the credit facility.

During 2011, Cleco repaid a $150.0 million bank term loan and $112.1 million of long-term debt, consisting of $100.0

million of credit facility draws and $12.3 million of long-term bonds. Cleco repurchased $132.0 million of long-term debt, consisting of $100.0 million of GO Zone bonds and $32.0 million of solid waste disposal facility bonds, both of which were issued in 2008. Cleco also used $68.0 million for the payment of common stock dividends and $13.0 million for the repurchase of common stock. Cleco paid $18.6 million on the settlement of the $100.0 million extended treasury rate lock, which included an other-than-insignificant financing component. These payments were partially offset by the issuance of $100.0 million of long-term debt and $95.0 million in credit facility draws.

During 2010, Cleco received proceeds of $247.2 million for the issuance of long-term bonds and made $20.0 million of draws on the credit facility. Cleco also received net proceeds of $150.0 million for the issuance of a bank term loan, which was used to facilitate the Acadia Unit 1 transaction. These cash proceeds were partially offset by $120.9 million of repayments of retail notes and storm recovery bonds, $59.0 million of common stock dividends, and $100.0 million of payments on the credit facility.

Cleco Power Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities was $244.1 million during 2012, $251.8 million during 2011, and $172.5 million in 2010. Cash provided by operating activities during 2012 decreased $7.7 million from 2011, primarily due to the following items:


•	the absence of 2011 fuel oil inventory sales of $31.5 million,


•	higher vendor payments of $27.9 million,


•	higher deferred fuel costs of $12.9 million,


•	higher expenditures for other fuel inventories and related transportation of $12.4 million, and


•	lower customer deposits of $1.5 million.

These decreases were partially offset by:


•	lower pension plan contributions of $60.0 million,


•	lower payments for gas and power purchases of $11.5 million,


•	the absence of tax credits purchased in 2011 of $4.2 million, and


•	lower tax payments of $2.9 million.

Cash provided by operating activities during 2011 increased $79.3 million from 2010, primarily due to the following items:


•	absence of 2010 Madison 3 construction carrying costs, Acadia Unit 1 acquisition costs, rate case costs, and IRP/FRP costs of $47.2 million,


•	higher collection of receivables of $31.6 million,


•	fuel oil inventory sales of $31.5 million,


•	lower petroleum coke inventory purchases of $23.3 million due to the build-up of inventory in 2010,


•	lower payments to affiliates of $19.2 million,


•	lower natural gas purchases of $3.9 million due to the build-up of inventory in 2010, and


•	lower postretirement plan carrying costs of $2.4 million.

These were partially offset by:


•	higher pension plan contributions of $55.0 million,


•	higher coal inventory purchases of $16.7 million, and


•	higher vendor payments of $11.0 million.

Net Investing Cash Flow

Net cash used in investing activities was $203.6 million during 2012, $172.2 million during 2011, and $136.4 million in 2010. Net cash used in investing activities during 2012 was higher than 2011, primarily due to higher additions to property, plant, and equipment and purchases of restricted investments, partially offset by higher transfers of cash from restricted accounts and higher property, plant, and equipment grants received. Net cash used in investing activities during 2011 was higher than 2010, primarily due to higher additions to property, plant, and equipment.

During 2012, Cleco Power had additions to property, plant, and equipment, net of AFUDC of $232.2 million and purchases of restricted investments, net of premium and interest of $12.0 million. This was partially offset by $21.6 million of cash transferred from restricted accounts, primarily related to restricted investments and cash restricted for storm costs, and $16.6 million of grants received.

During 2011, Cleco Power had additions to property, plant, and equipment, net of AFUDC of $179.7. This was partially offset by the transfer of $5.2 million of cash from restricted accounts, primarily related to GO Zone bonds and cash restricted for storm costs.

During 2010, Cleco Power had additions to property, plant, and equipment, net of AFUDC of $138.5 million, primarily related to the Acadiana Load Pocket transmission project and the Teche Unit 4 Blackstart project. Cleco Power also used $14.4 million to repay a company-owned life insurance loan. These payments were partially offset by the transfer of $15.4 million of cash from restricted accounts related to GO Zone bonds.

Net Financing Cash Flow

Net cash used in financing activities was $84.6 million during 2012 and $197.0 million during 2011, compared to net cash provided by financing activities of $10.7 million in 2010. Net cash used in financing activities during 2012 was lower than 2011, primarily due to the absence of the repurchase of long-term debt, $72.0 million of lower distributions made to Cleco Corporation, the absence of payments on the credit facility, and the absence of settlement of the treasury rate lock. This was partially offset by higher repayments of long-term debt, the absence of draws on the credit facility, and lower issuance of long-term debt. Net cash used in financing activities during 2011 was higher than 2010, primarily due to lower issuances of long-term debt, the repurchase of long-term debt, higher payments on the credit facility, and higher payments to settle the treasury rate lock. These were partially offset by lower retirements of long-term debt, higher draws on the credit facility, and $20.0 million of lower distributions made to Cleco Corporation.

Capital Expenditures

Cleco allocates its capital expenditure budget among its major first-tier subsidiaries — Cleco Power and Midstream. Cleco Power capital expenditures relate primarily to assets that may be included in Cleco Power’s rate base and, if considered prudent by the LPSC, can be recovered from its customers.

Those assets also earn a rate of return authorized by the LPSC and are subject to the rate agreement. Such assets consist of improvements to Cleco Power’s distribution system, transmission system, and generating stations. Midstream’s capital expenditure activities pertain predominately to Coughlin. Cleco believes cash and cash equivalents on hand, together with cash generated from operations, borrowings from credit facilities, and the net proceeds of any issuances of equity or debt securities, will be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.

Cleco Power’s capital expenditures, excluding AFUDC, totaled $232.2 million in 2012, $179.7 million in 2011, and $138.5 million in 2010. In 2012, 2011, and 2010, 100% of Cleco Power’s capital expenditure requirements were funded internally. In 2013 and for the five-year period ending 2017, Cleco Power expects to be able to internally fund 100% of its capital expenditure requirements. All computations of internally funded capital expenditures exclude AFUDC.

Other subsidiaries had capital expenditures of $6.1 million, $17.8 million, and $155.9 million during the years ended December 31, 2012, 2011, and 2010, respectively. The expenditures during 2010 were primarily due to Cleco Corporation’s facilitation of the Acadia Unit 1 transaction. Capital expenditures for other subsidiaries in 2013 are estimated to total $8.0 million. For the five-year period ending 2017, estimated capital expenditures for other subsidiaries are expected to total $17.0 million.

Cleco’s estimated capital expenditures and debt maturities for 2013 and for the five-year period ending 2017 are presented in the following tables. All amounts exclude AFUDC.



Cleco
PROJECT (THOUSANDS)	2013		%		2013-2017		%
Other environmental	$	2,000	1	%	$	13,000	2	%
AMI	17,000		7	%	17,000		2	%
MATS	83,000		35	%	105,000		14	%
New business	27,000		11	%	142,000		20	%
General ⁽¹⁾	111,000		46	%	453,000		62	%
Total capital expenditures	$	240,000	100	%	$	730,000	100	%
Debt payments	89,000				229,000
Total capital expenditures and debt payments	$	329,000			$	959,000
⁽¹⁾Refers to the rehabilitation of older transmission, distribution, and generation assets at Cleco Power, plant maintenance at Coughlin, and hardware and software upgrades at Support Group.



Cleco Power
PROJECT (THOUSANDS)	2013		%		2013-2017		%
Other environmental	$	2,000	1	%	$	13,000	2	%
AMI	17,000		7	%	17,000		2	%
MATS	83,000		36	%	105,000		15	%
New business	27,000		12	%	142,000		20	%
General ⁽¹⁾	103,000		44	%	436,000		61	%
Total capital expenditures	$	232,000	100	%	$	713,000	100	%
Debt payments	89,000				204,000
Total capital expenditures and debt payments	$	321,000			$	917,000
⁽¹⁾ Refers to the rehabilitation of older transmission, distribution, and generation assets at Cleco Power.

For more information on the AMI project, see “— Regulatory and Other Matters — AMI Project.”

Other Cash Requirements

Cleco Power’s regulated operations and Midstream’s merchant power plant are Cleco’s primary sources of internally generated funds. These funds, along with the issuance of additional debt and equity in future years, will be used for general corporate purposes, capital expenditures, and repayment of corporate debt.

Shelf Registrations

On October 31, 2012, a registration statement (No. 333-184695) was declared effective by the SEC and registered the offer and sale of up to $500.0 million of debt and equity securities for Cleco Corporation. At December 31, 2012, this registration statement had remaining capacity allowing for the issuance of up to $500.0 million in debt and equity securities.

On October 31, 2012, a registration statement (No. 333-184694) was declared effective by the SEC and registered the offer and sale of up to $400.0 million of debt securities for Cleco Power. At December 31, 2012, this registration statement had remaining capacity allowing for the issuance of up to $400.0 million of debt securities.

Common Stock Repurchase Program

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. During the years ended December 31, 2012 and 2011, Cleco Corporation repurchased 200,000 shares and 400,000 shares of common stock, respectively.

Authorized Preferred Stock Redemption

Cleco Corporation’s 4.5% cumulative preferred stock not subject to mandatory redemption had an optional redemption price of $101 per share. In January 2011, Cleco Corporation’s Board of Directors authorized and approved the redemption of all outstanding shares of the 4.5% cumulative preferred stock not subject to mandatory redemption provided that no shares of such preferred stock were redeemed prior to the repayment in full and termination of the $150.0 million bank term loan that matured on August 19, 2011. During 2011, the $150.0 million bank term loan was repaid and 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.

Contractual Obligations and Other Commitments

Cleco, in the course of normal business activities, enters into a variety of contractual obligations. Some of these result in direct obligations that are reflected in Cleco’s Consolidated Balance Sheets while others are commitments, some firm and some based on uncertainties, that are not reflected in the consolidated financial statements. The obligations listed in the following table do not include amounts for ongoing needs for which no contractual obligation existed as of December 31, 2012, and represent only the projected future payments that Cleco was contractually obligated to make as of December 31, 2012.



							PAYMENTS DUE BY PERIOD
CONTRACTUAL OBLIGATIONS (THOUSANDS)	TOTAL		LESS THAN ONE YEAR		1-3 YEARS		3-5 YEARS		MORE THAN 5 YEARS
Cleco Corporation
Long-term debt obligations ⁽¹⁾	$	27,361	$	25,625	$	1,250	$	486	$	—
Operating lease obligations ⁽³⁾	14		9		5		—		—
Purchase obligations ⁽⁴⁾	61,406		27,490		33,366		537		13
Other long-term liabilities ⁽⁵⁾	14,237		1,573		5,726		2,043		4,895
Pension obligations ⁽⁶⁾	177,372		5,557		12,002		13,241		146,572
Total Cleco Corporation	$	280,390	$	60,254	$	52,349	$	16,307	$	151,480
Cleco Power
Long-term debt obligations ⁽¹⁾	$	2,701,632	$	169,039	$	235,053	$	166,367	$	2,131,173
Capital lease obligations ⁽²⁾	11,350		2,171		4,753		4,426		—
Operating lease obligations ⁽³⁾	53,978		9,333		19,886		21,002		3,757
Purchase obligations ⁽⁴⁾	552,671		253,120		212,477		86,825		249
Other long-term liabilities ⁽⁵⁾	202,501		14,543		32,613		38,653		116,692
Total Cleco Power	$	3,522,132	$	448,206	$	504,782	$	317,273	$	2,251,871
Midstream
Purchase obligations ⁽⁴⁾	$	3,198	$	1,398	$	1,200	$	600	$	—
Total Midstream	$	3,198	$	1,398	$	1,200	$	600	$	—
Total long-term debt obligations ⁽¹⁾	$	2,728,993	$	194,664	$	236,303	$	166,853	$	2,131,173
Total capital lease obligations ⁽²⁾	$	11,350	$	2,171	$	4,753	$	4,426	$	—
Total operating lease obligations ⁽³⁾	$	53,992	$	9,342	$	19,891	$	21,002	$	3,757
Total purchase obligations ⁽⁴⁾	$	617,275	$	282,008	$	247,043	$	87,962	$	262
Total other long-term liabilities ⁽⁵⁾	$	216,738	$	16,116	$	38,339	$	40,696	$	121,587
Total pension obligations ⁽⁶⁾	$	177,372	$	5,557	$	12,002	$	13,241	$	146,572
Total	$	3,805,720	$	509,858	$	558,331	$	334,180	$	2,403,351

Other Commitments

The obligations listed in the following table represent the projected future payments that Cleco may be obligated to make relative to uncertain tax positions as of December 31, 2012. For more information on Cleco’s uncertain tax positions, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 9 — Income Taxes — Uncertain Tax Positions.”



UNCERTAIN TAX POSITIONS (THOUSANDS)	AT DEC. 31, 2012
Tax liability	3,126
Interest	1,420
Total*	$	4,546
Cleco	4,546		⁽¹⁾
Cleco Power	3,606		⁽²⁾
Midstream	1,794		⁽³⁾
*Uncertain federal and state tax positions as of December 31, 2012, that will be settled at some future date with the IRS and Louisiana Department of Revenue. ⁽¹⁾ Includes interest of $1,420 ⁽²⁾ Includes interest of $3,358 ³⁾ Includes interest of ($1,085)

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 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.

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 on terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco’s 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 December 31, 2012, 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 DEC. 31, 2012
(THOUSANDS)	FACE AMOUNT		REDUCTIONS		NET 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.

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’s Consolidated Balance Sheets as of December 31, 2012, 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.

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. After the three-year period, a residual value of less than $0.1 million will remain. At December 31, 2012, Acadia had an indemnification liability of $0.4 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco’s Consolidated Balance Sheet. Acadia recognized income of $7.2 million for the year ended December 31, 2012, and $0.9 million for the year ended December 31, 2011, primarily due to the contractual expiration of the underlying indemnification. APH recognized no income for the year ended December 31, 2012, and $0.9 million income for the year ended December 31, 2011, primarily due to the contractual expiration of the underlying indemnification. For more information regarding this transaction, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

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 of $21.8 million, which represents the fair value of these indemnifications. 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 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. After the three-year period, a residual value of approximately $0.2 million will remain. At December 31, 2012, Acadia had an indemnification liability of $7.8 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco’s Consolidated Balance Sheet. Acadia recognized income of $14.0 million for the year ended December 31, 2012, and no income for the year ended December 31, 2011, due to the contractual expiration of the underlying indemnification. 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. For more information regarding this transaction, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

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 December 31, 2012, Cleco Power had a liability of $3.8 million related to the amended agreement. The maximum projected payment by Cleco Power under this obligation 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.

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.

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

2011-2014 time period. 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. Cleco Power issued its final RFP for biomass fuel in February 2012, and received all proposals by April 17, 2012. On August 3, 2012, Cleco Power filed a written report to the LPSC regarding co-firing biomass fuel in Madison Unit 3. Following its review of the results of Cleco Power's RFP and Cleco Power's written report, 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.

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. The NRG agreement provided 200 MW of capacity and energy from January 1, 2012, through April 30, 2012, while the Evangeline agreement provided 250 MW of capacity and energy beginning January 1, 2012, through April 30, 2012.

RFP for Contractual Resources Beginning in May 2012

In September 2011, Cleco Power issued a draft RFP for capacity and energy resources and conducted a technical and bidders conference on October 13, 2011. The final RFP seeking up to approximately 750 MW of capacity and energy for a three-or-five year term was published on October 21, 2011. In March 2012, Cleco Power received approval from the LPSC for a three-year power purchase agreement providing 730 MW of capacity and energy with Evangeline for a delivery term beginning May 1, 2012 and ending April 30, 2015. Because Cleco Power and Evangeline are affiliates, Cleco Power also received approval from FERC to make power sales between affiliates pursuant to Section 205 of the Federal Power Act.

2012 Long-Term RFP for Capacity and Energy Resources

In May 2012, Cleco Power issued a draft RFP seeking up to approximately 800 MW beginning May 2015 to meet long-term capacity and energy needs due to load growth and environmental regulations. Cleco Power conducted a technical and bidders conference in May 2012, in addition to a technical and bidders conference call on July 19, 2012, following the issuance of its final RFP on July 10, 2012. Cleco Power received proposals from potential suppliers in August 2012. On October 30, 2012, Cleco Power announced Evangeline as the winning bidder in the Cleco Power 2012 Long-Term RFP, subject to further due diligence, the completion of definitive agreements, and regulatory approvals from the LPSC and FERC. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. The transaction is expected to close as early as the fourth quarter of 2013, after completion of regulatory approvals.

CCN

In May 2006, the LPSC issued its order granting Cleco Power a CCN to construct, own, and operate Madison Unit 3. The LPSC approved a Madison Unit 3 post-certification monitoring plan that required, at least quarterly, reports addressing construction progress, expenditures, project financing, environmental compliance, and other related matters. As of December 31, 2011, Cleco Power was in compliance with this monitoring plan. The monitoring plan has remained in place since the unit began commercial operation on February 12, 2010. In February 2012, Cleco Power provided its final monitoring document to the LPSC. Cleco Power is effectively relieved of its monitoring plan requirements and no longer provide updates to the LPSC.

Environmental Matters

For information on environmental matters, see Part I, Item 1, “Business — Environmental Matters.”

Retail Rates of Cleco Power

Retail rates regulated by the LPSC accounted for approximately 89% and 93% of Cleco Power’s 2012 and 2011 revenue, respectively.

In August 2009, the LPSC opened a docket to study the promotion of energy efficiency by jurisdictional electric and natural gas utilities. At the December 12, 2012 Business and Executive Session, the LPSC adopted the energy efficiency rules issued for comment October 15, 2012, with modifications. The proposed rule is not expected to have a material impact on the results of operations, financial condition, and cash flows of Cleco Power.

Fuel Rates

Environmental Rates

the audit was approximately $11.3 million. In April 2012, the LPSC Staff’s consultant issued an audit report recommending no cost disallowance for the review period. There was no opposition from intervenors to the recommendations of the LPSC Staff’s consultant and the report was approved by the LPSC on July 18, 2012. Cleco Power has EAC filings for the years 2010 through 2012 that remain subject to audit.

Base Rates

The current amount of Cleco Power’s annual retail earnings is subject to the terms of an FRP established by the LPSC effective February 12, 2010. The 2010 FRP allows Cleco Power the opportunity to earn a target return on equity of 10.7%, including returning to retail customers 60.0% 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. Credits are typically included on customers’ bills the following summer, but the timing of the refunds is ultimately at the discretion of the LPSC. The capital structure assumes an equity ratio of 51.0%. The 2010 FRP included a mechanism that allowed for the recovery of revenue requirements related to Cleco Power’s acquisition of Acadia Unit 1, which was completed in February 2010. The 2010 FRP also includes a mechanism allowing for recovery of revenue requirements for the Acadiana Load Pocket transmission project, which was completed in December 2012, and incremental capacity costs above the level included in base rates. The 2010 FRP allows Cleco Power to propose additional capital projects to the LPSC during its initial four-year term. Cleco Power anticipates requesting an extension of its current FRP in a second quarter 2013 filing with the LPSC.

For information concerning amounts accrued and refunded by Cleco Power as a result of the FRP and information on the Staff’s FRP reviews, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 11 — Electric Customer Credits.”

Wholesale Rates of Cleco

Power Sales

Cleco’s wholesale electric power sales are regulated by FERC via cost- and market-based tariffs.

In April 2004, FERC issued an order revising the methodology to be used in assessing whether a jurisdictional electric utility has generation market power, requiring a utility to pass a screening test as a condition for securing and/or retaining approval to sell electricity in wholesale markets at market-based rates. An updated market power analysis is to be filed with FERC every three years or upon the occurrence of a change in status as defined by FERC regulation.

In January 2012, Cleco filed a Notice of Change of Status with FERC resulting from the termination of the Evangeline 2010 Tolling Agreement. In connection with this notice, Cleco included an analysis of Cleco’s generation market power. In June 2012, Cleco filed its triennial market power analysis with FERC. FERC has not yet issued any findings in connection with either filing. The power marketing entities may continue to charge market-based rates for wholesale power, pending review and acceptance by FERC.

Transmission Service

Cleco’s electric transmission rates are regulated by FERC via a cost-based, pro forma OATT, a FERC-approved document

outlining rates, charges, rules, and conditions under which a utility provides electric transmission service. The pro forma OATT was instituted by FERC in 1996 with the issuance of Order Nos. 888 and 889. These orders required FERC-regulated electric utilities to offer third parties access to transmission under terms and conditions comparable to the terms and conditions followed by the utilities for use of their own systems. The goal of these orders was to ensure that the provision of transmission service is reasonable and not unduly discriminatory or preferential. On March 29, 2012, Cleco Power filed a request with FERC for revisions to its OATT. The revisions were proposed to allow adoption of a formula rate methodology for transmission delivery and ancillary services provided by Cleco Power under the OATT and the existing bilateral Electric System Interconnection Agreements that preceded the OATT. The new formula rates will permit recovery of Cleco Power’s FERC-jurisdictional investments in transmission and other assets placed in service since the existing rates were established. On May 31, 2012, FERC issued an order accepting the rates for scheduling, system control and dispatch service, and the loss factors effective June 1, 2012. The remaining proposed rates were suspended for the maximum five-month statutory period and were effective November 1, 2012, subject to refund. On February 6, 2013, Cleco Power received notification that FERC had approved its settlement agreement filed on December 21, 2012. This settlement agreement allows for a return on equity of 10.5%, with an equity ratio of 53%. In accordance with the settlement, Cleco Power shall discount the charges produced by the formula rate by 10% until the earlier of December 31, 2014, or the date upon which Cleco commences operations under the MISO tariff.

On July 21, 2011, FERC issued Order No. 1000 that reforms the electric transmission planning and cost allocation requirements for public utility transmission providers. The rule builds on the reforms of Order No. 890 and corrects remaining deficiencies with respect to transmission planning processes and cost allocation methods. Cleco Power is currently reviewing the new requirements and business practices. Management is unable, at this time, to determine if this order will have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

On December 6, 2012, Cleco Power filed an application with the LPSC requesting a public interest determination to find in favor of the transfer of functional control of certain transmission assets to MISO. MISO operates a fully functioning RTO market with two major market processes: the Day-Ahead Energy and Operating Reserves Market and the Real-Time Energy and Operating Reserves Market. These markets use market-based mechanisms to manage transmission congestion across the MISO market area. The Day-Ahead Energy and Operating Reserve Market is a forward market that simultaneously clears energy and operating reserves on a co-optimized basis for each hour of the next operating day. Consumers and market participants submit schedules, load bids, and day-ahead wholesale offers for each hour of the following operating day. MISO then analyzes the offers and bids in light of projected transmission constraints and calculates the resulting day-ahead Locational Marginal Price (“LMP”) for each pricing node on the MISO system for each hour of the day. As part of this process, MISO determines market participants' obligations to supply or take energy, based on bids received. The vast majority of transactions in the MISO markets are cleared through the day-

ahead market; however, MISO also operates a real-time energy market to address deviations between day-ahead and real-time schedules. In its application, Cleco Power proposed to defer and collect its integration costs from jurisdictional customers through the FRP. Costs to integrate into MISO are estimated at $8.1 million; however, in its application, Cleco Power estimated yearly savings of $19.4 million by operating within MISO compared to operating independently outside of the regional market.

For more information about the risks associated with Cleco Power’s integration into MISO, see Part I, Item 1A, “Risk Factors — MISO.”

Market Restructuring

Wholesale Electric Markets

Regional Transmission Organization

In 1999, FERC issued Order No. 2000, which established a general framework for all transmission-owning entities in the nation to voluntarily place their transmission facilities under the control of an appropriate RTO.

In April 2004, Entergy filed at FERC to make potentially significant modifications to its transmission tariff. The modifications would incorporate an independent third-party entity, the ICT, into its transmission operations, with the ICT having access to pertinent information regarding the Entergy transmission system. After receiving approval from FERC and state commissions (including the LPSC), the SPP began a four-year trial as Entergy’s acting ICT on November 17, 2006.

In early 2009, the Arkansas Public Service Commission directed the SPP to perform a comprehensive Cost Benefit Analysis Study of full SPP membership by all the Entergy operating companies as compared to participation under the existing ICT services arrangement and full SPP membership by Entergy Arkansas as a standalone entity, compared to continuing under the existing ICT services arrangement. The study was completed on September 30, 2010.

Additional addendum studies were performed during 2011, which included all the Entergy operating companies joining the MISO RTO. Based on these addendum studies, Entergy has announced that MISO provides more overall savings for their customers than SPP.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Inc., and Entergy Texas, Inc. have made regulatory filings with their respective public service commissions indicating their intent to join MISO by January 1, 2014. As of December 31, 2012, all six of these Entergy companies have received conditional approval from their respective public service commissions.

On December 6, 2012, Cleco Power filed an application with the LPSC indicating Cleco’s intent to join MISO asking the commission to: find that transferring control of certain transmission assets to MISO is in the public interest; create an accounting order deferring costs related to Cleco Power’s transition into the MISO market; and expedited treatment. Cleco Power anticipates joining the MISO RTO by January 2014.

Electric Reliability Organization

The Energy Policy Act of 2005 added Section 215 to the Federal Power Act, which provides for a uniform system of mandatory, enforceable reliability standards. In 2006, FERC

named NERC as the ERO that will be required to develop and enforce the mandatory reliability standards.

In April 2010, the SPP RE conducted an audit of Cleco to determine Cleco’s compliance with the NERC Reliability Standard Requirements. Cleco submitted mitigation plans and evidence of remedial efforts in connection with the SPP’s findings from the April 2010 audit. In October 2010, Cleco and SPP agreed to a financial settlement totaling less than $0.1 million, which has been approved by NERC. Cleco’s next scheduled audit is expected to begin in November 2013.

For a discussion of risks associated with FERC’s regulation of Cleco Power’s wholesale electric business, see Part I, Item 1A, “Risk Factors — Reliability and Infrastructure Protection Standards Compliance.”

Retail Electric Markets

Currently, the LPSC does not provide exclusive service territories for electric utilities under its jurisdiction. Instead, retail service is obtained through a long-term nonexclusive franchise. The LPSC uses a “300-foot rule” for determining the supplier for new customers. The “300-foot rule” requires a customer to take service from the electric utility that is within 300 feet of the respective customer. If the customer is beyond 300 feet from any existing utility service, they may choose their electric supplier. The “300-foot rule” (Docket No. R-28955) is currently under review by the LPSC. Management is unable to predict the time of completion and cannot determine the impact any potential rulemaking may have on the results of operations, financial condition, and cash flows of Cleco Power. The application of the current rule has led to competition with neighboring utilities for retail customers at the borders of Cleco Power’s service areas. Such competition has led to complaints by competitors that Cleco Power has violated the 300-foot rule. Several complaints have been made by competitors who operate as rural electric cooperatives and, if the LPSC were to rule in favor of such competitors, Cleco Power may be fined. Management does not believe any such fines, if imposed, would have a material impact on Cleco Power’s financial condition. Cleco Power also competes in its service area with suppliers of alternative forms of energy, some of which may be less costly than electricity for certain applications. Cleco Power could experience some competition for electric sales to industrial customers in the form of cogeneration or from independent power producers.

For information on dual franchise attempts, see Part I, Item 1, “Business — Regulatory Matters, Industry Developments, and Franchises — Franchises.”

Lignite Deferral

Cleco Power operates a generating unit jointly owned with SWEPCO that uses lignite as its fuel source.

between Cleco Power, SWEPCO and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over approximately 11.5 years. The settlement also established a new benchmark utilizing the contract’s escalators to assure a minimum 2% savings to customers compared to the costs under the prior mining contract. Under the settlement, the benchmarking was scheduled to end after April 2011. Cleco Power and SWEPCO also agreed to commit to continued operation of the mining operation through 2026 as long as the operation of the mine was considered prudent. Cleco Power did not record any additional deferred fuel costs under the new benchmarking method.

In connection with its approval of the Oxbow Lignite Mine acquisition, in 2009 the LPSC agreed to discontinue benchmarking and the corresponding potential to defer future lignite mining costs while preserving the recovery of the legacy deferred fuel balance previously authorized. At December 31, 2012 and 2011, Cleco Power had $16.6 million and $19.1 million, respectively, in deferred costs remaining uncollected.

Acadiana Load Pocket Transmission 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. At December 31, 2012, Cleco Power had spent $123.7 million on the project. A return on and recovery of the costs associated with the completed portions of the Acadiana Load Pocket transmission project are included in base rates. The project was completed in December 2012.

AMI Project

In October 2009, Cleco Power received notification of its selection to receive a $20.0 million grant from the DOE to deploy advanced metering infrastructure technology for Cleco Power’s customers. Cleco Power applied to the DOE under a small grant process, which capped the grant award at $20.0 million. The DOE selected 100 smart-grid initiatives out of approximately 400 applications for funding under the smart-grid investment grant program. 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. In May 2010, Cleco Power accepted the terms of the $20.0 million grant from the DOE and the DOE assistance agreement was executed.

Implementing advanced metering technology includes installing smart meters with two-way communication capabilities along with implementing a territory-wide communication network and data management system. The primary initial benefit is savings gained through operational efficiencies. Another benefit is increased information about

customer usage, which will give Cleco Power better distribution system planning data, better response to customer usage questions, and faster detection and restoration of system outages. Future benefits could include providing customers with near real-time energy usage information and rate options. These benefits may also require other significant capital investments.

Cleco Power estimates the project will cost approximately $73.0 million, with the DOE grant providing $20.0 million toward the project and Cleco Power providing the remaining $53.0 million. In April 2010, Cleco Power received board approval for the project conditioned upon approval by the LPSC. Cleco Power filed an application with the LPSC in June 2010 and requested expedited approval of the project prior to the end of 2010. In November 2010, the LPSC requested that Cleco Power levelize the impact to customers’ bills by utilizing deferrals of initial net incremental costs in the early years, which would then reverse as net cost savings materialize later in the project cycle. The project was approved by the LPSC in February 2011. At December 31, 2012, Cleco Power had incurred $55.5 million in project costs, of which $20.0 million has been submitted to and reimbursed by the DOE. The project is expected to be completed in the third quarter of 2013.

Teche Unit 4 Blackstart Project

In January 2009, Cleco Power filed an application with the LPSC to improve its “blackstart” process by constructing a 33-MW gas turbine sited at the Teche Power Station, which has been designated as Teche Unit 4. This project allows Cleco Power to return its generating system to service more efficiently than was previously possible in the event of a total system shutdown, and can also be dispatched in peaking service to meet system load requirements. As part of the Teche Power Station, Teche Unit 4 is located in a region known as the Acadiana Load Pocket, an area that has experienced considerable growth in recent years. The new unit was placed into commercial operation in April 2011. The project was completed at a total cost of $29.6 million.

Franchises

For information on franchises, see Part I, Item 1, “Business — Regulatory Matters, Industry Developments, and Franchises — Franchises.”

Recent Authoritative Guidance

For a discussion of recent authoritative guidance, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 2 — Summary of Significant Accounting Policies — Recent Authoritative Guidance.”



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 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. When positions close, actual gains or losses are included in the fuel adjustment clause and reflected on customers’ bills as a component of the FAC.

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 Moody’s or Standard & Poor’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 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 6 — 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 variable-rate obligations is computed by assuming a 1% change in the current interest rate applicable to such debt.

At December 31, 2012, the carrying value of Cleco’s long-term fixed-rate debt was approximately $1.32 billion, with a fair market value of approximately $1.55 billion. The $234.5 million difference between the carrying value of the debt and the market value is driven by the spread between the stated rate of Cleco’s debt as compared to the current market yield for debt with similar risk profiles, maturities, and terms as Cleco’s debt. Fair value was determined using quoted market prices. Each 1% increase in the average interest rates would result in a corresponding decrease of approximately $135.1 million in the fair value of these instruments. If these instruments are held to maturity, no change in stated value will be realized.

At December 31, 2012, Cleco had no short-term variable rate debt outstanding.

At December 31, 2012, Cleco Corporation had $25.0 million borrowings outstanding under its $250.0 million credit facility at an interest rate of 1.71%. The borrowings under the credit facility are considered to be long-term as the credit facility expires in 2016. The borrowing costs under the facility are equal to one-month LIBOR plus 1.50% or ABR, plus facility fees of 0.25%. The existing borrowings had 30-day terms. The $25.0 million draws outstanding consisted of a $15.0 million draw and a $10.0 million draw. The $15.0 million draw matured and was renewed on January 17, 2013, and was subsequently repaid on February 4, 2013. The $10.0 million draw matured and was repaid on January 28, 2013. Each 1% increase in the interest rate applicable to such debt would have resulted in a decrease in Cleco’s pre-tax earnings of $0.1 million.

On November 14, 2011, Cleco Power entered into a forward starting interest rate swap contract in order to mitigate the interest rate exposure on coupon payments related to a $50.0 million fixed-rate forecasted debt issuance. The forward starting interest rate swap has a spot 30-year all-in swap rate of 3.05%, notional amount of $50.0 million, with the pricing date of May 14, 2013, or the issuance of the notes, whichever is earlier. The forward starting interest rate swap meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging. The fair market value of the forward starting interest rate swap is the net of the present value of the fixed payments to be paid by Cleco Power and the present value of the three-month LIBOR payments to be received by Cleco Power. Cleco Power recognized $1.2 million unrealized mark-to-market gains and $3.3 million unrealized mark-to-market losses in other comprehensive income for the years ended December 31, 2012 and 2011, respectively. The fair market value of $2.6 million and $3.3 million for the forward starting interest rate swap was recorded on Cleco and Cleco Power’s Consolidated Balance Sheets as

an interest rate risk management liability as of December 31, 2012 and December 31, 2011, respectively. There was no impact to earnings due to ineffectiveness for the year ended December 31, 2011. There were $0.5 million of deferred losses due to ineffectiveness for the year ended December 31, 2012. For every 0.01% change in the three-month LIBOR forward curve, the value of the forward starting interest rate swap changes by approximately $0.1 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, 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 certain levels of hedging percentages to help mitigate 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 FAC in the month the physical contract settles. Based on market prices at December 31, 2012, there was no net mark-to-market impact related to open natural gas positions and a loss of $5.3 million at December 31, 2011. There were no open natural gas positions at December 31, 2012. Deferred losses relating to closed natural gas positions at December 31, 2011, totaled $1.2 million.

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 2012, as well as the VaR at December 31, 2012 and 2011, are summarized in the following table.



	FOR THE YEAR ENDED DEC. 31, 2012						AT DEC. 31,
(THOUSANDS)	HIGH		LOW		AVERAGE		2012		2011
Fuel cost hedges	$	382.0	$	—	$	125.1	$	—	$	196.1



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. For details, see Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 6 — Debt.” 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.

As of December 31, 2012, the carrying value of Cleco Power’s long-term fixed-rate debt was approximately $1.32 billion, with a fair market value of approximately $1.55 billion. The $234.5 million difference between the carrying value of the debt and the market value of such debt is driven by the spread between the stated rate of Cleco Power’s debt as compared to the current market yield for debt with similar risk profiles,

maturities, and terms as Cleco Power’s debt. Fair value was determined using quoted market prices. Each 1% increase in the average interest rates applicable to such debt would result in a corresponding decrease of approximately $135.1 million in the fair values of these instruments. If these instruments are held to maturity, no change in stated value will be realized.

Cleco Power had no short- or long-term variable-rate debt as of December 31, 2012. At December 31, 2012, Cleco Power had no borrowings outstanding under its $300.0 million credit facility.

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.

To the Shareholders and Board of

Directors of Cleco Corporation:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Corporation (the "Company") and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 19, 2013



Consolidated Statements of Income
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)	2012			2011			2010
Operating revenue
Electric operations	$	944,169		$	1,051,956		$	1,086,102
Tolling operations	—			19,004			26,067
Other operations	50,158			52,962			44,529
Affiliate revenue	—			202			1,564
Gross operating revenue	994,327			1,124,124			1,158,262
Electric customer credits	(630		)	(6,811		)	(9,596		)
Operating revenue, net	993,697			1,117,313			1,148,666
Operating expenses
Fuel used for electric generation	280,553			383,254			363,550
Power purchased for utility customers	53,134			70,462			144,152
Other operations	120,898			123,849			117,229
Maintenance	86,488			82,076			81,228
Depreciation	132,407			122,578			114,584
Taxes other than income taxes	38,515			36,356			34,626
Loss on sale of assets	51			491			338
Total operating expenses	712,046			819,066			855,707
Operating income	281,651			298,247			292,959
Interest income	346			891			409
Allowance for other funds used during construction	6,711			4,947			12,413
Equity income from investees, before tax	—			62,050			38,849
Gain on toll settlement	—			—			148,402
Other income	29,117			8,914			5,242
Other expense	(4,694		)	(5,646		)	(4,609		)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net	86,448			72,445			100,339
Allowance for borrowed funds used during construction	(2,292		)	(1,787		)	(4,563		)
Total interest charges	84,156			70,658			95,776
Income before income taxes	228,975			298,745			397,889
Federal and state income tax expense	65,327			102,897			142,498
Net income	163,648			195,848			255,391
Preferred dividends requirements	—			26			46
Preferred stock redemption costs	—			112			—
Net income applicable to common stock	$	163,648		$	195,710		$	255,345

Average number of basic common shares outstanding	60,370,588			60,488,740			60,431,142
Average number of diluted common shares outstanding	60,628,129			60,833,564			60,754,589
Basic earnings per share
Net income applicable to common stock	$	2.71		$	3.24		$	4.23
Diluted earnings per share
Net income applicable to common stock	$	2.70		$	3.22		$	4.20
Cash dividends paid per share of common stock	$	1.30		$	1.1225		$	0.975
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Balance Sheets
	AT DEC. 31,
(THOUSANDS)	2012			2011
Assets
Current assets
Cash and cash equivalents	$	31,020		$	93,576
Restricted cash and cash equivalents	8,781			8,761
Customer accounts receivable (less allowance for doubtful accounts of $1,105 in 2012 and $1,128 in 2011)	39,293			37,813
Other accounts receivable (less allowance for doubtful accounts of $0 in 2012 and $8 in 2011)	37,741			42,051
Taxes receivable, net	34,612			44,584
Unbilled revenue	28,662			30,129
Fuel inventory, at average cost	46,867			41,845
Material and supplies inventory, at average cost	58,232			53,714
Accumulated deferred federal and state income taxes, net	79,353			29,249
Accumulated deferred fuel	7,833			2,136
Cash surrender value of company-/trust-owned life insurance policies	57,346			51,073
Prepayments	5,951			5,384
Regulatory assets – other	11,095			13,028
Other current assets	552			3,442
Total current assets	447,338			456,785
Property, plant and equipment
Property, plant, and equipment	4,140,194			4,023,655
Accumulated depreciation	(1,311,273		)	(1,230,783		)
Net property, plant, and equipment	2,828,921			2,792,872
Construction work in progress	180,540			101,027
Total property, plant and equipment, net	3,009,461			2,893,899
Equity investment in investees	14,540			14,540
Prepayments	4,261			4,770
Restricted cash and cash equivalents, less current portion	5,440			27,067
Restricted investments	10,852			—
Regulatory assets and liabilities – deferred taxes, net	210,445			214,421
Regulatory assets – other	289,570			269,444
Net investment in direct financing lease	13,542			13,633
Intangible asset	120,545			133,595
Other deferred charges	21,355			22,048
Total assets	$	4,147,349		$	4,050,202
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Balance Sheets (Continued)
	AT DEC. 31,
(THOUSANDS)	2012			2011
Liabilities and shareholders’ equity
Liabilities
Current liabilities
Long-term debt due within one year	$	91,140		$	26,099
Accounts payable	102,695			127,467
Customer deposits	45,553			43,091
Provision for rate refund	4,165			7,323
Interest accrued	12,957			22,642
Energy risk management liabilities, net	—			5,336
Interest rate risk management liability	2,627			3,330
Regulatory liabilities - other	8,255			33,019
Deferred compensation	9,626			8,302
Uncertain tax positions	686			27,239
Other current liabilities	16,926			17,154
Total current liabilities	294,630			321,002
Deferred credits
Accumulated deferred federal and state income taxes, net	762,992			649,926
Accumulated deferred investment tax credits	6,252			7,432
Postretirement benefit obligations	186,746			133,274
Regulatory liabilities – other	—			7,303
Restricted storm reserve	16,285			24,880
Uncertain tax positions	2,184			23,494
Tax credit fund investment, net	78,840			61,507
Contingent sale obligations	8,150			29,357
Other deferred credits	34,799			35,114
Total deferred credits	1,096,248			972,287
Long-term debt, net	1,257,258			1,337,056
Total liabilities	2,648,136			2,630,345
Commitments and Contingencies (Note 14)
Shareholders’ equity
Common shareholders’ equity
Common stock, $1 par value, authorized 100,000,000 shares, issued 60,961,570 and 60,702,342 shares and outstanding 60,355,545 and 60,291,939 shares at December 31, 2012 and 2011, respectively	60,962			60,702
Premium on common stock	416,619			409,904
Retained earnings	1,075,074			990,605
Treasury stock, at cost, 606,025 and 410,403 shares at December 31, 2012 and 2011, respectively	(21,072		)	(13,215		)
Accumulated other comprehensive loss	(32,370		)	(28,139		)
Total shareholders’ equity	1,499,213			1,419,857
Total liabilities and shareholders’ equity	$	4,147,349		$	4,050,202
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Statements of Cash Flows
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Operating activities
Net income	$	163,648		$	195,848		$	255,391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	162,430			160,765			168,363
Gain on forgiveness of debt	—			—			(129,870		)
Return on equity investment in investees	—			58,665			—
Income from equity investments	—			(62,050		)	(38,849		)
Unearned compensation expense	6,180			7,416			5,587
Allowance for other funds used during construction	(6,711		)	(4,947		)	(12,413		)
Net deferred income taxes	19,930			23,618			54,873
Deferred fuel costs	(12,222		)	653			21,086
Cash surrender value of company-/trust-owned life insurance	(3,300		)	1,687			(2,759		)
Changes in assets and liabilities:
Accounts receivable	(11,543		)	(19,146		)	(12,503		)
Unbilled revenue	1,468			14,520			(22,675		)
Fuel, materials and supplies inventory	(9,539		)	35,442			(7,465		)
Prepayments	(59		)	1,520			(2,316		)
Accounts payable	(23,016		)	(3,618		)	8,140
Customer deposits	11,167			12,693			12,313
Long-term receivable	—			—			27,976
Postretirement benefit obligations	7,485			(55,529		)	2,975
Regulatory assets and liabilities, net	(31,043		)	(43,131		)	(88,333		)
Contingent sale obligations	—			10,900			4,714
Other deferred accounts	(15,695		)	4,305			(114		)
Taxes accrued	9,786			5,171			(34,266		)
Interest accrued	(6,676		)	(38,103		)	2,466
Energy risk management assets and liabilities, net	38			4,646			7,885
Other operating	777			(1,264		)	(3,307		)
Net cash provided by operating activities	263,105			310,061			216,899
Investing activities
Additions to property, plant, and equipment	(245,033		)	(202,405		)	(306,883		)
Allowance for other funds used during construction	6,711			4,947			12,413
Property, plant, and equipment grants	16,647			2,788			—
Insurance reimbursement for property loss	5,454			4,482			—
Return of equity investment in investees	—			89,654			—
Equity investment in investees	—			(1,460		)	(8,700		)
Return of equity investment in tax credit fund	37,652			33,430			—
Contributions to tax credit fund	(59,645		)	(43,921		)	(35,871		)
Repayment of company-owned life insurance loan	—			—			(14,355		)
Transfer of cash from restricted accounts	21,607			5,220			45,535
Purchase of restricted investments	(11,966		)	—			—
Sale of restricted investments	1,348			—			—
Other investing	(1,939		)	3,549			(770		)
Net cash used in investing activities	(229,164		)	(103,716		)	(308,631		)
(Continued on next page)



Consolidated Statements of Cash Flows (Continued)
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Financing activities
Issuance of short-term debt	—			—			150,000
Retirement of short-term debt	—			(150,000		)	—
Draws on credit facility	25,000			95,000			20,000
Payments on credit facility	(10,000		)	(100,000		)	(100,000		)
Issuance of long-term debt	50,000			100,000			247,245
Retirement of long-term debt	(74,368		)	(12,269		)	(120,867		)
Repurchase of long-term debt	—			(132,000		)	—
Repurchase of common stock	(8,007		)	(13,009		)	—
Settlement of treasury rate lock	—			(18,636		)	5,675
Dividends paid on common stock	(78,844		)	(68,023		)	(58,988		)
Other financing	(278		)	(4,960		)	(5,398		)
Net cash (used in) provided by financing activities	(96,497		)	(303,897		)	137,667
Net (decrease) increase in cash and cash equivalents	(62,556		)	(97,552		)	45,935
Cash and cash equivalents at beginning of period	93,576			191,128			145,193
Cash and cash equivalents at end of period	$	31,020		$	93,576		$	191,128
Supplementary cash flow information
Interest paid (net of amount capitalized)	$	80,823		$	87,359		$	90,773
Interest paid on treasury rate lock settlement	$	—		$	8,128		$	—
Income taxes (refunded) paid, net	$	(624	)	$	46,636		$	75,498
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$	16,102		$	17,525		$	6,032
Issuance of common stock – ESPP	$	340		$	328		$	299
Non-cash additions to property, plant, and equipment	$	21,559		$	7,824		$	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 consolidated financial statements.



Consolidated Statements of Changes in Common Shareholders’ Equity
	COMMON STOCK			PREMIUM ON COMMON STOCK		RETAINED EARNINGS			TREASURY STOCK					ACCUMULATED OTHER COMPREHENSIVE LOSS			TOTAL COMMON EQUITY
(THOUSANDS, EXCEPT SHARE AMOUNTS)	SHARES	AMOUNT		PREMIUM ON COMMON STOCK		RETAINED EARNINGS			SHARES		COST			ACCUMULATED OTHER COMPREHENSIVE LOSS			TOTAL COMMON EQUITY
Balances, Dec. 31, 2009	60,277,462	$	60,277	$	399,148	$	667,220		(18,094	)	$	(311	)	$	(11,291	)	$	1,115,043
Common stock issued for compensatory plans	262,162	263		6,129		—			—		—			—			6,392
Issuance of treasury stock	—	—		36		—			4,596		37			—			73
Dividend requirements, preferred stock, net	—	—		—		(46		)	—		—			—			(46		)
Dividends on common stock, $0.975 per share	—	—		—		(59,328		)	—		—			—			(59,328		)
Net income	—	—		—		255,391			—		—			—			255,391
Other comprehensive loss, net of tax	—	—		—		—			—		—			(347		)	(347		)
Balances, Dec. 31, 2010	60,539,624	$	60,540	$	405,313	$	863,237		(13,498	)	$	(274	)	$	(11,638	)	$	1,317,178
Common stock issued for compensatory plans	162,718	162		4,523		—			—		—			—			4,685
Issuance of treasury stock	—	—		68		—			3,095		68			—			136
Repurchase of treasury stock	—	—		—		—			(400,000	)	(13,009		)	—			(13,009		)
Dividend requirements, preferred stock, net	—	—		—		(26		)	—		—			—			(26		)
Stock redemption costs, preferred stock, net	—	—		—		(112		)	—		—			—			(112		)
Dividends on common stock, $1.1225 per share	—	—		—		(68,342		)	—		—			—			(68,342		)
Net income	—	—		—		195,848			—		—			—			195,848
Other comprehensive loss, net of tax	—	—		—		—			—		—			(16,501		)	(16,501		)
Balances, Dec. 31, 2011	60,702,342	$	60,702	$	409,904	$	990,605		(410,403	)	$	(13,215	)	$	(28,139	)	$	1,419,857
Common stock issued for compensatory plans	259,228	260		6,701		—			—		—			—			6,961
Issuance of treasury stock	—	—		14		—			4,378		150			—			164
Repurchase of treasury stock	—	—		—		—			(200,000	)	(8,007		)	—			(8,007		)
Dividends on common stock, $1.30 per share	—	—		—		(79,179		)	—		—			—			(79,179		)
Net income	—	—		—		163,648			—		—			—			163,648
Other comprehensive loss, net of tax	—	—		—		—			—		—			(4,231		)	(4,231		)
Balances, Dec. 31, 2012	60,961,570	$	60,962	$	416,619	$	1,075,074		(606,025	)	$	(21,072	)	$	(32,370	)	$	1,499,213
The accompanying notes are an integral part of the consolidated financial statements.

To the Member and Board of

Managers of Cleco Power LLC:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Power LLC (the "Company") and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 19, 2013



Consolidated Statements of Income
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Operating revenue
Electric operations	$	944,169		$	1,051,956		$	1,086,102
Other operations	48,156			50,948			42,578
Affiliate revenue	1,372			1,389			1,371
Gross operating revenue	993,697			1,104,293			1,130,051
Electric customer credits	(630		)	(6,811		)	(9,596		)
Operating revenue, net	993,067			1,097,482			1,120,455
Operating expenses
Fuel used for electric generation	280,249			383,254			363,550
Power purchased for utility customers	78,683			70,462			144,152
Other operations	115,072			116,988			109,678
Maintenance	72,386			74,603			72,048
Depreciation	125,486			115,634			107,966
Taxes other than income taxes	33,999			32,157			32,744
(Gain) loss on sale of assets	(2		)	(9		)	47
Total operating expenses	705,873			793,089			830,185
Operating income	287,194			304,393			290,270
Interest income	333			630			379
Allowance for other funds used during construction	6,711			4,947			12,413
Other income	5,847			3,163			2,007
Other expense	(4,602		)	(3,799		)	(3,826		)
Interest charges
Interest charges, including amortization of debt expense, premium, and discount, net	82,794			98,877			83,294
Allowance for borrowed funds used during construction	(2,292		)	(1,787		)	(4,563		)
Total interest charges	80,502			97,090			78,731
Income before income taxes	214,981			212,244			222,512
Federal and state income taxes	68,133			69,409			75,107
Net income	$	146,848		$	142,835		$	147,405
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Balance Sheets
	AT DEC. 31,
(THOUSANDS)	2012			2011
Assets
Utility plant and equipment
Property, plant, and equipment	$	3,871,940		$	3,759,541
Accumulated depreciation	(1,227,078		)	(1,153,004		)
Net property, plant, and equipment	2,644,862			2,606,537
Construction work in progress	176,584			97,595
Total utility plant, net	2,821,446			2,704,132
Current assets
Cash and cash equivalents	23,368			67,458
Restricted cash and cash equivalents	8,781			8,761
Customer accounts receivable (less allowance for doubtful accounts of $1,105 in 2012 and $1,128 in 2011)	39,293			37,813
Accounts receivable – affiliate	2,991			2,405
Other accounts receivable (less allowance for doubtful accounts of $0 in 2012 and $8 in 2011)	37,562			35,618
Taxes receivable, net	—			3,197
Unbilled revenue	28,662			30,129
Fuel inventory, at average cost	46,867			41,845
Material and supplies inventory, at average cost	55,472			51,132
Accumulated deferred federal and state income taxes, net	87,286			19,829
Accumulated deferred fuel	7,833			2,136
Cash surrender value of company-owned life insurance policies	20,842			20,433
Prepayments	4,415			4,155
Regulatory assets – other	11,095			13,028
Other current assets	371			375
Total current assets	374,838			338,314
Equity investment in investee	14,532			14,532
Prepayments	4,261			4,770
Restricted cash and cash equivalents, less current portion	5,343			26,970
Restricted investments	10,852			—
Regulatory assets and liabilities – deferred taxes, net	210,445			214,421
Regulatory assets – other	289,570			269,444
Intangible asset	120,545			133,595
Other deferred charges	19,897			20,293
Total assets	$	3,871,729		$	3,726,471
(Continued on next page)



Consolidated Statements of Cash Flows
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Operating activities
Net income	$	146,848		$	142,835		$	147,405
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	137,053			127,109			119,940
Unearned compensation expense	1,587			1,796			1,846
Allowance for other funds used during construction	(6,711		)	(4,947		)	(12,413		)
Net deferred income taxes	57,364			45,608			34,555
Deferred fuel costs	(12,222		)	653			21,086
Cash surrender value of company-owned life insurance	(409		)	(383		)	(345		)
Changes in assets and liabilities:
Accounts receivable	(12,290		)	(18,206		)	(12,608		)
Unbilled revenue	1,468			14,520			(22,675		)
Fuel, materials and supplies inventory	(9,361		)	35,673			(7,202		)
Prepayments	249			1,294			(2,016		)
Accounts payable	(22,874		)	(4,498		)	8,907
Accounts and notes payable, affiliate	(122		)	600			(18,598		)
Customer deposits	11,167			12,693			12,313
Postretirement benefit obligations	5,947			(57,531		)	647
Regulatory assets and liabilities, net	(31,043		)	(43,131		)	(88,333		)
Other deferred accounts	(19,989		)	(2,399		)	(10,009		)
Taxes accrued	4,503			926			(7,561		)
Interest accrued	(5,431		)	(5,609		)	1,594
Energy risk management assets and liabilities, net	38			4,646			7,885
Other operating	(1,672		)	109			(1,933		)
Net cash provided by operating activities	244,100			251,758			172,485
Investing activities
Additions to property, plant, and equipment	(238,943		)	(184,615		)	(150,937		)
Allowance for other funds used during construction	6,711			4,947			12,413
Property, plant, and equipment grants	16,647			2,788			—
Equity investment in investees	—			(1,460		)	(200		)
Repayment of company-owned life insurance loan	—			—			(14,355		)
Transfer of cash from restricted accounts	21,607			5,220			15,404
Purchase of restricted investments	(11,966		)	—			—
Sale of restricted investments	1,348			—			—
Other investing	1,039			886			1,277
Net cash used in investing activities	(203,557		)	(172,234		)	(136,398		)
(Continued on next page)



Note 1 — The Company

General

Cleco Corporation is a holding company composed of the following:

•

Cleco Power, a regulated electric utility subsidiary, which owns 9 generating units with a total nameplate capacity of 2,565 MW and serves approximately 283,000 customers in Louisiana through its retail business and 10 communities across Louisiana and Mississippi through wholesale power contracts. Cleco Power also owns a 50% interest in an entity that owns lignite reserves. Cleco Power owns all of the outstanding membership interests in Cleco Katrina/Rita, a special purpose entity, that is consolidated with Cleco Power in its financial statements.


•	Midstream is a wholesale energy subsidiary regulated by FERC which owns Evangeline (which owns and operates Coughlin).


•	Cleco Corporation’s other operations consist of a holding company, two transmission interconnection facility subsidiaries, a shared services subsidiary, and an investment subsidiary.



Note 2 — Summary of Significant Accounting Policies

Use of Estimates

of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Principles of Consolidation

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

Reclassifications

Certain reclassifications have been made to the 2010 and 2011 financial statements to conform them to the presentation used in the 2012 financial statements. These reclassifications had no effect on Cleco Corporation’s net income applicable to common stock or total common shareholders’ equity or Cleco Power’s net income or total member’s equity.

During 2012, the Registrants began presenting the LPSC allowable portion of the amortization of the plant acquisition adjustment related to Acadia Unit 1 as depreciation expense on the Registrants’ Consolidated Statements of Income. Previously, this amortization was presented as other expense. The Registrants have reclassified prior year amounts to conform to this presentation. This change increased depreciation and decreased other expenses by $2.8 million and $2.4 million for the years ended December 31, 2011 and 2010, respectively.

Also during 2012, the Registrants determined that an error existed in the statement of cash flows presentation of contributions received in aid of construction, specifically the impact that the accounting for these contributions had on the presentation of cash flows related to the additions of property, plant, and equipment. This caused errors between the operating activities section and investing activities section for prior periods, including 2010 and 2011. Cleco Corporation and Cleco Power’s Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2011, were adjusted in the Registrants’ Combined Quarterly Report on Form 10-Q



Cleco
	FOR THE YEAR ENDED
				2010						2011
(THOUSANDS)	AS REPORTED			AS ADJUSTED			AS REPORTED			AS ADJUSTED
Accounts receivable	$	(16,156	)	$	(12,503	)	$	(15,798	)	$	(19,146	)
Other deferred accounts	$	1,813		$	(114	)	$	(1,084	)	$	4,305
Net cash provided by operating activities	$	215,173	*	$	216,899		$	308,020		$	310,061
Additions to property, plant, and equipment	$	(305,157	)*	$	(306,883	)	$	(200,364	)**	$	(202,405	)
Net cash used in investing activities	$	(306,905	)*	$	(308,631	)	$	(101,675	)	$	(103,716	)
Net increase in cash and cash equivalents	$	45,935		$	45,935		$	(97,552	)	$	(97,552	)
Cash and cash equivalents at the beginning of the period	$	145,193		$	145,193		$	191,128		$	191,128
Cash and cash equivalents at the end of the period	$	191,128		$	191,128		$	93,576		$	93,576
* These amounts were previously revised in the Registrants’ Combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011.
**These amounts differ with the amounts previously reported in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2011, due to Insurance reimbursement for property loss being shown separately from Additions to property, plant, and equipment in order to conform to the presentation used in the 2012 financial statements.



Cleco Power
	FOR THE YEAR ENDED
				2010						2011
(THOUSANDS)	AS REPORTED			AS ADJUSTED			AS REPORTED			AS ADJUSTED
Accounts receivable	$	(16,261	)	$	(12,608	)	$	(14,858	)	$	(18,206	)
Other deferred accounts	$	(8,082	)	$	(10,009	)	$	(7,788	)	$	(2,399	)
Net cash provided by operating activities	$	170,759	*	$	172,485		$	249,717		$	251,758
Additions to property, plant, and equipment	$	(149,211	)*	$	(150,937	)	$	(182,574	)	$	(184,615	)
Net cash used in investing activities	$	(134,672	)*	$	(136,398	)	$	(170,193	)	$	(172,234	)
Net increase in cash and cash equivalents	$	46,799		$	46,799		$	(117,454	)	$	(117,454	)
Cash and cash equivalents at the beginning of the period	$	138,113		$	138,113		$	184,912		$	184,912
Cash and cash equivalents at the end of the period	$	184,912		$	184,912		$	67,458		$	67,458
* These amounts were previously revised in the Registrants’ Combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011.

Statements of Cash Flows

Cleco Corporation and Cleco Power’s Consolidated Statements of Cash Flows are prepared using the indirect method described in the authoritative guidance for the presentation of the statement of cash flows. This method requires that net income be adjusted to remove the effects of all deferrals and accruals of operating cash receipts and payments and the effects of all investing and financing cash flow items. Derivatives meeting the definition of an accounting hedge are classified in the same category as the item being hedged.

Regulation

Cleco Power maintains its accounts in accordance with the Uniform System of Accounts prescribed for electric utilities by FERC, as adopted by the LPSC. Cleco Power’s retail rates are regulated by the LPSC, and its rates for transmission services and wholesale power sales are regulated by FERC. Cleco Power follows the authoritative guidelines for industry 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.

Pursuant to this authoritative guidance, Cleco Power has recorded regulatory assets and liabilities. For more information

regarding the regulatory assets and liabilities recorded by Cleco Power, see Note 3 — “Regulatory Assets and Liabilities.”

Any future plan adopted by the LPSC for purposes of transitioning utilities from LPSC regulation to retail competition may affect the regulatory assets and liabilities recorded by Cleco Power if the criteria for the application of the authoritative guidelines for industry regulated operations cannot continue to be met. At this time, Cleco cannot predict whether any legislation or regulation affecting Cleco Power will be enacted or adopted and, if enacted, what form such legislation or regulation may take.

Asset Retirement Obligation

Cleco Power has recorded asset retirement obligations (liabilities) in accordance with the authoritative guidance. This authoritative guidance requires an entity to record an ARO when there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel to incur costs to remove an asset when the asset is retired. These guidelines also require an ARO which is conditional on a future event to be recorded even if the event has not yet occurred.

At the point the liability for asset retirement is incurred, the authoritative guidance requires capitalization of the costs to the related property, plant, and equipment asset. For AROs

existing at the time of adoption, the statement requires capitalization of costs at the level that existed at the point of incurring the liability. These capitalized costs are depreciated over the same period as the related property asset. Cleco Power also defers the current depreciation of the asset retirement cost as a regulatory asset.

Under the authoritative guidance, the initial ARO liability recorded is accreted to its present value each accounting period. Cleco Power defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers. For more information on Cleco Power’s AROs, see Note 3 — “Regulatory Assets and Liabilities — Asset Removal Costs.”

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. For information on jointly owned assets, see Note 4 — “Jointly Owned Generation Units.”

Cleco’s cost of improvements to property, plant, and equipment is capitalized. Costs associated with repairs and major maintenance projects are expensed as incurred. Cleco capitalizes the cost to purchase or develop software for internal use. The amounts of unamortized computer software costs at December 31, 2012 and 2011 were $5.3 million and $3.3 million, respectively. Amortization of capitalized computer software costs charged to expense for the years ending December 31, 2012, 2011, and 2010 was $1.2 million, $1.5 million, and $1.7 million, respectively.

Upon retirement or disposition, the cost of Cleco’s depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. For Cleco’s other depreciable assets, upon disposition or retirement, the difference between the net book value of the property and any proceeds received for the property is recorded as a gain or loss on asset disposition on Cleco’s Consolidated Statements of Income. Any cost incurred to remove the asset is charged to expense. Annual depreciation provisions expressed as a percentage of average depreciable property for Cleco Power for 2012, 2011, and 2010 were 2.68%, 2.80%, and 2.55%, respectively.

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



	YEARS
Utility plant	5-58
Other	5-44

Property, plant, and equipment consist of:



	AT DEC. 31,
(THOUSANDS)	2012			2011
Regulated utility plants	$	3,871,940		$	3,759,541
Other	268,254			264,114
Total property, plant, and equipment	4,140,194			4,023,655
Accumulated depreciation	(1,311,273		)	(1,230,783		)
Net property, plant, and equipment	$	2,828,921		$	2,792,872

During 2012, Cleco’s investment in regulated utility plants increased primarily due to the Acadiana Load Pocket transmission project.

Cleco Power’s property, plant, and equipment includes plant acquisition adjustments related to the acquisition of Acadia Unit 1 in 2010 and Teche in 1997. Accumulated amortization associated with the plant acquisition adjustments are reported in accumulated depreciation on Cleco Power’s balance sheet. For more information on the Acadia Unit 1 transaction, see Note 18 — “Acadia Transactions — Acadia Unit 1.” The plant acquisition adjustments and accumulated amortization reported in property, plant, and equipment and accumulated depreciation on Cleco Power’s balance sheet at December 31, 2012 and 2011, are shown in the following table.



	AT DEC. 31,
(THOUSANDS)	2012		2011
Acadia Unit 1
Plant acquisition adjustment	$	95,578	$	95,578
Less: accumulated amortization	9,018		5,836
Net plant acquisition adjustment	$	86,560	$	89,742
Teche
Plant acquisition adjustment	$	5,359	$	5,359
Less: accumulated amortization	3,979		3,724
Net plant acquisition adjustment	$	1,380	$	1,635

Deferred Project Costs

Cleco Power defers costs related to the initial stage of a construction project during which time the feasibility of the construction of property, plant, and equipment is being investigated. Cleco Power had spent approximately $1.2 million as of December 31, 2012, for various resource planning projects. The amount spent for these projects as of December 31, 2011, was also approximately $1.2 million. These projects are still in the initial stages of development and as a result are classified as other deferred charges on Cleco’s and Cleco Power’s Consolidated Balance Sheets.

Inventories

Fuel inventories consist of petroleum coke, coal, lignite, and natural gas used to generate electricity.

Materials and supplies inventory consists of transmission and distribution line construction and repair materials. It also consists of generating station and transmission and distribution substation repair materials.

Both fuel and materials and supplies inventories are stated at average cost and are issued from inventory using the average cost of existing inventory. The amount of storeroom operating expenses allocated to inventory for the years ended December 31, 2012 and 2011, was $4.3 million and $4.7 million, respectively. Storeroom operating expenses remaining

in materials and supplies inventory at December 31, 2012 and 2011, were $4.9 million and $5.0 million, respectively.

During 2011, Cleco Power sold its entire fuel oil supply. Cleco Power does not anticipate a need to use fuel oil as a fuel source going forward.

Accounts Receivable

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. At December 31, 2012, the allowance for doubtful accounts amounted to $1.1 million. The allowance for doubtful accounts at December 31, 2011, was also $1.1 million. There is no off-balance sheet credit exposure related to Cleco’s customers.

Financing Receivables

At December 31, 2012 and 2011, Cleco, through Perryville and Attala, had a combined net investment in direct financing lease long-term asset of $13.5 million and $13.6 million, respectively. Each subsidiary leases its respective transmission assets to a single counterparty. Both counterparties are considered credit worthy and are expected to pay their obligations when due, thus, no allowance for credit loss has been recognized. Management bases this assessment on the following common factors of each counterparty:


•	both counterparties use the respective transmission facilities to move electricity from its power plants to the regional transmission grid,


•	neither counterparty has another avenue to move electricity from its respective power plants to the regional transmission grid,


•	the stream of payments was approved by the FERC through respective rate orders, and


•	both counterparties serve retail and wholesale customers in their respective service territories under LPSC oversight that allows recovery of prudent costs, of which, the stream of payments under the direct financing leases appear to be prudent.

Management monitors both entities for indication of adverse actions by their respective public service commissions and market conditions which would indicate an inability to pay their obligations under the direct financing leases when due. Since the inception of the agreements, each counterparty has paid their respective obligations when due, and at December 31, 2012 and 2011, no amounts were past due.

Reserves

Cleco maintains property insurance on generating stations, buildings and contents, and substations. Cleco is self-insured for any damage to transmission and distribution lines. To mitigate the exposure to potential financial loss for damage to lines, Cleco maintains an LPSC-approved funded storm reserve.

Cleco also maintains liability and workers’ compensation insurance to mitigate financial losses due to injuries and damages to the property of others. Cleco’s insurance covers claims that exceed certain self-insured limits. For claims that do not meet the limits to be covered by insurance, Cleco

maintains reserves. At December 31, 2012, the general liability and workers compensation reserves are immaterial because the balance of these items together represented 0.2% of total liabilities. The general liability and workers compensation reserves are immaterial at December 31, 2011, as well, because the balance of these items together, also, represented 0.2% of total liabilities.

Cash Equivalents

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

Restricted Cash and Cash Equivalents



	AT DEC. 31,
(THOUSANDS)	2012		2011
Diversified Lands’ mitigation escrow	$	97	$	97
Cleco Katrina/Rita’s storm recovery bonds	8,781		8,761
Cleco Power’s future storm restoration costs	5,343		24,876
Cleco Power’s renewable energy grant	—		381
Cleco Power’s NO_x allowance escrow	—		1,713
Total restricted cash and cash equivalents	$	14,221	$	35,828

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 2012, Cleco Katrina/Rita collected $20.1 million net of operating expenses. In March and September 2012, Cleco Katrina/Rita used $6.7 million and $6.4 million, respectively for scheduled storm recovery bond principal payments and $3.6 million and $3.4 million, respectively for related interest. Cleco Power’s restricted cash and cash equivalents held for future storm restoration costs decreased $19.5 million from December 31, 2011, primarily due to the transfer of $10.9 million to restricted investments and the transfer of $10.0 million to cover expenses associated with Hurricane Isaac. These amounts were partially offset by $1.4 million of storm surcredits. Cleco Power’s restricted cash and cash equivalents NO_x allowance escrow decreased $1.7 million from December 31, 2011. The funds were transfered from restricted to non-restricted cash and cash equivalents due to the courts vacating CSAPR. For more information about the restricted investments, see Note 5 — “Fair Value Accounting — Restricted Investments” and for more information about Hurricane Isaac, see Note 19 — “Storm Restoration.”

Equity Investments

Cleco reports its investment in unconsolidated affiliated companies on the equity method of accounting, as defined in the authoritative guidance on investments. The amounts reported on Cleco Corporation and Cleco Power’s Consolidated Balance Sheets represent assets contributed by Cleco Corporation or Cleco Power, plus their share of the net income of the affiliate, less any distributions of earnings (dividends) received from the affiliate. The revenues and expenses of these affiliates are netted and reported on one line

item as equity income from investees on Cleco Corporation and Cleco Power’s Consolidated Statements of Income. For more information, see Note 12 — “Variable Interest Entities.”

Cleco applies the provisions of the authoritative guidance on investments to account for equity method investment impairments. Under this standard, Cleco evaluates at each balance sheet date whether events and circumstances have occurred that indicate a possible other-than-temporary decline in the fair value of the investment and the possible inability to recover the carrying value through operations. Cleco uses estimates of the future cash flows from the investee and observable market transactions in order to calculate fair value and recoverability. An impairment is recognized when an other-than-temporary decline in market value occurs and recovery of the carrying value is not probable. No impairments were recorded for 2012, 2011, or 2010. For more information, see Note 12 — “Variable Interest Entities.”

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 transaction, Acadia’s assets, liabilities, revenues, expenses, and cash flows are presented on the corresponding line items of Cleco’s consolidated financial statements, prospectively. For more information on the Acadia Unit 2 transaction, see Note 18 — “Acadia Transactions — Acadia Unit 2.”

Income Taxes

Cleco accounts for income taxes under the asset and liability method. Cleco provides for federal and state income taxes currently payable, as well as for those deferred due to timing differences between reporting income and expenses for financial statement purposes versus tax purposes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted income tax rates expected to be applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. Cleco’s income tax expense and related regulatory assets and liabilities could be affected by changes in its assumptions and estimates and by ultimate resolution of assumptions and estimates with taxing authorities. Cleco files a federal consolidated income tax return for all wholly owned subsidiaries. Cleco computes its federal and state income taxes as if it were a standalone taxpayer. The LPSC generally requires Cleco Power to flow the effects of state income taxes immediately to customers. The LPSC specifically requires that the state tax benefits associated with the deductions related to storm damages be normalized. For more information on income taxes, see Note 9 — “Income Taxes.”

Investment Tax Credits

Investment tax credits, which were deferred for financial statement purposes, are amortized to income over the estimated service lives of the properties that gave rise to the credits.

NMTC Fund

In 2008, Cleco Corporation and U.S. Bancorp Community Development Corporation (USBCDC) formed the NMTC Fund.

The purpose of the NMTC 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. The NMTC Fund was later amended to include renewable energy investments. The majority of the energy investments qualify for grants under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009. For more information, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures About Guarantees — Other Commitments — New Markets Tax Credits.”

Accounting for Renewable Energy Tax Credits and Grants Under the American Recovery and Reinvestment Act of 2009 (Stimulus Act)

Cleco and the NMTC Fund have elected to receive cash grants under the Stimulus Act for investments in various projects. Cleco has elected to reduce the carrying value of the qualifying assets as cash grants are received, which will reduce the amount of depreciation expense recognized after the underlying assets are placed in service. Certain of the cash grants also reduce the tax basis of the underlying assets. Grants received via the NMTC Fund reduce the carrying value of the investment for GAAP, but do not reduce the income tax basis of the investment.

Debt Expenses, Premiums, and Discounts

Expenses, premiums, and discounts applicable to debt securities are amortized to income ratably over the lives of the related issues. Expenses and call premiums related to refinanced Cleco Power debt are deferred and amortized over the life of the new issue.

Revenue and Fuel Costs

Utility Revenue

Revenue from sales of electricity is recognized based upon the amount of energy delivered. The costs of fuel and purchased power used for retail customers currently are recovered from customers through the FAC. These costs are subject to audit and final determination by regulators. Excise taxes and pass-through fees collected on the sale of electricity are not recorded in utility revenue.

Unbilled Revenue

Cleco Power accrues estimated revenue monthly for energy delivered since the latest billings. The monthly estimated unbilled revenue amounts are recorded as revenue and a receivable and are reversed the following month.

Other Revenue

Other revenue is recognized at the time products or services are provided to and accepted by customers.

Franchise Fees

Cleco Power collects a consumer fee for one of its franchise agreements. This fee is not recorded on Cleco’s income statement as revenue and expense, but is reflected at gross amounts on Cleco’s balance sheet as a receivable until it is collected and as a payable until the liability is paid. Cleco currently does not have any excise taxes reflected on its income statement.

AFUDC

The capitalization of AFUDC by Cleco Power is a utility accounting practice prescribed by FERC and the LPSC. AFUDC represents the estimated cost of financing construction and is not a current source of cash. Under regulatory practices, a return on and recovery of AFUDC is permitted in setting rates charged for utility services. The composite AFUDC rate, including borrowed and other funds, was 12.1% on a pre-tax basis (7.5% net of tax) for 2012, 12.0% on a pre-tax basis (7.5% net of tax) for 2011, and 11.9% on a pre-tax basis (7.4% net of tax) for 2010.

Fair Value Measurements and Disclosures

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. 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 may enter into 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 FAC 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.

Cleco has entered into various contracts to mitigate the volatility in interest rate risk. These contracts include, but are not limited to, interest rate swaps and treasury rate locks. For these contracts in which Cleco is hedging the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of hedges will be recognized in current-period earnings unless management determines that it is probable that the costs will be recovered through the rate making process. If management determines that it is probable that the costs will be recovered, then they will be recognized as a regulatory asset or liability and amortized to earnings over the life of the related debt. For those contracts in which Cleco is hedging the variability of cash flows related to forecasted transactions that do not qualify as cash flow hedges, the changes in the fair value of such derivative instruments will be recognized in current period earnings unless management determines that it is probable that the costs will be recovered through the rate-making process. If management determines that it is probable that the costs will be recovered, then they will be recognized as a regulatory asset or liability and amortized to earnings over the life of the related debt. For more information on the interest rate risk contracts, see Note 5 — “Fair Value Accounting — Interest Rate Derivatives.”

Recent Authoritative Guidance

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

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 an 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 did not have an 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 did not 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. In December 2011, the FASB deferred the requirements relating to the presentation of reclassifications of items out of accumulated other comprehensive income until a later date to be determined by the FASB. The other provisions of the June 2011 guidance are not affected by this deferral. The adoption of this guidance did 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 did not have any impact on the financial condition or results of operations of the Registrants.

In December 2011, FASB revised the accounting for a parent that ceases to have a controlling financial interest in a subsidiary due to a default on the subsidiary’s non-recourse debt when the subsidiary is in substance real estate by requiring the application of real estate sales guidance. This revision is effective for events occurring on or after June 15, 2012. The adoption of this guidance did not have any impact on the financial condition or results of operations of the Registrants.

In December 2011, FASB revised the disclosure requirements related to balance sheet offsetting. After the effective date, entities must disclose both the gross and net information about instruments and transactions eligible for offsetting on the balance sheet, including transactions under master netting agreements. The adoption of this revision is required for interim and annual periods beginning on or after January 1, 2013. The adoption of this revision will not have any effect on the financial condition or results of operations of the Registrants since it relates to disclosures.

In July 2012, FASB issued guidance on testing indefinite-lived intangible assets for impairment. This guidance is intended to reduce costs and complexity of testing indefinite-lived intangible assets other than goodwill for impairment. Entities are allowed to perform a “qualitative” assessment to determine whether further impairment testing of indefinite-lived intangible assets is necessary, similar in approach to the goodwill impairment test. The adoption of this guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The adoption of this guidance will not have any impact on the financial condition or results of operations of the Registrants.

Earnings per Average Common Share

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

There were no stock option grants excluded from the computation of diluted earnings per share for the years 2012, 2011, and 2010.

Preferred Stock Redemption

For information on Cleco’s preferred stock redemption, see Note 7 — “Common and Preferred Stock — Preferred Stock.”

Stock-Based Compensation

For information on Cleco’s stock-based compensation, see Note 7 — “Common and Preferred Stock — Common Stock — Stock-Based Compensation.”



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.

Under the current regulatory environment, Cleco Power believes these regulatory assets will be fully recoverable; however, if in the future, as a result of regulatory changes or competition, Cleco Power’s ability to recover these regulatory assets would no longer be probable, then to the extent that such regulatory assets were determined not to be recoverable, Cleco Power would be required to write-down such assets. In addition, potential deregulation of the industry or possible future changes in the method of rate regulation of Cleco Power could require discontinuance of the application of these authoritative guidelines.

The following chart summarizes Cleco Power’s regulatory assets and liabilities at December 31, 2012 and 2011.



	AT DEC. 31,						REMAINING RECOVERY PERIOD	RETURN ON EQUITY
(THOUSANDS)	2012			2011			REMAINING RECOVERY PERIOD	RETURN ON EQUITY
Total federal regulatory asset — income taxes	$	24,222		$	34,127		N/A
Total state regulatory asset — income taxes	57,480			51,720			N/A
AFUDC	132,267			132,802			N/A
Total investment tax credit	(3,524		)	(4,228		)	N/A
Total regulatory assets — deferred taxes, net	210,445			214,421
Mining costs	16,569			19,117			6.5 yrs.	No
Interest costs	6,304			6,667			27 yrs.	No
Asset removal costs	867			829			37 yrs.	No
Postretirement plan costs	156,458			132,556			N/A	No
Tree trimming costs	5,656			8,371			2 yrs.	Yes
Training costs	7,330			7,486			47 yrs.	Yes
Storm surcredits, net	6,211			9,254			10 yrs.	No
Construction carrying costs	4,697			10,883			0.75 yrs.	No
Lignite mining agreement contingency	3,781			3,781			N/A	No
Power purchase agreement capacity costs	6,217			—			2.5 yrs.	Yes
AMI deferred revenue requirement	1,483			—			15 yrs.	Yes
AFUDC equity gross-up	74,158			74,346			N/A	No
Rate case costs	581			1,117			1 yr.	No
Acadia Unit 1 acquisition costs	2,865			2,971			27 yrs.	No
IRP/RFP costs	39			508			—	No
AMI pilot costs	22			153			0.5 yrs.	No
Financing costs	7,282			4,433			29 yrs.	No
Biomass costs	145			—			5 yrs.	No
Total regulatory assets - other	300,665			282,472
Construction carrying costs	(8,255		)	(40,322		)	0.6 yrs.	No
Fuel and purchased power	7,833			2,136			N/A	No
Total regulatory assets, net	$	510,688		$	458,707

Income Taxes

Cleco Power has recorded a net regulatory asset related to deferred income taxes in accordance with the authoritative guidance on income taxes. The related regulatory asset or liability recorded represents the effect of tax benefits or detriments that must be flowed through to customers as they are received or paid. Generally, the recovery periods for regulatory assets and liabilities are based on assets’ lives, which are typically 30 years or greater. The amounts deferred are attributable to differences between book and tax recovery periods.

Mining Costs

Cleco Power operates a generating unit jointly owned with SWEPCO that uses lignite as its fuel source.

Cleco Power (along with SWEPCO) maintains a Lignite Mining Agreement with DHLC, the operator of the Dolet Hills mine. As ordered then by the LPSC, Cleco Power’s retail customers began receiving fuel cost savings through the year 2011 while actual mining costs incurred above a certain percentage of the benchmark price were deferred, and could be recovered from retail customers through the FAC only when the actual mining costs are below a certain percentage of the benchmark price. The benchmark price used the GDP-IPD index as a proxy for the numerous escalators in the previous mining contract. During the course of the contract, Cleco Power and SWEPCO determined that the GDP-IPD index did not appropriately reflect the increase in mining costs caused

by sharp increases in diesel fuel and electricity costs associated with the mining operation. Because of this disconnect between the GDP-IPD index and actual mining costs, a significant amount of mining costs was being deferred by Cleco Power.

In 2006, Cleco Power recognized that there was a possibility it may not recover all or part of the lignite mining costs it had deferred and sought relief from the LPSC. In December 2007, the LPSC approved a settlement agreement between Cleco Power, SWEPCO and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over approximately 11.5 years. The settlement also established a new benchmark utilizing the contract’s escalators to assure a minimum 2% savings to customers compared to the costs under the prior mining contract. Under the settlement, the benchmarking was scheduled to end after April 2011. Cleco Power and SWEPCO also agreed to commit to continued operation of the mining operation through 2026 as long as the operation of the mine was considered prudent. Cleco Power did not record any additional deferred fuel costs under the new benchmarking method.

Interest Costs

Cleco Power’s deferred interest costs include additional deferred capital construction financing costs authorized by the LPSC. These costs are being amortized over the estimated lives of the respective assets constructed.

Asset Removal Costs

Under the authoritative guidance for asset retirement and environmental obligations, Cleco Power determined that a liability exists for cleanup and closing costs of solid waste facilities associated with its generating stations that use lignite for fuel. Applying these guidelines, Cleco Power determined that a liability exists for costs which may be incurred in the future for removal of asbestos from its general service buildings, the removal of transmission towers on leased right-of-ways and for the abatement of PCBs in transformers.

At December 31, 2012 and 2011, the liability for solid waste facility closure costs at the generating station using lignite is estimated at $0.6 million and $0.5 million, respectively, and is included in other deferred credits. At December 31, 2012 and 2011, Cleco Power’s liability for removal of asbestos is estimated at $0.3 million and also is included in other deferred credits.

Postretirement Costs

Authoritative guidance on retirement benefits compensation requires companies to recognize the funded status of their postretirement benefit plans as a net liability or asset. The net liability or asset is defined as the difference between the benefit obligation and the fair market value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. Historically, the LPSC has allowed Cleco Power to recover pension plan expense. Cleco Power, therefore, recognizes a regulatory asset based on its determination that these costs can be collected from customers. The amount and timing of the recovery will be

based on the changing funded status of the pension plan in future periods. For more information on Cleco’s pension plan and adoption of these authoritative guidelines, see Note 8 — “Pension Plan and Employee Benefits.”

Tree Trimming Costs

In January 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset for costs incurred to trim, cut, or remove trees that were damaged by hurricanes Katrina and Rita, but were not addressed as part of the restoration efforts. The regulatory asset was capped at $12.0 million in actual expenditures plus a 12.4% grossed-up rate of return. Recovery of these expenditures was requested in Cleco Power’s base rate application filed in July 2008 and was approved by the LPSC in October 2009. In February 2010, Cleco Power began amortizing the regulatory asset over a five-year period.

Training Costs

In February 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset which is being charged with training costs associated with existing processes and technology for new employees at Madison Unit 3. Recovery of these expenditures was requested in Cleco Power’s base rate application filed in July 2008 and were covered by the retail rate plan which was approved by the LPSC in October 2009. In February 2010, Cleco Power began amortizing the regulatory asset over a 50-year period.

Storm Surcredits, Net

Cleco Power has recorded a storm surcredit as the result of a settlement with the LPSC that addressed, among other things, the recovery of the storm damages related to hurricanes Katrina and Rita. In the settlement, Cleco Power was required to implement a surcredit to provide ratepayers with the economic benefit of the carrying charges of all accumulated deferred income tax liabilities due to the storm damage costs at a 12.2% rate of return which was set in LPSC Order No. U-29157A. The accumulated deferred income tax liability includes the tax benefit on deductions for operation and maintenance expenses, casualty loss, and depreciation against taxable income in the year incurred and all subsequent periods. The settlement, through a true-up mechanism, allows the surcredit to be adjusted to reflect the actual tax deductions allowed by the IRS.

Cleco Power also was allowed to record a corresponding regulatory asset in an amount representing the flow back of the carrying charges to ratepayers. This amount is being amortized over the life of the storm recovery bonds. The corresponding regulatory asset will be adjusted through the same surcredit true-up mechanism at the time of a final determination of the tax benefit for storm damage costs by the IRS.

As a result of the settlement with the LPSC, Cleco Power is required to implement a surcredit when funds are withdrawn from the restricted storm reserve. In September 2012 and September 2011, Cleco Power withdrew $10.0 million and $2.0 million, respectively, from the restricted storm reserve to pay for storm damages resulting in the establishment of a surcredit. Cleco Power will replenish the restricted storm reserve with the surcredit.

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. Cleco Power’s retail rate plan, which was approved in October 2009, established that Cleco Power return carrying costs to customers 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 operations and Cleco Power began returning the construction carrying costs to customers. These costs are being amortized over a four-year period. At December 31, 2012, the regulatory liability and the related regulatory asset were $8.3 million and $4.7 million, respectively. As of December 31, 2012, Cleco Power had returned $158.2 million to customers. At December 31, 2012, the remaining $8.3 million is due to be returned to customers within one year.

Amended Lignite Mining Agreement Contingency

In April 2009, Cleco Power and SWEPCO entered into a series of transactions to acquire additional lignite reserves and mining equipment from NAC, each agreeing to purchase a 50% ownership interest in Oxbow from NAC for a combined price of $25.7 million. Through mineral lease agreements and ownership of fee land, Oxbow controls approximately 43 million tons of lignite reserves in an area referred to as the Oxbow Mine. Cleco Power, SWEPCO, and DHLC entered into the Amended Lignite Mining Agreement which requires DHLC to mine lignite at the existing Dolet Hills Mine along with the Oxbow Mine and deliver the lignite to the Dolet Hills Power Station at cost plus a specified management fee. The two mining areas are expected to be sufficient to provide the Dolet Hills Power Station with lignite fuel until at least 2026.

Among the provisions of the Amended Lignite Mining Agreement, it is a requirement that if DHLC is unable to pay for loans and lease payments when due, Cleco Power will pay 50% of the amounts due. Any payments under this provision will be considered a prepayment of lignite to be delivered in the future and will be credited to future invoices from DHLC. This provision meets the recognition requirements as a guarantee to an unrelated third party. Cleco Power recognized a liability of $3.8 million upon the closing of the transactions. A regulatory asset of $3.8 million was also recognized due to Cleco Power’s ability to recover prudent fuel costs from customers through the FAC. The liability and related regulatory asset will be derecognized when the Amended Lignite Mining Agreement terminates. 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.

Power Purchase Agreement Capacity Costs

In March 2012, Cleco Power received approval from the LPSC for a three-year power purchase agreement with Evangeline providing 730 MW of capacity and energy beginning May 1, 2012, and ending April 30, 2015. The LPSC order allows

Cleco Power to defer and recover a portion of capacity costs associated with the power purchase agreement. The deferred costs are being collected over the term of the contract.

AMI Deferred Revenue Requirement

In February 2011, the LPSC approved Cleco Power’s stipulated settlement in Docket No. U-31393 allowing Cleco Power to defer, as a regulatory asset, the estimated revenue requirements for the AMI project. The amount of the regulatory asset, including carrying charges, was capped by the LPSC at $20.0 million. The regulatory asset will amortize by the end of the economic life of the project, currently estimated at 15 years.

AFUDC Equity Gross-Up

Cleco Power capitalizes equity AFUDC as a cost component of construction projects in accordance with the authoritative guidance for regulated operations. Cleco Power has recorded a regulatory asset to recover the tax gross-up related to the equity component of AFUDC. These costs are being amortized over the estimated lives of the respective assets constructed. In the first quarter of 2010, AFUDC equity gross-up was reclassed from Regulatory assets and liabilities – deferred taxes, net to Regulatory assets – other.

Rate Case Costs

In October 2009, the LPSC approved Cleco Power’s request to recover costs incurred as a result of Cleco Power’s rate case filed in July 2008. The new rates became effective upon the commercial operation of Madison Unit 3 on February 12, 2010, and Cleco Power began amortizing the regulatory asset over a four-year period.

Acadia Unit 1 Acquisition Costs

In October 2009, the LPSC approved Cleco Power’s request to establish a regulatory asset for costs incurred as a result of the acquisition by Cleco Power of Acadia Unit 1 and half of Acadia Power Station’s related common facilities. Recovery of these expenditures was requested in Cleco Power’s base rate application filed in July 2008, and these expenditures were covered by the retail rate plan which was approved by the LPSC in October 2009. The new rates became effective upon the commencement of commercial operation of Madison Unit 3 and Cleco Power began amortizing the regulatory asset over a 30-year period. For more information regarding the Acadia Unit 1 transaction, see Note 18 — “Acadia Transactions — Acadia Unit 1.”

IRP/RFP Costs

In October 2009, the LPSC approved Cleco Power’s request to establish a regulatory asset to recover IRP and RFP costs incurred. The new rates became effective upon the commencement of commercial operation of Madison Unit 3 and Cleco Power began amortizing the regulatory asset over a three-year period.

AMI Pilot Costs

In September 2009, the LPSC approved Cleco Power’s request to establish a regulatory asset to recover AMI pilot costs incurred. Recovery of these expenditures was approved by the LPSC in October 2009. The new rates became effective upon the commercial operation of Madison Unit 3. In March 2010, Cleco Power began amortizing these costs over a three-year period.

Financing Costs

In 2011, Cleco Power entered into and settled two treasury rate locks. Also in 2011, Cleco Power entered into a forward starting swap contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance. As a result of management’s assessment that it is probable that these costs will be recovered through the rate-making process, Cleco Power will amortize the regulatory asset over the term of the related debt issuance.

Biomass Test Burn Costs

In November 2011, the LPSC approved Cleco Power’s request to establish a regulatory asset for the non-fuel, non-capital portion of costs incurred to conduct a test burn of biomass fuel at Madison Unit 3. In August 2012, Cleco Power began amortizing these costs over a five-year period.

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 FAC, which enables Cleco Power to pass on to its customers substantially all such charges. For 2012, approximately 89% of Cleco Power’s total fuel cost was regulated by the LPSC, while the remainder was regulated by FERC.

The $5.7 million increase in the under-recovered costs was primarily due to an $12.2 million increase in fuel and purchased power costs. Partially offsetting this increase was a $6.5 million decrease in losses on natural gas positions.



Note 4 — Jointly Owned Generation Units

Two electric generation units operated by Cleco Power are jointly owned with other utilities. The joint-owners are responsible for their own share of the capital and the operating

and maintenance costs of the respective units. Cleco Power recognized $130.2 million, $131.8 million, and $118.3 million as its proportionate share of operating and maintenance expenses associated with these two units, which include fuel costs of $107.9 million, $109.2 million, and $97.9 million during the years ended December 31, 2012, 2011, and 2010, respectively.



				AT DEC. 31, 2012
(DOLLAR AMOUNTS IN THOUSANDS)	RODEMACHER UNIT #2			DOLET HILLS			TOTAL
Utility plant in service	$	92,011		$	305,010		$	397,021
Accumulated depreciation	$	69,600		$	199,138		$	268,738
Ownership	30		%	50		%
Nameplate capacity (MW)	523			650
Cleco Power’s ownership interest (MW)	157			325



Note 5 — Fair Value Accounting

The amounts reflected in Cleco Corporation and Cleco Power’s Consolidated Balance Sheets at December 31, 2012 and December 31, 2011, for cash and cash equivalents, restricted 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 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 with similar maturities. The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments subject to fair value accounting.


•	Certificates of deposit, banker’s acceptances and time deposits,


•	Corporate notes and bonds, fixed or floating rate, and covered bonds,


•	Commercial paper,


•	Asset backed securities with a minimum long-term rating of AA by Standard & Poor’s and Aaa by Moody’s,


•	U.S. government mortgage securities with a short average life with a minimum long-term rating of AA by Standard & Poor’s and Aaa by Moody’s,


•	Repurchase agreements with the primary government securities dealers or financial institutions in which Cleco deposits and/or concentrates cash, and


•	Money market funds which must have at least $15.0 billion in assets under management; must have been in existence for not less than two years; must have a minimum rating of AAA by Standard & Poor’s and Aaa by Moody’s and must be compliant with the SEC rule 2a-7 which restricts the quality, maturity, and diversity of investments by money market funds.

The minimum acceptable short-term credit rating must be A-1 by Standard & Poor’s and P-1 by Moody’s. The maximum maturity of any instrument must be 36 months, and the maximum portfolio duration must be 12 months.

Diversification of holdings must be stressed recognizing the total amount of the portfolio. Investments in securities of any one issuer will be limited to 5%at the time of purchase except for U.S. Treasury and Agency Securities and money market funds. No more than 50% of the portfolio at the time of purchase will be invested in any single Federal Agency/Government Sponsored Enterprise.

Restricted Investments

In September 2007, the LPSC authorized the funding and securitization of a $50.0 million reserve for Cleco Power’s future storm costs. On July 1, 2012, Cleco Power transferred $13.0 million of the related restricted cash and cash equivalents to an outside investment manager. Investments made by the investment manager are restricted to the criteria established by management in Cleco Power’s guidelines for short-term investments. At December 31, 2012, the investments included cash and cash equivalents and debt securities.

The cash and cash equivalents are reflected in Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2012, as restricted cash and cash equivalents and approximate fair value because of their short-term nature.

The debt securities were recorded at fair value on Cleco and Cleco Power’s Consolidated Balance Sheets at

December 31, 2012, as restricted investments. The investments in debt securities include municipal bonds and commercial paper with original maturity dates of more than three months and are classified as available-for-sale securities and are marked-to-market at least quarterly. Because Cleco Power’s investment strategy for these investments fits within the requirements established by the LPSC for the restricted reserve fund, realized and unrealized gains and losses, interest income, investment management fees and custody fees are recorded directly to Cleco Power’s restricted storm reserve rather than in earnings or other comprehensive income. As a result, no amounts will be recorded to other comprehensive income for these investments.

Quarterly, Cleco Power’s available-for-sale, debt securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary.

Management determines whether it intends to sell or if it is more likely than not that it will be required to sell impaired securities. This determination considers current and forecasted liquidity and regulatory requirements. For Cleco Power’s impaired debt securities for which there was no intent or expected requirement to sell, the evaluation assesses whether it is likely the amortized cost will be recovered considering the nature of the securities, credit rating, financial condition of the issuer or the extent and duration of the unrealized loss and market conditions. If Cleco Power determined that an other-than-temporary decline in value existed on its debt securities, the investments would be written down to fair value with a new cost basis established. Declines in fair value below cost basis that are determined to be other-than-temporary would be recorded to Cleco Power’s restricted storm reserve. The unrealized losses on Cleco Power’s debt securities as of December 31, 2012, were caused by interest rate movements. Cleco Power does not intend to sell the debt securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of the amortized cost value. Cleco Power determined there were no material other-than-temporary impairments on its debt securities at December 31, 2012.

The following table provides a reconciliation of Cleco Power’s available-for-sale debt securities from cost basis to fair value at December 31, 2012.



	AT DEC. 31, 2012
(THOUSANDS)	AMORTIZED COST		TOTAL UNREALIZED GAINS ⁽¹⁾		TOTAL UNREALIZED LOSSES ⁽¹⁾		FAIR VALUE
Municipal bonds	$	10,228	$	3	$	28	$	10,203
Commercial paper	649		—		—		649
Total available-for-sale securities	$	10,877	$	3	$	28	$	10,852

⁽¹⁾ Unrealized gains and losses are recorded to the restricted storm reserve.

Cleco Power recognized less than $0.1 million of unrealized mark-to-market losses in the restricted storm reserve for the year ended December 31, 2012. The following table summarizes the debt securities that were in an unrealized loss position at December 31, 2012, but for which no other-than-temporary impairment was recognized:

At December 31, 2012, the fair value of Cleco Power’s available-for-sale debt securities by contractual maturity was:



(THOUSANDS)	AT DEC. 31, 2012
One year or less	$	6,204
Over one year through five years	4,648
Total fair value	$	10,852

There were no realized gains or losses on Cleco Power’s available-for-sale securities for the year ended December 31, 2012. Realized gains and losses will be determined on a specific identification basis.

Interest Rate Derivatives

Forward Starting Interest Rate Swap

On November 14, 2011, Cleco Power entered into a pay fixed/receive variable forward starting interest rate swap contract in order to mitigate the interest rate exposure on coupon payments related to the remaining $50.0 million fixed-rate forecasted debt issuance. The forward starting interest rate swap has a spot 30-year all-in swap rate of 3.05%, notional amount of $50.0 million, with the pricing date of May 14, 2013, or the issuance of the notes, whichever is earlier. The forward starting interest rate swap meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging and is carried on the balance sheet at its fair value. The fair market value of the forward starting interest rate swap is calculated by the net of the present value of the fixed payments to be paid by Cleco Power and the present value of the three-month LIBOR payments to be

received by Cleco Power. Since future LIBOR rates are not available for each month until termination, quoted LIBOR rates from an active exchange for observable time periods were used to create a forward LIBOR curve for all months until termination. Because of the inputs and common techniques used to calculate fair value, the swap valuation was considered Level 2. Cleco Power recognized $1.2 million unrealized mark-to-market gains and $3.3 million unrealized mark-to market losses in other comprehensive income for the years ended December 31, 2012 and 2011, respectively. The fair market value of $2.6 million and $3.3 million for the forward starting interest rate swap was recorded on Cleco and Cleco Power’s Consolidated Balance Sheets as an interest rate risk management liability as of December 31, 2012 and December 31, 2011, respectively. There was no impact to earnings due to ineffectiveness for the year ended December 31, 2011. There were $0.5 million of deferred losses due to ineffectiveness for the year ended December 31, 2012.

Fair Value Measurements and Disclosures

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

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

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.

The institutional money market funds were reported on the Cleco Consolidated Balance Sheet in cash and cash equivalents, current restricted cash and cash equivalents, non-current restricted cash and cash equivalents, and restricted investments of $24.7 million, $8.8 million, $5.4 million, and $0.6 million respectively, at December 31, 2012. At Cleco Power, the institutional money market funds were reported on the consolidated balance sheet in cash and cash equivalents, current restricted cash and cash equivalents, non-current restricted cash and cash equivalents, and restricted investments and were $18.6 million, $8.8 million, $5.3 million, and $0.6 million, respectively, as of December 31, 2012.

The municipal bonds were reported on Cleco and Cleco Power’s Consolidated Balance Sheets in restricted investments in the amount of $10.2 million at December 31, 2012.

The forward starting interest rate swap was reported on Cleco and Cleco Power’s Consolidated Balance Sheets as a current liability in the line item interest rate risk management liability at December 31, 2012 and 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 December 31, 2012 or 2011.

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 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 mark-to-market value of 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 the mark-to-market value of the 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 municipal bonds consisted of a single class. In order to maximize income and to meet the requirements established by the LPSC for the restricted reserve fund, restricted cash and cash equivalents were invested in short-term, fixed-income, debt instruments in order to maintain safety and liquidity. The risks associated with this class are counterparty risk of the fund manager and risk of price volatility associated with the municipal bonds. Quarterly, Cleco receives reports from the trustee for the investment manager which provides the fair value measurement. Cleco performs an evaluation of those reports to verify the fair value of the securities.

The Level 2 interest rate derivative was one forward starting interest rate swap liability that consisted of a single class that only contains one instrument. The risks are changes in the three-month LIBOR rate and counterparty risk. This instrument is with a direct counterparty and not traded through an exchange.

The Level 2 long-term debt liability consists of a single class. In order to fund capital requirements, Cleco issues long-term, fixed rate debt with various tenors. The fair value of this class fluctuates as the market interest rates for fixed rate debt with similar tenors and credit ratings changes. The fair value of the debt could also change from period to period due to changes in the credit rating of the Cleco entity that issued the debt.

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 years ended December 31, 2012, 2011, and 2010, Cleco did not experience any transfers between levels.

Derivatives and Hedging

The authoritative guidance on derivatives and hedging requires entities to provide transparency 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 and quantitative 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 Consolidated Balance Sheets as of December 31, 2012 and 2011:



	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
	LIABILITY DERIVATIVES
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT DEC. 31, 2012		AT DEC. 31, 2011
Commodity contracts
Fuel cost hedges:
Current	Energy risk management liabilities, net	$	—	$	(5,336	)
Total		$	—	$	(5,336	)

The following table presents the effect of derivatives not designated as hedging instruments on Cleco Corporation and Cleco Power’s Consolidated Statements of Income for the years December 31, 2012, 2011, and 2010.



	AT DEC. 31,
(THOUSANDS)	2012			2011
Bonds
Cleco Power’s senior notes, 5.375%, due 2013	$	75,000		$	75,000
Cleco Power’s senior notes, 4.95%, due 2015	50,000			50,000
Cleco Power’s senior notes, 6.65%, due 2018	250,000			250,000
Cleco Power’s senior notes, 4.33%, due 2027	50,000			—
Cleco Power’s senior notes, 6.50%, due 2035	295,000			295,000
Cleco Power’s senior notes, 5.942%, due 2040	250,000			250,000
Cleco Power’s senior notes, 5.988%, due 2041	100,000			100,000
Cleco Power’s pollution control revenue bonds, 5.875%, due 2029, callable after September 1, 2009	—			61,260
Cleco Power’s solid waste disposal facility bonds, 4.70%, due 2036, callable after November 1, 2016	60,000			60,000
Cleco Power’s solid waste disposal facility bonds, 5.25%, due 2037, mandatory tender on March 1, 2013	60,000			60,000
Cleco Katrina/Rita’s storm recovery bonds, 4.41%, due 2020	62,598			75,707
Cleco Katrina/Rita’s storm recovery bonds, 5.61%, due 2023	67,600			67,600
Total bonds	1,320,198			1,344,567
Other long-term debt
Cleco Corporation’s credit facility draws	25,000			10,000
Barge lease obligations, ending December 31, 2017	11,350			17,538
Gross amount of long-term debt	1,356,548			1,372,105
Less: long-term debt due within one year	88,969			24,258
Less: lease obligations classified as long-term debt due within one year	2,171			1,841
Unamortized premium and discount, net	(8,150		)	(8,950		)
Total long-term debt, net	$	1,257,258		$	1,337,056

The amounts payable under long-term debt agreements for each year through 2017 and thereafter are as follows.



(THOUSANDS)
Amounts payable under long-term debt agreements
2013	$	88,969
2014	$	14,876
2015	$	90,824
2016	$	16,814
2017	$	17,896
Thereafter	$	1,115,819

At December 31, 2012 and 2011, Cleco had no short-term debt outstanding.

At December 31, 2012, Cleco’s long-term debt outstanding was $1.35 billion, of which $91.1 million was due within one year, compared to $1.36 billion outstanding at December 31, 2011, of which $26.1 million was due within one year. The long-term debt due within one year at December 31, 2012, represents $75.0 million in senior notes due May 1, 2013, $14.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $2.1 million of capital lease payments.

million of Rapides Parish pollution control bonds in January 2012 and a $6.2 million decrease in capital lease obligations. These decreases were partially offset by the issuance of $50.0 million senior unsecured notes in May 2012, a $15.0 million increase in credit facility draws outstanding, and debt premium amortizations of $0.8 million.

The amounts payable under the capital lease agreements for each year through 2017 and thereafter are as follows.



(THOUSANDS)
Amounts payable under capital lease agreements
2013	$	2,171
2014	$	2,305
2015	$	2,448
2016	$	2,607
2017	$	1,819

Cleco Power

Cleco Power’s total indebtedness as of December 31, 2012 and 2011, was as follows.



	AT DEC. 31,
(THOUSANDS)	2012			2011
Bonds
Senior notes, 5.375%, due 2013	$	75,000		$	75,000
Senior notes, 4.95%, due 2015	50,000			50,000
Senior notes, 6.65%, due 2018	250,000			250,000
Senior notes, 4.33%, due 2027	50,000			—
Senior notes, 6.50%, due 2035	295,000			295,000
Senior notes, 5.942%, due 2040	250,000			250,000
Senior notes, 5.988%, due 2041	100,000			100,000
Pollution control revenue bonds, 5.875%, due 2029, callable after September 1, 2009	—			61,260
Solid waste disposal facility bonds, 4.70%, due 2036, callable after November 1, 2016	60,000			60,000
Solid waste disposal facility bonds, 5.25%, due 2037, mandatory tender on March 1, 2013	60,000			60,000
Cleco Katrina/Rita’s storm recovery bonds, 4.41%, due 2020	62,598			75,707
Cleco Katrina/Rita’s storm recovery bonds, 5.61%, due 2023	67,600			67,600
Total bonds	1,320,198			1,344,567
Other long-term debt
Barge lease obligations, ending December 31, 2017	11,350			17,538
Gross amount of long-term debt	1,331,548			1,362,105
Less: long-term debt due within one year	88,969			24,258
Less: lease obligations classified as long-term debt due within one year	2,171			1,841
Unamortized premium and discount, net	(8,150		)	(8,950		)
Total long-term debt, net	$	1,232,258		$	1,327,056

The amounts payable under long-term debt agreements for each year through 2017 and thereafter are as follows.



(THOUSANDS)
Amounts payable under long-term debt agreements
2013	$	88,969
2014	$	14,876
2015	$	65,824
2016	$	16,814
2017	$	17,896
Thereafter	$	1,115,819

At December 31, 2012 and 2011, Cleco Power had no outstanding short-term debt.

At December 31, 2012, Cleco Power’s long-term debt outstanding was $1.32 billion, of which $91.1 million was due within one year, compared to $1.35 billion outstanding at December 31, 2011, of which $26.1 million was due within one year. The long-term debt due within one year at December 31, 2012, represents $75.0 million in senior notes due May 1, 2013, and $14.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $2.1 million of capital lease payments.

For Cleco Power, long-term debt decreased $29.8 million from December 31, 2011, primarily due to redeeming $50.1 million of DeSoto Parish pollution control bonds in May 2012 and $13.1 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2012. Also contributing to the decrease was the redemption of $11.2 million of Rapides Parish pollution control bonds in January 2012 and a $6.2 million decrease in capital lease obligations. These decreases were partially offset by the issuance of $50.0 million senior unsecured notes in May 2012 and debt premium amortizations of $0.8 million.

The amounts payable under the capital lease agreements for each year through 2017 and thereafter are as follows.



(THOUSANDS)
Amounts payable under capital lease agreements
2013	$	2,171
2014	$	2,305
2015	$	2,448
2016	$	2,607
2017	$	1,819

Interest Rate Derivatives

Treasury Rate Locks

On November 14, 2011, Cleco Power settled the $150.0 million treasury rate lock contract and extended the treasury rate lock contract at a notional amount of $100.0 million, with a pricing date of December 21, 2011, or the date of issuance of the debt, whichever was earlier. The 3.89% rate lock was based on the 30-year treasury note yield as of November 14, 2011, and two-thirds of the fair market value of the previous treasury rate lock. This treasury rate lock extension did not qualify for hedge accounting due to ineffectiveness resulting from the embedded loss related to the previous treasury rate lock. On December 16, 2011, Cleco Power issued $100.0 million senior unsecured private placement notes at an interest rate of 5.12%. The maturity date of the notes is December 16, 2041.

The proceeds were used for general corporate purposes and for the repurchase of debt. On December 2, 2011, the pricing date of the notes, Cleco Power settled the treasury rate lock extension. At December 31, 2011, Cleco Power recorded $22.3 million in other comprehensive income and deferred $4.4 million in losses and ineffectiveness as a regulatory asset related to the settlement of the two treasury rate locks. During 2012, Cleco Power deferred an additional $2.4 million of losses and ineffectiveness related to the treasury rate locks as a regulatory asset.

As a result of management’s assessment that it is probable that the losses and ineffectiveness will be recovered through the rate-making process, Cleco Power will amortize the regulatory asset over the 30-year term of the related debt. The amount recorded in other comprehensive income, will also be amortized as interest expense over the 30-year term of the related debt issuance.

Forward Starting Interest Rate Swap

Also, on November 14, 2011, Cleco Power entered into a forward starting swap contract in order to mitigate the interest rate exposure on coupon payments related to a forecasted debt issuance. The notional amount of the forward starting swap is $50.0 million, with a pricing date of May 14, 2013, or the date of issuance of the debt, whichever is earlier. The forward starting swap meets the criteria of a cash flow hedge under the authoritative guidance as it relates to derivatives and hedging. The 3.05% swap was based on the 30-year treasury note yield as of November 14, 2011. At December 31, 2012, Cleco Power deferred $0.5 million of losses and ineffectiveness related to the forward starting swap contract as a regulatory asset.

Credit Facilities

At December 31, 2012, Cleco had two separate revolving credit facilities, one for Cleco Corporation and one for Cleco Power, with a maximum aggregate capacity of $550.0 million.

In October 2011, Cleco Corporation entered into a $250.0 million five-year revolving credit facility. The credit facility was set to mature on October 7, 2016, and provided for working capital and other needs. The borrowing costs are LIBOR plus 1.50% or ABR, plus facility fees of 0.25%. At December 31, 2012, Cleco Corporation had $25.0 million borrowings outstanding under its existing credit facility, leaving an available borrowing capacity of $225.0 million. The $25.0 million draws outstanding consisted of a $15.0 million draw and a $10.0 million draw. The $15.0 million draw matured and was renewed on January 17, 2013, and was subsequently repaid on February 4, 2013. The $10.0 million draw matured and was repaid on January 28, 2013. Under covenants contained in Cleco Corporation’s credit facility, Cleco is required to maintain total indebtedness equal to or less than 65% of total capitalization. At December 31, 2012, approximately $758.3 million of Cleco’s retained earnings was unrestricted. If Cleco Power defaults under the Cleco Power facility, then Cleco Corporation would be considered in default under the Cleco Corporation facility. At December 31, 2012, Cleco Corporation was in compliance with the covenants in its credit facility.

In October 2011, Cleco Power entered into a $300.0 million five-year revolving credit facility. The credit facility was set to mature on October 7, 2016, and provided for working capital and other needs. Cleco Power’s borrowing costs under this facility were equal to LIBOR plus 1.275%, or ABR, plus

facility fees of 0.225% and the borrowing capacity remained $300.0 million. At December 31, 2012, Cleco Power had no borrowings outstanding under its existing credit facility. Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness equal to or less than 65% of total capitalization. At December 31, 2012, approximately $623.7 million of Cleco Power’s member’s equity was unrestricted. At December 31, 2012, Cleco Power was in compliance with the covenants in its credit facility.



Note 7 — Common and Preferred Stock

Common Stock

Stock-Based Plan Descriptions and Share Information

At December 31, 2012 and 2011, Cleco had two stock-based compensation plans, the ESPP and the LTICP.

Employee Stock Purchase Plan

Regular, full-time, and part-time employees of Cleco Corporation and its participating subsidiaries, except officers, general managers, and employees who own 5% or more of Cleco Corporation's stock, may participate in the ESPP. An eligible employee elects to participate in the ESPP by entering into an option agreement with Cleco Corporation or its affiliate authorizing payroll deductions to purchase stock at a discounted rate. The amount of payroll deductions required by the plan are to be no less than $10 but no more than $350 each pay period. The payroll deductions are accumulated during a calendar quarter, which is referred to as the “offering period,” and remain as general assets of Cleco pending the purchase of common stock by the plan administrator. No trust or other fiduciary account has been established in connection with the ESPP. At the end of each offering period, payroll deductions are automatically applied to the purchase of common stock. Shares of common stock are purchased at a 5% discount of the fair market value as of the last trading day of each offering period. The number of shares of common stock purchased is determined by dividing each participant's payroll deductions during the offering period by the option price of a share of common stock. A participant may purchase a maximum of 62 shares per offering period. Dividends received on shares are automatically reinvested as required by the dividend reinvestment plan (DRIP) provisions of the ESPP.

A maximum of 734,000 shares of common stock may be purchased under the ESPP, subject to adjustment for changes in the capitalization of Cleco Corporation. The Compensation

Committee of Cleco Corporation's Board of Directors monitors the ESPP. The Compensation Committee and the Board of Directors possess the authority to amend the ESPP, but shareholder approval is required for any amendment that increases the number of shares covered by the ESPP. As of December 31, 2012, there were 418,527 shares of common stock available for purchase under the ESPP.

Long-Term Incentive Compensation Plan

Stock options, restricted stock, known as non-vested stock as defined by the authoritative guidance on stock-based compensation, common stock equivalent units, and stock appreciation rights may be granted or awarded to certain officers, key employees, or directors of Cleco Corporation and its affiliates under the LTICP. On December 31, 2009, the 2000 LTICP expired and no further grants or awards were made under this plan. The grants and awards that had been made under the 2000 LTICP are to remain outstanding and in effect until exercised, matured, expired, or forfeited in accordance with their existing terms. At December 31, 2012, 46,180 shares of non-vested Cleco Corporation common stock remained outstanding under the 2000 LTICP. There were no stock options or common stock equivalent units outstanding under this plan at December 31, 2012.

With shareholder approval, the 2010 LTICP became effective January 1, 2010. Under this plan, a maximum of 2,250,000 shares of Cleco Corporation common stock can be granted or awarded. At December 31, 2012, there were 1,635,384 shares available for future grants or awards under the 2010 LTICP. Equity instruments awarded to employees and directors historically have come from issuing new shares of common stock; however, future awards may come from purchasing outstanding shares of common stock through Cleco Corporation's common stock repurchase program.

Stock Options

Stock options are granted at an exercise price calculated by averaging the high and low stock price on the grant date rounded to the nearest one-eighth. Stock options granted to directors are immediately exercisable and expire after 10 years. Stock options granted to officers and employees vest one-third each year beginning on the third anniversary of the grant date and expire after 10 years. There were no stock options granted in 2012, 2011, or 2010.

A summary of LTICP stock option activity during the year ended December 31, 2012, is presented in the following table.

Non-Vested Stock and Common Stock Equivalent Units

In 2012, 2011, and 2010, Cleco granted non-vested stock to certain officers, key employees, and directors. In 2010, common stock equivalent units were granted to certain officers, and key employees. Because it can only be settled in shares of Cleco Corporation common stock, non-vested stock is classified as equity. Recipients of non-vested stock have full voting rights of a stockholder. At the time restrictions lapse, the accrued dividend equivalent units that are paid to the recipient are prorated based upon the percentage of vested stock to the total restricted stock awarded. Because they are settled in cash, awarded common stock equivalent units are

classified as a liability. Recipients of common stock equivalent

units receive dividend equivalent units under the same terms

as the dividends paid on non-vested stock. In order to vest, both instruments require the satisfaction of a service requirement and a market-based requirement. Recipients of both types of instruments are eligible to receive opportunity instruments if certain market-based measures are exceeded.

Cleco also awards employees and directors non-vested stock with only a service period requirement. These awards

require the satisfaction of a pre-determined service period in order for the shares to vest. At December 31, 2012, the number of target and opportunity restricted shares and common stock equivalent units previously awarded for which restrictions had not lapsed totaled 683,318. At December 31, 2012, the number of shares of non-vested stock previously granted with only a service period requirement for which the period had not ended was 127,376.

During 2012, Cleco granted 148,186 shares of non-vested stock to certain officers, key employees, and directors of Cleco pursuant to the LTICP. Of the total shares of non-vested stock granted during 2012, 137,175 shares were granted from new shares of common stock and 11,011 shares were granted through Cleco's common stock repurchase program. There were no common stock equivalent units granted in 2012 or 2011.

A summary of non-vested stock activity during the year ended December 31, 2012, is presented in the following table.

The fair value of shares of non-vested stock which vested during the years ended December 31, 2012, 2011, and 2010 was $3.1 million, $4.0 million, and $2.4 million, respectively.

Stock-Based Compensation

During the years ended December 31, 2012, 2011, and 2010, Cleco did not modify any of the terms of outstanding awards. Cleco has recognized stock-based compensation expense for these provisions in accordance with the non-substantive vesting period approach.

Cleco recorded compensation expense for all non-vested options and non-vested stock during the years ended December 31, 2012, 2011, and 2010. Assuming achievement of vesting requirements is probable, stock-based compensation expense of non-vested stock is recorded during

the service periods, which are generally three years, after which the restrictions lapse. All stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense in the income statement over the award's requisite service period. Awards that vest pro rata during the requisite service period that contain only a service condition are defined as having a graded vesting schedule and could be treated as multiple awards with separate vesting schedules. However, Cleco has elected to treat grants with graded vesting schedules as one award and recognize the related compensation expense on a straight-line basis over the requisite service period.

The ESPP does not contain optionality features beyond those listed by the authoritative guidance on stock-based compensation; therefore, Cleco is not required to recognize a

As required by the authoritative guidance on stock-based compensation, the amount of stock-based compensation capitalized in property, plant, and equipment on Cleco's consolidated balance sheets for the years ended December 31, 2012 and 2011, was $0.8 million and $1.0 million, respectively. The amount of stock-based compensation capitalized in property, plant, and equipment on Cleco Power's consolidated balance sheets for the years ended December 31, 2012 and 2011, was $0.6 million and $0.7 million, respectively.

As of December 31, 2012, there were 145,146 non-vested share-based compensation arrangements granted under the LTICP that are expected to vest over an average period of 1.6 years. The total unrecognized before-tax compensation cost was $4.9 million for non-vested stock-based compensation arrangements granted under the LTICP.

Common Stock Repurchase Program

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. During 2012 and 2011, Cleco Corporation repurchased 200,000 shares and 400,000 shares of common stock, respectively.

Preferred Stock

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.



Note 8 — Pension Plan and Employee Benefits

In accordance with the authoritative guidance for compensation of retirement benefits, Cleco’s measurement date is the same as its fiscal year end.

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. Cleco’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 2012, Cleco made no discretionary or required contributions to the pension plan. During 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. In January 2013, Cleco Power made $34.0 million in discretionary contributions to the pension plan. 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’s retirees and their dependents are eligible to receive medical, dental, vision, and life insurance benefits (other benefits). Cleco recognizes the expected cost of these other benefits during the periods in which the benefits are earned.

The employee pension plan and other benefits obligation plan assets and funded status at December 31, 2012 and 2011, are presented in the following table.



	PENSION BENEFITS						OTHER BENEFITS
(THOUSANDS)	2012			2011			2012			2011
Change in benefit obligation
Benefit obligation at beginning of year	$	361,986		$	330,342		$	42,680		$	41,444
Service cost	8,312			8,390			1,461			1,532
Interest cost	18,254			17,629			2,239			1,818
Plan participants’ contributions	—			—			1,308			1,251
Actuarial loss	58,109			19,452			2,462			141
Expenses paid	(1,511		)	(1,208		)	—			—
Medicare D	—			—			—			206
Other adjustments ⁽¹⁾	—			—			—			452
Benefits paid	(13,581		)	(12,619		)	(4,581		)	(4,164		)
Benefit obligation at end of year	431,569			361,986			45,569			42,680
Change in plan assets
Fair value of plan assets at beginning of year	312,395			242,513			—			—
Actual return on plan assets	46,738			23,709			—			—
Employer contributions	—			60,000			—			—
Expenses paid	(1,511		)	(1,208		)	—			—
Benefits paid	(13,581		)	(12,619		)	—			—
Fair value of plan assets at end of year	344,041			312,395			—			—
Unfunded status	$	(87,528	)	$	(49,591	)	$	(45,569	)	$	(42,680	)

⁽¹⁾ During 2011, Cleco received $0.5 million for the Early Retiree Reinsurance Program.

The employee pension plan accumulated benefit obligation at December 31, 2012 and 2011, is presented in the following table.



	PENSION BENEFITS
(THOUSANDS)	2012		2011
Accumulated benefit obligation	$	387,776	$	330,193

The authoritative guidelines for compensation of retirement benefits require the disclosure of the net actuarial gains/losses, transition obligations/assets, and prior period service costs included in other comprehensive income as a result of being included as a component of net periodic benefit costs. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2012 and 2011.



	PENSION BENEFITS						OTHER BENEFITS
(THOUSANDS)	2012			2011			2012		2011
Net actuarial loss occurring during year	$	32,177		$	20,389		$	2,461	$	141
Net actuarial loss amortized during year	$	8,346		$	5,556		$	1,479	$	1,010
Transition obligation amortized during year	$	—		$	—		$	20	$	20
Prior service (credit) amortized during year	$	(71	)	$	(71	)	$	—	$	(206	)

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’s other subsidiaries is transferred with a like amount of assets to Cleco Power monthly. The expense of the pension plan related to Cleco’s other subsidiaries for the years ended December 31, 2012, 2011, and 2010 was $2.2 million, $2.1 million, and $1.9 million, respectively.

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 December 31, 2012 and 2011, the current portion of the other benefits liability for Cleco was $3.1 million and $3.1 million, respectively. At December 31, 2012 and 2011, the current portion of the other benefits liability for Cleco Power was $2.9 million and $2.9 million, respectively. The expense related to other benefits reflected in Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2012, 2011, and 2010 was $4.5 million, $3.6 million, and $2.1 million, respectively. Cleco Power had no reduction of other benefits expense during 2012 and 2011 as a result of the Medicare Part D subsidy due to the PPACA eliminating the subsidies by 2013. Cleco Power’s allocated amount of the other benefit liability was $35.3 million and $33.2 million at December 31, 2012 and 2011, respectively.

In March 2010, the President signed the PPACA, a comprehensive health care law, which was upheld by the U.S. Supreme Court on June 28, 2012. While all provisions of the PPACA are not effective immediately, management does not expect the provisions to materially impact the Registrants’ retiree medical unfunded liability and related expenses. Management will continue to monitor this law and its possible impact on the Registrants.

In June 2010, the President signed into law a defined benefit pension funding relief bill. If the Registrants elect to take advantage of the funding relief, required pension contributions would be deferred for at least two years. After the deferral period, required pension contributions would sharply increase. A company electing to take the funding relief would be required to make contributions to the pension plan during the deferral period if it pays excess employee compensation, declares extraordinary dividends, or redeems company stock above certain thresholds. Currently, management does not intend to elect to take the funding relief.

In July 2012, a law was passed that changed the calculation of minimum pension funding requirements. The effect of this law will be to lower minimum funding requirements in the short-term (about two to three years). This law is not expected to impact overall minimum plan contributions over the long-term.

The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows.



	PENSION BENEFITS				OTHER BENEFITS
	2012		2011		2012		2011
Weighted-average assumptions used to determine the benefit obligation as of December 31:
Discount rate	4.19	%	5.08	%	3.54	%	4.51	%
Rate of compensation increase	3.334	%	3.415	%	N/A		N/A



			PENSION BENEFITS						OTHER BENEFITS
	2012		2011		2010		2012		2011		2010
Weighted-average assumptions used to determine the net benefit cost (income) for the year ended December 31:
Discount rate	5.08	%	5.43	%	5.91	%	4.51	%	4.61	%	5.29	%
Expected return on plan assets	6.61	%	7.80	%	7.80	%	N/A		N/A		N/A
Rate of compensation increase	3.373	%	4.119	%	4.265	%	N/A		N/A		N/A

The expected return on plan assets was determined by examining the risk profile of each target category as compared to the expected return on that risk, within the parameters determined by the retirement committee. The result was also compared to the expected rate of return of other comparable plans. In assessing the risk as compared to return profile, historical returns as compared to risk was considered. The historical risk compared to returns was adjusted for the expected future long-term relationship between risk and return. The adjustment for the future risk compared to returns was, in part, subjective and not based on any measurable or observable events. For the calculation of the 2013 periodic expense, Cleco raised the expected long-term return on plan assets to 6.78%. This increase was caused by a slight shift to the upper target of international equity investments as allowed by the investment policy statement. The increase is expected to decrease expense by $0.6 million.

Employee pension plan assets may be invested in publicly traded domestic common stocks, including Cleco Corporation common stock; U.S. Government, federal agency and corporate obligations; an international equity fund, commercial real estate funds; a hedge fund-of-funds; and pooled temporary investments. Investments in securities (obligations of U.S. Government and U.S. Government Agencies, corporate debt, common/collective trust funds, mutual funds, common stocks, and preferred stock) traded on a national securities exchange are valued at the last reported sales price on the last business day of the year.

Real estate funds and the pooled separate accounts are stated at estimated market value based on appraisal reports prepared annually by independent real estate appraisers (members of the American Institute of Real Estate Appraisers). The estimated market value of recently acquired properties is assumed to approximate cost.

The hedge fund-of-funds is stated at fair value based upon financial statements and other financial information reported by the management of the underlying funds. In January 2009, the relationship with the hedge fund-of-funds manager was restructured to redemption status only.

Fair Value Disclosures

The authoritative guidance for fair value measurements and disclosures 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.


•	Level 1 – unadjusted quoted prices in active, liquid markets for the identical asset or liability,



(THOUSANDS)	REAL ESTATE FUNDS		HEDGE FUND OF FUNDS			TOTAL
December 31, 2010	$	14,568	$	3,271		$	17,839
Realized gain	—		17			17
Unrealized gain	1,454		77			1,531
Purchases	327					327
Sales	—		(473		)	(473		)
December 31, 2011	$	16,349	$	2,892		$	19,241
Realized gain	—		2			2
Unrealized gain	734		130			864
Purchases	258		—			258
Sales	—		(437		)	(437		)
December 31, 2012	$	17,341	$	2,587		$	19,928

The market-related value of plan assets differs from the fair value of plan assets by the amount of deferred asset gains or losses. Actual asset returns that differ from the expected return on plan assets are deferred and recognized in the market-related value of assets on a straight-line basis over a five-year period. For 2012, the return on plan assets was 15.2% compared to an expected long-term return of 6.6%. The 2011 return on pension plan assets was 8.7% compared to an expected long-term return of 7.8%.

As of December 31, 2012, the pension plan held no shares of Cleco Corporation common stock. None of the plan participants’ future annual benefits is covered by insurance contracts. In December 2008, Cleco became aware that, through its hedge fund-of-funds manager, a portion of its pension plan assets were invested in the Madoff feeder fund investment, Ascot Fund Limited. In January 2009, Cleco Power elected to liquidate the holdings of the hedge fund-of-funds manager. At December 31, 2012, the fund had $2.6 million remaining to be liquidated. Proceeds from the hedge fund-of-funds manager will be reallocated to the plan’s other investment managers.

Pension Plan Investment Objectives

Cleco Corporation’s retirement committee has established investment performance objectives of the pension plan assets. Over a three- to five-year period, the objectives are for the pension plan’s annualized total return to:


•	Exceed the assumed rate of return on plan assets, and


•	Exceed the annualized total return of a customized index consisting of a mixture of Standard & Poor’s 500 Index; Russell 2500 Index, Morgan Stanley Capital International Europe, Australia, Far East Index; Morgan Stanley Capital International Emerging Markets Index, Barclays Capital Long Credit Index, Barclays Capital Long Government/Credit Index,

National Council of Real Estate Investment Fiduciaries Index, and U.S. Treasury Bills plus 5%.

In order to meet the objectives and to control risk, the retirement committee has established guidelines that the investment managers must follow.

Domestic Equity Portfolios


•	Equity holdings of a single company must not exceed 10% of the manager’s portfolio.


•	A minimum of 25 stocks should be owned.


•	Equity holdings in a single sector should not exceed the lesser of three times the sector’s weighting in the Standard & Poor’s 500 Index or 35% of the portfolio.


•	Equity holdings should represent at least 90% of the portfolio.


•	Marketable common stocks, preferred stocks convertible into common stocks, and fixed income securities convertible into common stocks are the only permissible equity investments.


•	Securities in foreign entities denominated in U.S. dollars are limited to 10%. Securities denominated in currencies other than U.S. dollars are not permitted.


•	The purchase of securities on margin and short sales is prohibited.

International Equity Portfolios

Developed Markets


•	Equity holdings of a single company should not exceed 5% of the manager’s portfolio.


•	A minimum of 30 stocks should be owned.


•	Equity holdings in a single sector should not exceed 35%.


•	A minimum of 50% of the countries within the MSCI EAFE Index should be represented within the portfolio. The allocation to an individual country should not exceed the lesser of 30% or 5 times the country’s weighting within the MSCI EAFE Index.


•	Currency hedging decisions are at the discretion of the investment manager.

Emerging Markets


•	Equity holdings in any single company should not exceed 10% of the manager’s portfolio.


•	A minimum of 30 individual stocks should be owned.


•	Equity holdings of a single industry should not exceed 25%.


•	Equity investments must represent at least 75% of the manager’s portfolio.


•	A minimum of three countries should be represented within the manager’s portfolio.


•	Illiquid securities which are not readily marketable may represent no more than 10% of the manager’s portfolio.


•	Currency hedging decisions are at the discretion of the investment manager.

Fixed Income Portfolio - Long Government/Credit


•	Only U.S. Dollar denominated assets permitted, including U.S. government and agency securities, corporate securities, structured securities, other interest bearing securities, and short-term investments.


•	At least 85% of the debt securities should be investment grade securities (BBB- by Standard & Poor’s or Baa3 by Moody’s) or higher.


•	Debt holdings of a single issue or issuer must not exceed 5% of the manager’s portfolio.


•	Aggregate net notional exposure of futures, options, and swaps must not exceed 30% of the manager’s portfolio. Manager will only execute swaps with counterparties whose credit rating is A2/A or better.


•	Margin purchases or leverage is prohibited.

Fixed Income Portfolio - Long Credit


•	Permitted assets include U.S. government and agency securities, corporate securities, mortgage-backed securities, investment-grade private placements, surplus notes, trust preferred, e-caps, and hybrids, money-market securities, and senior and subordinated debt.


•	At least 90% of securities must be U.S. Dollar denominated.


•	At least 70% of the securities must be investment-grade credit.


•	Maximum position size of 5% or A rated securities and 3% for BBB rated securities.

Real Estate Portfolios


•	Real estate funds should be invested primarily in direct equity positions, with debt and other investments representing less than 25% of the fund.


•	Leverage should be no more than 70% of the market value of the fund.


•	Investments should be focused on existing income-producing properties, with land and development properties representing less than 40% of the fund.

Hedge Fund-of-Funds


•	The fund should be invested in a minimum of 20 individual partnerships.


•	No individual partnership should exceed 10% of the fund-of-funds.


•	The fund should be diversified across several different “styles” of partnerships, including event-driven strategies, fixed income arbitrage and trading, and other arbitrage strategies. The fund generally should not be invested in emerging markets, short-term only, traditional Commodity Trading Advisor’s or derivative-only strategies.

The use of futures and options positions which leverage portfolio positions through borrowing, short sales, or other encumbrances of the Plan’s assets is prohibited:


•	Debt portfolios and hedge fund-of-funds are exempt from the prohibition on derivative use.


•	Execution of target allocation rebalancing may be implemented through short to intermediate-term use of derivatives overlay strategies.


•	The notional value of derivative positions shall not exceed 20% of the total pension fund’s value at any given time.

During 2011, the retirement committee changed the pension plan’s investment policy to create a liability hedging portfolio based on the plan’s funded ratio. The following chart

shows the resulting dynamic asset allocation based on the funded ratio at December 31, 2012:



	PERCENT OF TOTAL PLAN ASSETS*
	MINIMUM		TARGET		MAXIMUM
Return-seeking
Domestic equity			21	%
International equity			18	%
Real estate			8	%
Hedge fund-of-funds			2	%
Total return-seeking	43	%	49	%	53	%
Liability hedging
Fixed income- long government/credit			17	%
Fixed income - long credit			36	%
Total liability hedging	47	%	53	%	57	%
*Minimums and maximums within subcategories not intended to equal total for category.

The estimated impact of future Medicare subsidies did not reduce the January 1, 2012 accumulated postretirement benefit obligation. The estimated impact of future Medicare subsidies reduced the January 1, 2011 accumulated postretirement benefit obligation by $0.4 million. The reduction in other benefit costs for the years ended December 31, 2012 and 2011, are presented in the following table.



	AT DECEMBER 31,
(THOUSANDS)	2012			2011
Components of other benefit costs:
(Increase) reduction in interest cost	$	(8	)	$	(24	)
Reduction in net loss amortization	199			195
Reduction in prior period service cost amortization	—			50
Reduction in net other benefit cost	$	191		$	221

The assumed health care cost trend rates used to measure the expected cost of other benefits was 8.0% in 2013. For 2012 and 2011, the rate used was 9.0%. The rate declines to 5.0% by 2031 and remains at 5.0% thereafter. Assumed health care cost trend rates have a significant effect on the amount reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on other benefits.



	ONE-PERCENTAGE POINT
(THOUSANDS)	INCREASE		DECREASE
Effect on total of service and interest cost components	$	14	$	(34	)
Effect on postretirement benefit obligation	$	318	$	(670	)

The projected benefit payments and projected receipts pursuant to Medicare Part D subsidy, the employee pension plan, and other benefits obligation plan for each year through 2017 and the next five years thereafter are listed in the following table.



(THOUSANDS)	PENSION BENEFITS		OTHER BENEFITS, GROSS		MEDICARE D, RECEIPTS
2013	$	14,905	$	3,060	$	194
2014	$	15,742	$	3,279	$	—
2015	$	16,570	$	3,496	$	—
2016	$	17,562	$	3,680	$	—
2017	$	18,695	$	3,821	$	—
Next five years	$	112,906	$	19,863	$	—

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 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 three-year period ended December 31, 2012. Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.

The SERP’s funded status at December 31, 2012 and 2011, is presented in the following table.



	SERP BENEFITS
(THOUSANDS)	2012			2011
Change in benefit obligation
Benefit obligation at beginning of year	$	46,264		$	42,160
Service cost	1,487			1,566
Interest cost	2,526			2,105
Actuarial loss	11,651			2,529
Benefits paid	(2,506		)	(2,096		)
Benefit obligation at end of year	$	59,422		$	46,264

The SERP’s accumulated benefit obligation at December 31, 2012 and 2011, is presented in the following table.



	SERP BENEFITS
(THOUSANDS)	2012		2011
Accumulated benefit obligation	$	53,350	$	42,410

The authoritative guidelines on compensation for retirement benefits require the disclosure of the net actuarial gains/losses, transition obligations/assets, and prior period service costs included in other comprehensive income as a result of being amortized as a component of net periodic benefit costs. The following table presents those items for the SERP at December 31, 2012 and 2011.



	SERP BENEFITS
(THOUSANDS)	2012		2011
Net actuarial loss occurring during year	$	11,651	$	2,529
Net actuarial loss amortized during year	$	1,764	$	940
Prior service cost amortized during year	$	54	$	54

The authoritative guidelines on compensation for retirement benefits also require the disclosure of the net gains/losses, transition obligations/assets, and prior period service

costs/credit in accumulated other comprehensive income that have not been recognized as components of net periodic benefit costs and the amounts expected to be recognized in 2013. The following table presents those items for SERP for December 31, 2013, 2012, and 2011.



			SERP BENEFITS
(THOUSANDS)	2013		2012		2011
Net actuarial loss	$	2,155	$	25,444	$	15,588
Prior service cost	$	54	$	280	$	334

The components of the net SERP cost for 2012, 2011, and 2010 are as follows.



			SERP BENEFITS
(THOUSANDS)	2012		2011		2010
Components of periodic benefit costs:
Service cost	$	1,487	$	1,566	$	1,531
Interest cost	2,526		2,105		2,122
Amortizations:
Prior period service cost	54		54		54
Net loss	1,764		940		924
Net periodic benefit cost	$	5,831	$	4,665	$	4,631

The measurement date used to determine the SERP benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows.



	SERP
	2012		2011
Weighted-average assumptions used to determine the benefit obligation as of December 31:
Discount rate	4.17	%	4.99	%
Rate of compensation increase	5.00	%	5.00	%



			SERP
	2012		2011		2010
Weighted-average assumptions used to determine the net benefit cost (income) for the year ended December 31:
Discount rate	4.99	%	5.26	%	5.78	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%

Liabilities relating to the SERP are reported on the individual subsidiaries’ financial statements. At December 31, 2012 and 2011, the current portion of the SERP liability for Cleco was $2.5 million and $2.2 million, respectively. At December 31, 2012 and 2011, the current portion of the SERP liability for Cleco Power was $0.8 million and $0.8 million, respectively. The expense related to the SERP reflected on Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2012, 2011, and 2010 was $1.5 million, $1.1 million, and $1.2 million, respectively. Cleco Power’s allocated amount of the SERP liability was $18.4 million and $15.0 million at December 31, 2012 and 2011, respectively.

The projected benefit payments for the SERP for each year through 2017 and the next five years thereafter are shown in the following table.



(THOUSANDS)	2013		2014		2015		2016		2017		NEXT FIVE YEARS
SERP	$	2,503	$	2,531	$	2,774	$	2,997	$	3,078	$	18,279

401(k)

Most employees are eligible to participate in the 401(k) Plan. Under the 401(k) Plan, Cleco makes matching contributions and funds dividend reinvestments with cash. Cleco’s 401(k) Plan expense for the years ended December 31, 2012, 2011, and 2010 is as follows:



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011		2010
401(k) Plan expense	$	4,375	$	3,917	$	3,709

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 was $1.0 million, $0.9 million, and $0.8 million for the years ended December 31, 2012, 2011, and 2010, respectively.



Note 9 — Income Taxes

Cleco

For the years ended December 31, 2012 and 2011, income tax expense was lower than the amount computed by applying the statutory federal rate to income before tax. For the year ended December 31, 2010, income tax expense was higher than the amount computed by applying the statutory federal rate to income before tax. The differences are as follows.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT FOR %)	2012			2011			2010
Income before tax	$	228,975		$	298,745		$	397,889
Statutory rate	35.0		%	35.0		%	35.0		%
Tax at federal statutory rate	$	80,141		$	104,561		$	139,261
Increase (decrease):
Plant differences, including AFUDC flowthrough	(1,222		)	(1,758		)	(7,757		)
Amortization of investment tax credits	(1,180		)	(1,238		)	(1,285		)
State income taxes	(218		)	2,155			11,897
Tax settlement	—			10,782			—
New Markets Tax Credits	(9,261		)	(4,697		)	—
Other	(2,933		)	(6,908		)	382
Total taxes	$	65,327		$	102,897		$	142,498
Effective Rate	28.5		%	34.4		%	35.8		%

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



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Current federal income tax expense	$	47,768		$	77,659		$	75,337
Deferred federal income tax expense	21,724			26,577			56,047
Amortization of accumulated deferred investment tax credits	(1,180		)	(1,238		)	(1,285		)
Total federal income tax expense	$	68,312		$	102,998		$	130,099
Current state income tax (benefit) expense	(1,192		)	2,857			13,572
Deferred state income tax benefit	(1,793		)	(2,958		)	(1,173		)
Total state income tax (benefit) expense	$	(2,985	)	$	(101	)	$	12,399
Total federal and state income tax expense	$	65,327		$	102,897		$	142,498
Items charged or credited directly to shareholders’ equity
Federal deferred	(2,386		)	(8,908		)	2,210
State deferred	(385		)	(1,439		)	357
Total tax expense (benefit) from items charged directly to shareholders’ equity	$	(2,771	)	$	(10,347	)	$	2,567
Total federal and state income tax expense	$	62,556		$	92,550		$	145,065

The $7.6 million change in total tax benefit from items charged directly to shareholders’ equity in 2012 compared to 2011 was primarily due to the tax effect of other post-employment benefit adjustments booked to accumulated other comprehensive income and interest rate derivatives.

Cleco recognizes the amortization of the NMTC Fund investment and the related interest on the liability as a component of current tax expense. The amount of amortization and interest recognized in 2012, 2011, and 2010 was $38.6 million, $27.5 million, and $44.1 million, respectively.

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2012 and 2011 was comprised of the following.



	AT DEC. 31,
(THOUSANDS)	2012			2011
Depreciation and property basis differences	$	(822,831	)	$	(594,135	)
Net operating loss carryforward	139,036			18,542
New Markets Tax Credits	82,584			36,398
Fuel costs	(9,400		)	(6,135		)
Deferred carrying charges	1,369			11,327
SERP – other comprehensive income	19,392			16,621
Regulated operations regulatory liability, net	(75,046		)	(83,965		)
Postretirement benefits other than pension	(2,275		)	(9,486		)
Other	(16,468		)	(9,844		)
Accumulated deferred federal and state income taxes	$	(683,639	)	$	(620,677	)

Valuation Allowance

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized. As of December 31, 2012, Cleco had a deferred tax asset resulting from New Markets Tax Credit carryforwards of $78.8 million. If the New Markets Tax Credit carryforwards are not utilized, they will begin to expire in 2029. Management considers it more likely than not that all deferred tax assets related to New Markets Tax Credit carryforwards will be realized; therefore, no valuation allowance has been recorded.

Net Operating Losses

Cleco Corporation filed its 2011 federal income tax return and recorded a $477.7 million increase to its net operating loss carryforward in 2012. The increase was primarily related to a tax accounting method change for bonus depreciation associated with Madison Unit 3. On July 3, 2012, Cleco and Cleco Power filed a PLR request with the IRS in order to determine the appropriateness and timing of the special allowance for depreciation for Madison Unit 3. On December 28, 2012, Cleco received a favorable PLR from the IRS, consistent with the request allowing for the additional first year depreciation deduction in the amount of $411.0 million as reflected on Cleco Corporation’s 2011 federal income tax return. Cleco considers it more likely than not that these income tax losses generated on the 2011 income tax return will be utilized to reduce future income taxes and Cleco expects to utilize the entire net operating loss carryforward within the statutory deadlines.

Cleco Power

Income tax expense is lower than the amount computed by applying the statutory rate to income before tax, as follows.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT FOR %)	2012			2011			2010
Income before tax	$	214,981		$	212,244		$	222,512
Statutory rate	35.0		%	35.0		%	35.0		%
Tax at federal statutory rate	$	75,243		$	74,285		$	77,879
Increase (decrease):
Plant differences, including AFUDC flowthrough	(1,222		)	(1,758		)	(7,757		)
Amortization of investment tax credits	(1,180		)	(1,238		)	(1,285		)
State income taxes	(705		)	(853		)	5,798
Other	(4,003		)	(1,027		)	472
Total tax expense	$	68,133		$	69,409		$	75,107
Effective Rate	31.7		%	32.7		%	33.8		%

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



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Current federal income tax expense	$	13,008		$	23,347		$	35,132
Deferred federal income tax expense	59,008			47,763			40,237
Amortization of accumulated deferred investment tax credits	(1,180		)	(1,238		)	(1,285		)
Total federal income tax expense	$	70,836		$	69,872		$	74,084
Current state income tax (benefit) expense	(1,060		)	1,691			6,704
Deferred state income tax benefit	(1,643		)	(2,154		)	(5,681		)
Total state income tax (benefit) expense	$	(2,703	)	$	(463	)	$	1,023
Total federal and state income taxes	$	68,133		$	69,409		$	75,107
Items charged or credited directly to shareholders’ equity
Federal deferred	20			(8,580		)	2,532
State deferred	3			(1,386		)	409
Total tax expense (benefit) from items charged directly to shareholders’ equity	$	23		$	(9,966	)	$	2,941
Total federal and state income tax expense	$	68,156		$	59,443		$	78,048

The $10.0 million change in total tax benefit from items charged directly to shareholders’ equity in 2012 compared to 2011 was primarily due to the tax effect of other post-

employment benefit adjustments booked to accumulated other comprehensive income and interest rate derivatives.

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2012 and 2011, was comprised of the following.



	AT DEC. 31,
(THOUSANDS)	2012			2011
Depreciation and property basis differences	$	(804,133	)	$	(592,634	)
Net operating loss carryforward	127,742			16,390
Fuel costs	(9,389		)	(6,125		)
Deferred carrying charges	1,369			11,327
SERP - other comprehensive income	11,961			11,984
Regulated operations regulatory liability, net	(75,046		)	(83,965		)
Postretirement benefits other than pension	(13,442		)	(22,461		)
Other	2,455			9,478
Accumulated deferred federal and state income taxes	$	(758,483	)	$	(656,006	)

Valuation Allowance

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

Net Operating Losses

Cleco Corporation filed its 2011 federal income tax return and recorded a $477.7 million increase to its net operating loss carryforward in 2012. The increase was primarily related to a tax accounting method change for bonus depreciation associated with Madison Unit 3. On July 3, 2012, Cleco and Cleco Power filed a PLR request with the IRS in order to determine the appropriateness and timing of the special allowance for depreciation for Madison Unit 3. On December 28, 2012, Cleco received a favorable PLR from the IRS, consistent with the request allowing for the additional first year depreciation deduction in the amount of $411.0 million as reflected on Cleco Corporation’s 2011 federal income tax return.Cleco Power considers it more likely than not that these income tax losses generated on the 2011 income tax return will be utilized to reduce future income taxes and Cleco Power expects to utilize the entire net operating loss carryforward within the statutory deadlines.

Uncertain Tax Positions

Cleco classifies 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 Consolidated Balance Sheets and Statements of Income, are shown in the following tables:



	AT DEC. 31,
(THOUSANDS)	2012		2011
Interest payable
Cleco Corporation	$	1,420	$	13,843
Cleco Power	$	3,358	$	17,327

The interest payable reflects the amount of interest anticipated to be paid to taxing authorities. These amounts do not included any offset for amounts that may be recovered from customers under existing rate orders. The amounts expected to be recoverable from Cleco Power’s customers under existing rate orders at December 31, 2012 and

December 31, 2011, are $6.2 million and $9.3 million, respectively.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Interest charges
Cleco Corporation	$	(9,223	)	$	(27,175	)	$	3,930
Cleco Power	$	(11,648	)	$	2,116		$	(5,448	)

The interest charges reflect the amount of interest anticipated to be paid to taxing authorities. These amounts do not include any offset for the amounts that may be recovered from customers under existing rate orders. The amounts expected to be recoverable from Cleco Power’s customers under existing rate orders at December 31, 2012 and December 31, 2011, are $3.0 million and $1.4 million, respectively.

The total liability for unrecognized tax benefits for Cleco and Cleco Power at December 31, 2012, 2011, and 2010 is shown in the following table:



Cleco
(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at January 1, 2010	$	129,235
Reduction for tax positions of current period	(5,738		)
Additions for tax positions of prior years	511
Reduction for tax positions of prior years	(6,146		)
Reduction for settlement with tax authority	(15,077		)
Reduction for lapse of statute of limitations	—
Balance at December 31, 2010	$	102,785
Reduction for tax positions of current period	(4,129		)
Additions for tax positions of prior years	11,031
Reduction for tax positions of prior years	(8,670		)
Reduction for settlement with tax authority	(44,782		)
Reduction for lapse of statute of limitations	—
Balance at December 31, 2011	$	56,235
Reduction for tax positions of current period	—
Additions for tax positions of prior years	—
Reduction for tax positions of prior years	—
Reduction for settlement with tax authority	(53,109		)
Reduction for lapse of statute of limitations	—
Balance at December 31, 2012	$	3,126



Cleco Power
(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
Balance at January 1, 2010	$	84,360
Reduction for tax positions of current period	(2,202		)
Additions for tax positions of prior years	3
Reduction for tax positions of prior years	(6,109		)
Reduction for settlement with tax authority	(15,077		)
Reduction for lapse of statute of limitations	—
Balance at December 31, 2010	$	60,975
Reduction for tax positions of current period	(4,018		)
Additions for tax positions of prior years	4,271
Reduction for tax positions of prior years	(8,670		)
Reduction for settlement with tax authority	—
Reduction for lapse of statute of limitations	—
Balance at December 31, 2011	$	52,558
Reduction for tax positions of current period	—
Additions for tax positions of prior years	—
Reduction for tax positions of prior years	—
Reduction for settlement with tax authority	(52,310		)
Reduction for lapse of statute of limitations	—
Balance at December 31, 2012	$	248

The federal income tax years that remain subject to examination by the IRS are 2004 through 2011. The Louisiana state income tax years that remain subject to examination by the Louisiana Department of Revenue are 2002 through 2011. In December 2010, Cleco deposited $52.2 million with the IRS associated with the years currently under audit. 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. At December 31, 2012, Cleco had $60.4 million deposited with the IRS, of which Cleco received a refund of tax and interest in January 2013 from the IRS of $42.3 million relating to tax years 2001 through 2008.

Cleco is currently under audit by the IRS for the years 2004 through 2009. Cleco estimates that it is reasonably possible that the balance of unrecognized tax benefits as of December 31, 2012, could decrease by a maximum of $0.6 million for Cleco and the balance for Cleco Power would be unchanged in the next 12 months as a result of reaching a settlement with the IRS and state tax authorities. The settlements could involve the payment of additional taxes, the adjustment of deferred taxes, and/or the recognition of tax benefits, which may have an effect on Cleco’s effective tax rate.

Cleco classifies income tax penalties as a component of other expenses. During 2012, 2011, and 2010, the amount of penalties recognized was immaterial.



Note 10 — Disclosures about Segments

Cleco

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 2012 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. For information on these services, see Note 15 — “Affiliate Transactions.”

Cleco Power

Cleco Power is a vertically integrated, regulated electric utility operating within Louisiana and is viewed as one unit by management. Discrete financial reports are prepared only at the company level. This approach is consistent with the standards applicable to segment reporting as defined by the authoritative guidance on segment reporting.



Note 11 — Electric Customer Credits

On October 31, 2011, Cleco Power filed its report for the 12 months ended June 30, 2011, which indicated that $5.1 million was due to be returned to customers. On July 18, 2012, the LPSC approved the monitoring report for the 12 months ended June 30, 2011. Cleco Power issued refunds for this filing on customers’ bills during the third quarter of 2012. On October 31, 2012, Cleco Power filed its report for the 12 months ended June 30, 2012. As of December 31, 2012, Cleco Power had accrued $1.7 million to be returned to customers based on the results for the 12-month period ended June 30, 2012. The ultimate amount of any customer refund is subject to LPSC approval. The accrual for estimated electric customer credits reflected on Cleco Corporation and Cleco Power’s Consolidated Balance Sheets at December 31, 2012 and 2011, was $4.2 million and $7.3 million, respectively.



Note 12 — 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 Corporation and Cleco Power’s Consolidated Balance Sheets. The revenue and expenses (excluding income taxes) of this entity are netted and reported as equity income or loss from investees on Cleco Corporation and Cleco Power’s Consolidated Statements of Income.

Prior to April 30, 2011, Cleco 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 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. Following the transaction, ongoing operations at Acadia are minimal, relating only to settling accounts receivable, accounts payable, and servicing indemnifications 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. For more information on the Acadia Unit 2 transaction, see Note 18 — “Acadia Transactions — Acadia Unit 2.”

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



(THOUSANDS)	AT DEC. 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 YEAR ENDED DEC. 31, 2011*
Operating revenue	$	5,227
Operating expenses	5,914
Gain on sale of assets	71,422
Other income	929
Income before taxes	$	71,664

* 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 more information on Acadia’s indemnification liability, see Note 14 — “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 recorded on APH’s financial statements were $24.0 million. For the year ended December 31, 2010, tax expenses recorded on APH’s financial statements were $14.7 million.

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 more information on the Entergy Louisiana indemnification, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Disclosures about Guarantees.”

Equity Method VIEs

Equity investment in investees at December 31, 2012, primarily represented Cleco Power’s $14.5 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 YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011			2010
Cajun	$	—	$	62,053		$	38,848
Subsidiaries less than 100% owned by Innovations LLC	—		(3		)	1
Total equity income	$	—	$	62,050		$	38,849

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 December 31, 2012, consisted of its

equity investment of $14.5 million. The following table presents the components of Cleco Power’s equity investment in Oxbow.



	AT DEC. 31,
INCEPTION TO DATE (THOUSANDS)	2012		2011
Purchase price	$	12,873	$	12,873
Cash contributions	1,659		1,659
Total equity investment in investee	$	14,532	$	14,532

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.



	AT DEC. 31,
(THOUSANDS)	2012		2011
Oxbow’s net assets/liabilities	$	29,065	$	29,065
Cleco Power’s 50% equity	$	14,532	$	14,532
Cleco’s maximum exposure to loss	$	14,532	$	14,532

The following tables contain summarized financial information for Oxbow.



	AT DEC. 31,
(THOUSANDS)	2012		2011
Current assets	$	1,814	$	1,711
Property, plant, and equipment, net	23,029		23,339
Other assets	4,248		4,128
Total assets	$	29,091	$	29,178
Current liabilities	$	26	$	40
Other liabilities	—		73
Partners’ capital	29,065		29,065
Total liabilities and partners’ capital	$	29,091	$	29,178



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011		2010
Operating revenue	$	1,126	$	1,781	$	931
Operating expenses	1,126		1,781		931
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 13 — Operating Leases

The following is a schedule of operating leases that Cleco maintains in the ordinary course of business activities. The majority of Cleco’s operating leases are for line construction and operating vehicles and for railcars for coal deliveries, which are utilized by Cleco Power. The remaining leases provide for office and operating facilities and office equipment. These leases have various terms and expiration dates. The following table is a summary of expected operating lease payments for Cleco and Cleco Power for the years indicated.



			YEAR ENDING DEC. 31,
(THOUSANDS)	CLECO		CLECO POWER		TOTAL
2013	$	10	$	9,333	$	9,343
2014	4		9,977		9,981
2015	—		9,909		9,909
2016	—		9,575		9,575
2017	—		11,427		11,427
Thereafter	—		3,757		3,757
Total operating lease payments	$	14	$	53,978	$	53,992

Cleco Power has vehicle leases with two vendors. The leases with the first vendor have terms that vary from five to ten years. The leases can be extended on a month-by-month basis at the end of the term. The lease payments are fixed amounts for the term of the lease. These leases include distribution line construction and maintenance vehicles. Most of these leases are considered operating leases, whereby Cleco returns the vehicle to the vendor at the end of the lease with no further obligation (assuming certain turn-in provisions are met). However, five of the leases are TRAC (terminal rent adjustment clause) leases whereby the vendor is guaranteed a certain residual value at lease-end. For each of the years ended December 31, 2012, 2011, and 2010, lease expense of $1.0 million was recognized.

The leases with the second vendor vary in term from five to seven years. The lease payments are fixed amounts for the term of the lease, based on a percentage of acquisition cost. These leases include distribution line construction and maintenance vehicles, as well as vehicles used throughout the company in generation, distribution, and transmission. These leases are TRAC leases, with a specific residual value guaranteed to the vendor. For the years ended December 31, 2012, 2011, and 2010, operating lease expense of $0.4 million, $0.4 million, and $0.2 million was recognized, respectively.

The operating leases for office and operating facilities and office equipment have lease terms from one to five years. For each of the years ended December 31, 2012, 2011, and 2010, operating lease expense of less than $0.1 million was recognized.

The railcar leases are divided into two groups. The first group has 120 railcars, and the lease expires on March 31, 2021. The second group has 121 railcars, and the lease expires on March 31, 2017. Cleco Power pays a monthly rental fee per car. For each of the years ended December 31, 2012, 2011, and 2010, operating lease expense of $1.1 million was recognized. The railcar leases do not contain contingent rent payments. For more information regarding operating leases, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Other Commitments — CBL Capital Corporation.”



Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

Devil’s Swamp

liability on those PRPs for the cost of response to the contamination. 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, but no final determination has been made. The PRPs began discussing a potential proposal to the EPA in February 2008. The EPA issued a Unilateral Administrative Order to PRP’s Clean Harbors, Inc. and Baton Rouge Disposal to Conduct an RI/FS on December 3, 2009. The Tier 1 and Tier 2 parts of the study were complete as of June 25, 2012. Currently, the study/remedy selection task continues. Therefore, management is unable to determine how significant Cleco’s share of the costs associated with the RI/FS and possible response action at the facility site, if any, may be and whether or not this will have a material adverse effect on the Registrants’ results of operations, financial condition, or cash flows.

Discrimination Complaints

In December 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. In July 2010, the plaintiffs moved to add an additional current employee alleging that Cleco had discriminated on the basis of race. The additional plaintiff seeks compensation of no less than $2.5 million and became the 13th plaintiff. In April 2011, Cleco entered into a settlement with one of the current employees which resulted in a dismissal of one of the 13 cases with prejudice. In September 2011, the Court ruled on Cleco’s summary judgment motions. The judge granted and denied the motions in part, with the end result that 11 out of 12 of the remaining plaintiffs have at least one claim remaining. The Court has severed the cases of the 11 remaining plaintiffs for further proceedings, and, if necessary, the trial. Additional depositions were completed in February 2012, and Cleco filed a summary judgment motion in each of the remaining 11 cases in March 2012. Each of such motions was fully briefed and submitted for decision by May 2012. On February 12, 2013, the court ruled on the second motion for summary judgment in one of the eleven cases and such case was dismissed with prejudice. None of the remaining ten cases has been set for trial.

On July 31, 2012, nine plaintiffs in the pending discrimination suits described above filed a new lawsuit in the same federal court in Shreveport alleging that Cleco and its Chief Executive Officer retaliated against them for pursuing their discrimination claims by directly writing them an offer of settlement that contained allegedly intimidating threats. The nine plaintiffs consist of six current employees and three former employees. The plaintiffs filed an amended complaint on August 29, 2012, stating that such settlement letters were delivered to legal counsel for each of the plaintiffs and not directly to the plaintiffs. On September 6, 2012, Cleco filed a

motion to dismiss the lawsuit. On November 19, 2012, the U.S. Magistrate recommended that Cleco’s motion be granted and that the lawsuit be dismissed with prejudice. On January 23, 2013, the motion to dismiss was granted and the retaliation claims were dismissed with prejudice.

City of Opelousas

In March 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 claim that Cleco Power owes customers in Opelousas more than $30.0 million as a result of the alleged overcharges. 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. In May 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. In September 2010, the federal court remanded both cases to the state court in which they were originally filed for further proceedings. In January 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). In September 2011, the Third Circuit denied both appeals. In October 2011, both Cleco and the LPSC appealed the Third Circuit’s ruling to the Louisiana Supreme Court. In November 2011, the Louisiana Supreme Court granted the appeals and remanded the case to the Third Circuit for further briefing, argument, and opinion. In February 2011, the administrative law judge (ALJ) in the LPSC proceeding ruled that the LPSC has jurisdiction to decide the claims raised by the class action plaintiffs. At its December 2011, Business and Executive Session, the LPSC adopted the ALJ’s recommendation that Cleco be granted summary judgment in its declaratory action finding that Cleco’s ratepayers in the City of Opelousas have been served under applicable rates and policies approved by the LPSC and Cleco’s Opelousas ratepayers have not been overcharged in connection with

LPSC rates or ratemaking. On January 30, 2012, the class action plaintiffs filed their appeal of such LPSC decision to the 19th Judicial District Court for Baton Rouge Parish, State of Louisiana. On February 15, 2012, the Third Circuit ruled that the State Court, and not the LPSC, has jurisdiction to hear the case. On March 15, 2012, Cleco Power appealed the Third Circuit’s ruling to the Louisiana Supreme Court asking that it overturn the Third Circuit decision and conform the LPSC’s exclusive jurisdiction over this matter. The LPSC also appealed the Third Circuit’s ruling to the Louisiana Supreme Court in March 2012. On May 18, 2012, the Louisiana Supreme Court granted the writ application of Cleco Power and the LPSC and set the matter for further briefing on the merits of the jurisdiction question raised in the writ application. Such briefing was completed during the third quarter of 2012 and the Louisiana Supreme Court heard oral arguments on September 7, 2012. On December 4, 2012, the Louisiana Supreme Court issued its opinion accepting Cleco’s jurisdictional arguments and dismissed the state court claims. The only matter remaining is before the 19th Judicial District Court to review the LPSC ruling in Cleco’s favor that it had properly charged the ratepayers of Opelousas. In view of the uncertainty of the claims, management is not able to predict or give a reasonable estimate of the possible range of liability, if any, of these claims. However, if it is found that Cleco Power overcharged customers resulting in a refund, any such refund could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.

LPSC Audits

Fuel Audit

The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through an LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. The LPSC FAC General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit of FAC filings will be performed not less than every other year. In March 2009, the LPSC initiated an audit of FAC filings for the years 2003 through 2008. The total amount of fuel expenses included in the audit was approximately $3.26 billion. In February 2012, the LPSC Staff’s consultant issued an audit report recommending a cost disallowance of approximately $0.4 million plus interest for these filing years. The report was approved by the LPSC on July 18, 2012. Cleco Power made refunds of $0.4 million plus interest to customers during the September 2012 billing cycle. Cleco Power has FAC filings for the years 2009 through 2012 that remain subject to audit.

Environmental Audit

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 December 31, 2012, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters is approximately $4.2 million.

Off-Balance Sheet Commitments



			AT DEC. 31, 2012
(THOUSANDS)	FACE AMOUNT		REDUCTIONS		NET 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

Disclosures about Guarantees

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 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.

residual value of less than $0.1 million will remain. At December 31, 2012, Acadia had an indemnification liability of $0.4 million, which represents the risk of payment, as a contingent sale obligation recorded on Cleco’s Consolidated Balance Sheet. Acadia recognized income of $7.2 million for the year ended December 31, 2012, and $0.9 million income for the year ended December 31, 2011, primarily due to the contractual expiration of the underlying indemnification. APH recognized no income for the year ended December 31, 2012 and $0.9 million income for the year ended December 31, 2011, primarily due to the contractual expiration of the underlying indemnification.


•	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.

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 Amended Lignite Mining Agreement, 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 December 31, 2012, 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.

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.

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

Long-Term Purchase Obligations

Cleco Corporation had no unconditional long-term purchase obligations at December 31, 2012. Cleco Power has several unconditional long-term purchase obligations related to the purchase of coal, petroleum coke, limestone, and energy delivery facilities. The aggregate amount of payments required under such obligations at December 31, 2012, is as follows.



YEAR ENDING DEC. 31,	(THOUSANDS)
2013	$	66,657
2014	36,425
2015	14,182
2016	15,673
2017	16,375
Thereafter	$	15,424
Total long-term purchase obligations	$	164,736

Payments under these agreements for the years ended December 31, 2012, 2011, and 2010 were $59.2 million, $97.4 million, and $56.7 million, respectively.

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 was completed and the tolling agreement was terminated. For more information regarding the Cleco Power transaction, see Note 18 — “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 more information regarding this guarantee, please refer to “— Off-Balance Sheet Commitments” above. On April 29, 2011, the transaction was completed 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 more information on the Acadia Unit 2 transaction, see Note 18 — “Acadia Transactions — Acadia Unit 2.”

General Electric Services Corporation

Cleco Power has entered into an operating lease agreement that expires in March 2017, with General Electric Equipment Services Corporation for leasing railcars in order to transport coal to Rodemacher Unit 2. The lease contained a provision for early termination, along with an associated termination fee that could have been exercised by Cleco Power in December 2010. Cleco Power did not exercise this right.

NMTC Fund

In 2008, Cleco Corporation and US Bancorp Community Development (USBCDC) formed the NMTC Fund. Cleco has a 99.9% membership interest in the NMTC Fund and USBCDC has a 0.1% interest in the NMTC Fund. The purpose of the NMTC 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.The NMTC Fund was later amended to include renewable energy investments. The majority of the energy investments qualify for grants under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009. The tax benefits received from the NMTC Fund reduce the federal income tax obligations of Cleco Corporation. In total, Cleco Corporation will contribute $285.5 million of equity contributions to the NMTC Fund and will receive at least $303.7 million in the form of tax credits, tax losses, capital gains/losses, earnings and cash over the life of the investment, which ends in 2017. The $18.2 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
2013	$	50,822
2014	39,059
2015	12,975
2016	11,890
2017	3,292
Total	$	118,038

Of the $118.0 million, $50.8 million is due to be paid within the next 12 months. Due to the right of offset, the investment and associated debt are presented on Cleco’s 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 December 31, 2012, was $98.9 million. The amount of tax benefits received but not utilized as of December 31, 2012, was $90.0 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 following table 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:	$	118,038
Less: unamortized discount	10,513
Total	$	107,525

The gross investment amortization expense will be recognized over a ten-year period, with five years remaining under the new amendment, using the cost method in accordance with the authoritative guidance for investments. The grants received under Section 1603 and other cash reduce the basis of the investment. Periodic amortization of the investment and the deferred taxes generated by the basis reduction temporary difference are included as components of income tax expense.

Fuel Transportation Agreement

In October 2007, Cleco Power entered into an agreement that met the accounting definition of a capital lease for barges in order to transport petroleum coke and limestone to Madison Unit 3.

On December 28, 2012, Cleco Power entered into an amended agreement for 42 dedicated barges. The amended agreement continues to meet the accounting definition of a capital lease.

Under the amended agreement the barge lease rate contains both fixed and variable components, of which the latter is adjusted annually per the Producer Price Index (PPI) for executory costs. The initial term of this agreement is from the date of the amendment until August 31, 2017. The term of this agreement will automatically renew for successive periods of two years each unless written notice is provided by either party. After September 2014, Cleco Power has the option to purchase any or all of the dedicated barges. The amended agreement contains a provision for early termination upon the occurrence of any one of four specified cancellation events.

Under both the original agreement and the amended agreement, if the barges are idle, the lessor is required to attempt to sublease the barges to third parties, with the revenue reducing Cleco Power's lease payment. During the year ended December 31, 2011, Cleco Power paid approximately $4.7 million in lease payments and did not receive any revenue from subleases. During the year ended December 31, 2012, Cleco Power paid approximately $4.3 million in lease payments and received approximately $0.4 million in revenue from subleases.

The following is an analysis of the leased property under capital leases by major classes:



	AT DEC. 31,
CLASSES OF PROPERTY (THOUSANDS)	2012		2011
Barges	$	11,350	$	22,050
Less: accumulated amortization	—		6,567
Net capital leases	$	11,350	$	15,483

The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2012.



(THOUSANDS)
Years ending December 31,
2013	$	3,725
2014	3,725
2015	3,725
2016	3,735
2017	2,480
Total minimum lease payments	$	17,390
Less: executory costs	4,347
Net minimum lease payments	$	13,043
Less: amount representing interest	1,693
Present value of net minimum lease payments	$	11,350
Current liabilities	$	2,171
Non-current liabilities	$	9,179

During the years ended December 31, 2012 and 2011, Cleco Power incurred immaterial amounts of contingent rent under the barge agreement related to the increase in the PPI.

Other

Cleco has accrued for liabilities related to third parties and employee medical benefits.

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.

Other

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.



Note 15 — Affiliate Transactions

Cleco

Cleco has entered into service agreements with affiliates to receive and to provide goods and professional services. Goods and services received by Cleco primarily involve services provided by Support Group. Support Group provides joint and common administrative support services in the areas of information technology; finance, cash management, accounting and auditing; human resources; investor relations; project consulting; risk management; strategic and corporate development; legal, ethics and regulatory compliance; facilities management; supply chain and inventory management and other administrative services. Midstream provides electric power plant operations and maintenance expertise. Prior to December 24, 2011, electric power plant operations and maintenance expertise services were provided by Generation Services.

Cleco is charged the higher of management’s estimated fair market value or fully loaded costs for goods and services provided by Cleco Power. Cleco, with the exception of Support Group, charges Cleco Power the lower of management’s estimated fair market value or fully loaded costs for goods and services provided in accordance with service agreements. Support Group charges only fully loaded costs.

In accordance with authoritative guidance, all charges from affiliates were eliminated in Cleco’s Consolidated Statements of Income for the years ending December 31, 2012, 2011, and 2010. Also, all affiliate revenue was eliminated in Cleco’s Consolidated Statement of Income for the year ended December 31, 2012.

The following table is a summary of affiliate revenue included in Cleco’s Consolidated Statements of Income.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011		2010
Acadia	$	—	$	202	$	1,564
Total	$	—	$	202	$	1,564

At December 31, 2012 and 2011, Cleco had no affiliate balances that were payable to or receivable from its non-consolidated affiliates.

Cleco Power

Cleco Power has entered into service agreements with affiliates to receive and to provide goods and professional

services. Charges from affiliates included in Cleco Power’s Consolidated Statements of Income primarily involve services provided by Support Group in accordance with service agreements and power purchased from Evangeline. Support Group provides joint and common administrative support services in the areas of information technology; finance, cash management, accounting and auditing; human resources; corporate communications; project consulting; risk management; strategic and corporate development; legal, ethics and regulatory compliance; facilities management; supply chain and inventory management and other administrative services. For information on the power purchased from Evangeline, see Note 17 — “Evangeline Transactions.”

Affiliates, with the exception of Support Group, charge Cleco Power the lower of management’s estimated fair market value or fully loaded costs for goods and services provided in accordance with service agreements. Support Group charges only fully loaded costs. The following table is a summary of charges from each affiliate included in Cleco Power’s Consolidated Statements of Income.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Support Group
Other operations	$	43,171		$	43,124		$	39,633
Maintenance	$	1,437		$	1,625		$	1,650
Taxes other than income taxes	$	(54	)	$	(1	)	$	(5	)
Other expenses	$	932		$	1,244		$	1,050
Evangeline
Purchased power expense	$	25,559		$	—		$	—
Other expenses	$	—		$	4		$	—
Diversified Lands
Other expenses	$	—		$	82		$	19

The majority of the services provided by Cleco Power relates to the lease of office space to Support Group. Cleco Power charges affiliates the higher of management’s estimated fair market value or fully loaded costs for goods and services provided in accordance with service agreements.

The following table is a summary of revenue received from affiliates included in Cleco Power’s Consolidated Statements of Income.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011		2010
Affiliate revenue
Support Group	$	1,335	$	1,349	$	1,332
Midstream	14		14		13
Evangeline	23		26		26
Total affiliate revenue	$	1,372	$	1,389	$	1,371
Other income
Cleco Corporation	$	—	$	10	$	118
Support Group	—		—		4
Evangeline	11		12		24
Diversified Lands	17		124		122
Perryville	6		4		5
Attala	6		5		4
Total other income	$	40	$	155	$	277
Total	$	1,412	$	1,544	$	1,648

Cleco Power had the following affiliate receivable and payable balances associated with the service agreements.



					AT DEC. 31,
			2012				2011
(THOUSANDS)	ACCOUNTS RECEIVABLE		ACCOUNTS PAYABLE		ACCOUNTS RECEIVABLE		ACCOUNTS PAYABLE
Cleco Corporation	$	139	$	1,140	$	18	$	827
Support Group	2,777		7,528		2,207		8,066
Midstream	27		5		24		5
Evangeline	6		1,401		12		214
Diversified Lands	42		23		20		3
Acadia	—		—		124		196
Total	$	2,991	$	10,097	$	2,405	$	9,311

During 2012, 2011, and 2010, Cleco Power made $58.0 million, $130.0 million, and $150.0 million of distribution payments to Cleco Corporation, respectively.

During 2010, Cleco Power received $225.7 million in non-cash equity contributions from Cleco Corporation relating to Acadia Unit 1. Cleco Power received no equity contributions from Cleco Corporation in 2012 or 2011.

Affiliates that participate in the defined benefit pension plan sponsored by Cleco Power transfer their liability and an equal amount of cash on a periodic basis to Cleco Power. The following table shows the amounts transferred by affiliates during 2012 and 2011.



	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012		2011
Support Group	$	1,881	$	1,844
Generation Services	—		220
Midstream	280		37
Total	$	2,161	$	2,101



Note 16 — Intangible Asset

During 2008, Cleco Katrina/Rita acquired a $177.5 million intangible asset which includes $176.0 million for the right to bill and collect storm recovery charges from customers of

Cleco Power and $1.5 million of financing costs. This intangible asset is expected to have a life of 12 years, but could have a life of up to 15 years depending on the time period required to collect the required amount from Cleco Power’s customers. The intangible asset’s expected amortization expense is based on the estimated collections from Cleco Power’s customers. At the end of its life, this asset will have no residual value. During the years ended December 31, 2012, 2011, and 2010, Cleco Katrina/Rita recognized amortization expense of $13.1 million, $11.8 million, and $11.7 million, respectively, based on actual collections.

The following table summarizes the intangible asset balance as of December 31, 2012 and 2011.



	AT DEC. 31,
(THOUSANDS)	2012		2011
Gross carrying amount	$	177,537	$	177,537
Accumulated amortization	56,992		43,942
Intangible asset	$	120,545	$	133,595

The following table summarizes the amortization expense expected to be recognized during each year through 2017 and thereafter.



(THOUSANDS)
Expected amortization expense
2013	$	14,026
2014	$	14,931
2015	$	15,876
2016	$	16,864
2017	$	18,009
Thereafter	$	40,839



Note 17 — 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 enter into the Evangeline 2010 Tolling Agreement, effective March 1, 2010. The Evangeline 2010 Tolling Agreement expired on December 31, 2011. The other significant terms of the Evangeline Restructuring Agreement were:


•	the tolling agreement was a market-based tolling agreement, for Coughlin Units 6 and 7, ending on December 31, 2011, with an option for JPMVEC to extend the term through December 31, 2012. The agreement also gave 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, and


•	JPMVEC returned Cleco Corporation’s $15.0 million letter of credit issued under the Evangeline Tolling Agreement and the letter of credit was canceled.

The termination of the Evangeline Tolling Agreement was considered a termination of an operating lease and a triggering event requiring an asset impairment analysis.

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.

Due to the expiration of the Evangeline 2010 Tolling Agreement on December 31, 2011, Coughlin’s capacity and energy was available to Midstream beginning January 1, 2012. Evangeline was one of the successful bidders in Cleco Power’s RFP for short-term 2012 resources beginning January 1, 2012, and began providing 250 MW of capacity and energy to Cleco Power under a tolling agreement through April 30, 2012. In addition to Cleco Power’s RFP referenced above, in December 2011, Evangeline was also notified that Cleco Power selected its proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power RFP for contractual resources beginning in May 2012. The proposal was for a 730-MW product beginning May 1, 2012, and ending April 30, 2015. The definitive agreement between Evangeline and Cleco Power was executed in January 2012 and was approved by the LPSC in March 2012 and FERC in April 2012. On October 30, 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 Long-Term RFP, subject to further due diligence, the completion of definitive agreements, and regulatory approvals from the LPSC and FERC. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. The transaction is expected to close as early as the fourth quarter of 2013, after completion of regulatory approvals.



Note 18 — 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 19 — Storm Restoration

On August 28, 2012, Hurricane Isaac made landfall in south Louisiana as a Category 1 hurricane, causing power outages to approximately 95,000, or 34%, of Cleco Power’s electric customers and affecting Cleco Power’s entire service territory. By September 2, 2012, power was restored to 100% of customers who could receive power.

The current estimate of the cost of restoration for Hurricane Isaac is approximately $24.0 million. The damage to equipment from the storm required replacement, as well as repair of existing assets. Therefore, the balance sheets of Cleco and Cleco Power reflect the capitalization of approximately 56% of the restoration costs recorded at December 31, 2012, or approximately $13.6 million. The remaining cost was offset against Cleco Power’s existing funded storm damage reserve.



Note 20 — Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss are summarized in the following tables for Cleco and Cleco Power. Where applicable, transactions are reported net of income taxes.



Note 21 — Miscellaneous Financial Information (Unaudited)

Cleco

Quarterly information for Cleco for 2012 and 2011 is shown in the following tables.



							2012
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	222,773	$	240,123	$	297,372	$	233,431
Operating income	$	54,294	$	74,243	$	103,347	$	49,766
Net income applicable to common stock	$	30,031	$	46,686	$	63,818	$	23,112
Basic net income per average share	$	0.50	$	0.77	$	1.06	$	0.38
Diluted net income per average common share	$	0.50	$	0.77	$	1.05	$	0.38
Dividends paid per common share	$	0.3125	$	0.3125	$	0.3375	$	0.3375
Market sales price per share
High	$	40.10	$	42.45	$	45.30	$	43.75
Low	$	36.15	$	38.16	$	40.09	$	38.46



							2011
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	253,690	$	272,923	$	351,581	$	239,119
Operating income	$	64,518	$	69,581	$	115,500	$	48,647
Net income applicable to common stock	$	29,004	$	70,221	$	65,842	$	30,643
Basic net income per average share	$	0.48	$	1.16	$	1.09	$	0.51
Diluted net income per average common share	$	0.48	$	1.15	$	1.08	$	0.51
Dividends paid per common share	$	0.25	$	0.28	$	0.28	$	0.3125
Market sales price per share
High	$	34.51	$	35.66	$	36.14	$	38.31
Low	$	30.56	$	33.68	$	30.06	$	32.36

Cleco Corporation’s common stock is listed for trading on the New York Stock Exchange under the ticker symbol “CNL.” Cleco Corporation’s preferred stock is not listed on any stock

exchange. On December 31, 2012, Cleco had 5,838 common shareholders and no preferred shareholders, as determined from the records of the transfer agent.

On January 24, 2013, Cleco Corporation’s Board of Directors declared a quarterly dividend of $0.3375 per share payable on February 15, 2013, to common shareholders of record at the close of business on February 5, 2013.

In April 2011, the Board of Directors of Cleco Corporation declared a dividend of $0.28 per share of common stock. In October 2011, the Board of Directors raised the quarterly dividend from $0.28 per share of common stock to $0.3125 per share of common stock

In January and April 2012, the Board of Directors declared a dividend of $0.3125 per share of common stock. In July 2012, the quarterly dividend declared by the Board of Directors increased to $0.3375 per share of common stock. In October 2012, a dividend of $0.3375 was again declared. The declaration of dividend payments is at the Board of Directors’ sole discretion and future dividends are subject to numerous factors that ordinarily affect dividend policy, including the result of Cleco’s operations and its financial position, as well as general economic and business conditions.

Cleco Power

Quarterly information for Cleco Power for 2012 and 2011 is shown in the following tables.



							2012
(THOUSANDS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	222,620	$	239,967	$	297,212	$	233,269
Operating income	$	58,306	$	76,792	$	97,510	$	54,584
Net income	$	26,805	$	37,284	$	57,783	$	24,975
Distribution to Cleco Corporation (as sole member)	$	30,000	$	10,000	$	18,000	$	—



							2011
(THOUSANDS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	250,623	$	268,464	$	342,296	$	236,099
Operating income	$	67,105	$	74,834	$	109,495	$	52,959
Net income	$	30,030	$	35,694	$	53,833	$	23,278
Distribution to Cleco Corporation (as sole member)	$	50,000	$	—	$	50,000	$	30,000

Evaluation of Disclosure Controls and Procedures

As of December 31, 2012, evaluations were performed under the supervision and with the participation of Cleco Corporation and Cleco Power management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures (as defined in Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). 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 Exchange Act 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 (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the quarter ended December 31, 2012, and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Management’s Reports on Internal Control Over Financial Reporting

The management of Cleco and Cleco Power is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act. Cleco and Cleco Power’s internal control over financial reporting is a process designed by, or under the supervision of, each of Cleco and Cleco Power’s principal executive and financial officers and effected by Cleco and Cleco Power’s board of directors or managers, as the case may be, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Management’s assessments included review and testing of both the design effectiveness and operating effectiveness of controls over relevant assertions related to significant accounts and disclosures in the financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The management of Cleco and Cleco Power, under the supervision of each of the Registrants’ principal executive officer and principal financial officer, conducted an assessment of the effectiveness of Cleco and Cleco Power’s respective internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, the management of Cleco and Cleco Power concluded that, as of December 31, 2012, the Registrants’ internal control over financial reporting was effective.

The effectiveness of Cleco and Cleco Power’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their reports which appear on pages 60 and 67, respectively, of this Annual Report on Form 10-K.

Certifications

The certifications of the Registrants’ CEO and CFO required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1, 31.2, 31.3, and 31.4 to this Annual Report on Form 10-K. Additionally, as required by Section 303A.12(a) of the New York Stock Exchange (NYSE) Listed Company Manual, Cleco’s CEO filed a certification with the NYSE on May 22, 2012, reporting that he was not aware of any violation by Cleco of the NYSE’s Corporate Governance listing standards.

Stock Awards

On February 15, 2013, the Board of Directors of Cleco Corporation approved a special award in the amount of 1,500 shares of Cleco Corporation common stock to Darren J. Olagues, Senior Vice President - Chief Financial Officer. The Board of Directors also approved special awards to Judy P. Miller, Senior Vice President - Corporate Services and Internal Audit, and Keith D. Crump, Senior Vice President - Commercial Operations, each in the amount of 1,250 shares of Cleco Corporation common stock. The awards are intended to recognize services rendered during 2012. The awards were made under Cleco Corporation's 2010 LTICP.

The shares are restricted until February 15, 2016. During the restricted period, Mr. Olagues, Ms. Miller and Mr. Crump may not sell, assign, transfer, pledge or otherwise dispose of the shares. Dividends equivalents will accrue on the shares

during the restricted period and will be settled in cash upon the lapse of the restrictions. The shares, and any accrued

dividend equivalents thereon, will be forfeited if Mr. Olagues,

Ms. Miller or Mr. Crump are not employed at the end of the

restricted period, other than because of involuntary termination without cause (as defined in the 2010 LTICP), retirement, death or disability.

If a change in control (as defined in the 2010 LTICP) occurs during the restricted period and Mr. Olagues, Ms. Miller or Mr. Crump separates from service on account of a permitted reason during the 60-day period preceding or the 24-month period following the change, the restricted shares and related dividend equivalent units, to the extent not then vested, will vest and be delivered and settled at the end of the restricted period. Permitted reasons include an involuntary separation by Cleco without cause or a separation by Mr. Olagues, Ms. Miller or Mr. Crump, as the case may be, on account of good reason (as defined in the Cleco Corporation Executive Severance Plan).

The Board of Directors has reserved the ability to amend the terms and conditions of the awards, in its discretion.



NAME OF DIRECTOR	AGES AS OF FEBRUARY 19, 2013
J. Patrick Garrett	Age 69; Elected 1981 Retired President and Chief Executive Officer, Windsor Food Company, Ltd., Houston, TX Chairman of the Board and Chairman of the Nominating/Governance Committee
Elton R. King	Age 66; Elected 1999 Retired President of Network and Carrier Services Group, BellSouth Telecommunications, Inc., Atlanta, GA. Also retired President and Chief Executive Officer of Visual Networks, Inc. Member of the Finance and Nominating/Governance Committees
Logan W. Kruger	Age 62; Elected 2008 President and CEO, SUN Gold Limited, Jersey, Channel Islands United Kingdom. Former President, Chief Executive Officer and Director of Century Aluminum Company, Monterey, CA Member of the Audit and Compensation Committees
William L. Marks	Age 69; Elected 2001 Retired Chairman and Chief Executive Officer, Whitney Holding Corporation and Whitney National Bank, New Orleans, LA Chairman of the Finance Committee and member of the Compensation Committee
Peter M. Scott III	Age 63; Elected 2009 Retired Executive Vice President and Chief Financial Officer, Progress Energy, Inc., Raleigh, NC. Also retired President and Chief Executive Officer of Progress Energy Service Company, LLC Chairman of the Audit Committee and member of the Compensation Committee
Shelley Stewart Jr.	Age 59; Elected 2010 Vice President, Sourcing and Logistics/Chief Procurement Officer, E.I. du Pont de Nemours & Company, Wilmington, DE; former Senior Vice President, Operational Excellence & Chief Procurement Officer, Tyco International Limited, Princeton, NJ Member of the Audit and Nominating/Governance Committees
William H. Walker Jr.	Age 67; Elected 1996 Retired Chairman, Howard Weil, Inc., New Orleans, LA Chairman of the Compensation Committee and member of the Finance and Nominating/Governance Committees
Bruce A. Williamson	Age 53; Elected 2011 President and Chief Executive Officer, Cleco Corporation, Pineville, LA since July 2011 Chairman, President and Chief Executive Officer, Dynegy, Inc. from 2004 to 2011

EXHIBITS



CLECO			SEC FILE OR REGISTRATION NUMBER	REGISTRATION STATEMENT OR REPORT	EXHIBIT NUMBER
	3(a)(1)	Amended and Restated Articles of Incorporation of the Company, dated November 2, 2010	1-15759	8-K(11/2/10)	3.1
*	3(b)(1)	Bylaws of Cleco Corporation, revised effective January 24, 2013
	4(a)(1)	Indenture of Mortgage dated as of July 1, 1950, between Cleco Power (as successor) and First National Bank of New Orleans, as Trustee	1-5663	10-K(1997)	4(a)(1)
	4(a)(2)	Eighteenth Supplemental Indenture dated as of December 1, 1982, to Exhibit 4(a)(1)	1-5663	10-K(1993)	4(a)(8)
	4(a)(3)	Nineteenth Supplemental Indenture dated as of January 1, 1983, to Exhibit 4(a)(1)	1-5663	10-K(1993)	4(a)(9)
	4(a)(4)	Twenty-Sixth Supplemental Indenture dated as of March 15, 1990, to Exhibit 4(a)(1)	1-5663	8-K(3/90)	4(a)(27)
	4(b)(1)	Indenture between Cleco Power (as successor) and Bankers Trust Company, as Trustee, dated as of October 1, 1988	33-24896	S-3(10/11/88)	4(b)
	4(b)(2)	Agreement Appointing Successor Trustee dated as of April 1, 1996, by and among Central Louisiana Electric Company, Inc., Bankers Trust Company, and The Bank of New York	333-02895	S-3(4/29/96)	4(a)(2)
	4(b)(3)	First Supplemental Indenture, dated as of December 1, 2000, between Cleco Utility Group Inc. and the Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(2)
	4(b)(4)	Second Supplemental Indenture, dated as of January 1, 2001, between Cleco Power LLC and The Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(3)
	4(b)(5)	Third Supplemental Indenture, dated as of April 26, 2001, between Cleco Power LLC and the Bank of New York	1-5663	8-K(4/26/01)	4(a)
	4(b)(6)	Sixth Supplemental Indenture, dated as of April 28, 2003, between Cleco Power LLC and the Bank of New York providing for the issuance of $75,000,000 principal amount of 5.375% Notes due May 1, 2013	1-5663	8-K(4/28/03)	4.1
	4(b)(7)	Seventh Supplemental Indenture, dated as of July 6, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-5663	8-K(7/6/05)	4.1
	4(b)(8)	Eighth Supplemental Indenture, dated as of November 30, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-5663	8-K(11/28/05)	4.1
	4(b)(9)	Ninth Supplemental Indenture, dated as of June 3, 2008, between Cleco Power LLC and The Bank of New York Trust Company, N.A.	1-5663	8-K(6/2/08)	4.1
	4(b)(10)	Tenth Supplemental Indenture, dated as of November 13, 2009, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-5663	8-K(11/12/09)	4.1
	4(b)(11)	Eleventh Supplemental Indenture, dated as of November 15, 2010, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-5663	8-K(11/15/10)	4.1
	4(c)	Agreement Under Regulation S-K Item 601(b)(4)(iii)(A)	1-5663	10-Q(9/99)	4(c)
**	10(a)(1)	2000 Long-Term Incentive Compensation Plan	333-71643-01	2000 Proxy Statement(3/00)	A
**	10(a)(2)	2000 Long-Term Incentive Compensation Plan, Amendment Number 1, Effective as of December 12, 2003	1-15759	10-Q(3/05)	10(a)
**	10(a)(3)	2000 Long-Term Incentive Compensation Plan, Amendment Number 2, Effective as of July 23, 2004	1-15759	10-Q(9/04)	10(a)
**	10(a)(4)	2000 Long-Term Incentive Compensation Plan, Amendment Number 3, Dated as of January 28, 2005	1-15759	10-Q(3/05)	10(b)
**	10(a)(5)	2000 Long-Term Incentive Compensation Plan, Amendment Number 4, Dated as of November 4, 2008	1-15759	10-K(2008)	10(a)(6)
**	10(a)(6)	2000 Long-Term Incentive Compensation Plan, Amendment Number 5, Dated as of December 8, 2008	1-15759	8-K(12/9/08)	10.1
**	10(a)(7)	2000 Long-Term Incentive Compensation Plan, Administrative Procedure No. 1	1-15759	10-K(2005)	10(a)(6)
**	10(a)(8)	2010 Long-Term Incentive Compensation Plan, effective as of January 1, 2010	1-15759	2009 Proxy Statement (3/12/09)	C
**	10(a)(9)	Cleco Corporation 2010 Long-Term Incentive Compensation Plan Amendment, effective October 28, 2011	1-15759	10-Q(9/11)	10.4
**	10(a)(10)	Form of Notice and Acceptance of Directors’ Grant of Nonqualified Stock Options under Cleco’s 2000 Long-Term Incentive Compensation Plan	1-15759	10-Q(6/00)	10(a)
**	10(a)(11)	Form of Notice and Acceptance of Grant of Nonqualified Stock Options, with fixed option price under Cleco’s 2000 Long-Term Incentive Compensation Plan	1-15759	10-Q(6/00)	10(c)
**	10(a)(12)	Form of Notice and Acceptance of Grant of Nonqualified Stock Options, with variable option price under Cleco’s 2000 Long-Term Incentive Compensation Plan	1-15759	10-Q(6/00)	10(d)
**	10(a)(13)	Form of Notice and Acceptance of Director’s Grant of Nonqualified Stock Option	1-5663	10-Q(9/01)	10
	10(a)(14)	Form of Notice and Acceptance of Grant of Restricted Stock under Cleco’s 2000 Long-Term Incentive Compensation Plan	1-15759	10-Q(6/00)	10(b)
	10(a)(15)	Form of Notice and Acceptance of Grant of Restricted Stock and Allocation of Opportunity Shares	1-15759	10-Q(9/05)	10(c)
	10(a)(16)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2007 Performance Cycle	1-15759	10-K(2006)	10(n)(3)
	10(a)(17)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2008 Performance Cycle	1-15759	10-K(2007)	10(m)(4)
	10(a)(18)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2009 Performance Cycle	1-15759	10-K(2008)	10(m)(4)
	10(a)(19)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2010 Performance Cycle	1-15759	10-K(2009)	10(g)(2)
	10(a)(20)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2011 Performance Cycle	1-15759	10-K(2010)	10(a)(19)
	10(a)(21)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2012 Performance Cycle	1-15759	10-K(2011)	10(a)(23)
*	10(a)(22)	Form of Notice and Acceptance of Grant of Restricted Stock and Common Stock Equivalent Units and Allocation of Opportunity Shares and Opportunity Common Stock Equivalent Units – 2013 Performance Cycle
	10(a)(23)	Form of Notice and Acceptance of Grant of Restricted Stock under Cleco Corporation 2010 Long-Term Incentive Compensation Plan	1-15759	8-K(2/1/11)	10.1
	10(a)(24)	Notice and Acceptance of Award of Restricted Stock under Cleco Corporation 2010 Long-Term Incentive Compensation Plan, by and between Cleco Corporation and Michael H. Madison	1-15759	8-K(2/1/11)	10.2



CLECO			SEC FILE OR REGISTRATION NUMBER	REGISTRATION STATEMENT OR REPORT	EXHIBIT NUMBER
**	10(a)(25)	Notice and Acceptance of Award of Restricted Stock under Cleco Corporation 2010 Long-Term Incentive Compensation Plan, by and between Cleco Corporation and Bruce A. Williamson	1-15759	10-Q(3/12)	10.1
**	10(a)(26)	Notice and Acceptance of Award of Restricted Stock under Cleco Corporation 2010 Long-Term Incentive Compensation Plan, by and between Cleco Corporation and Bruce A. Williamson	1-15759	8-K(1/24/13)	10.1
*	10(a)(27)	Notice and Acceptance of Award of Restricted Stock under Cleco Corporation 2010 Long-Term Incentive Compensation Plan, by and between Darren J. Olagues, Judy P. Miller, and Keith D. Crump
**	10(b)(1)	Deferred Compensation Plan for Directors	1-5663	10-K(1992)	10(n)
**	10(b)(2)	Summary of Director Compensation, Benefits and Policies, last revised on July 29, 2011	1-15759	10-Q(9/11)	10.3
**	10(c)(1)	Supplemental Executive Retirement Plan	1-5663	10-K(1992)	10(o)(1)
**	10(c)(2)	First Amendment to Supplemental Executive Retirement Plan effective July 1, 1999	1-15759	10-K(2003)	10(e)(1)(a)
**	10(c)(3)	Second Amendment to Supplemental Executive Retirement Plan dated July 28, 2000	1-15759	10-K(2003)	10(e)(1)(b)
**	10(c)(4)	Supplemental Executive Retirement Plan Amended and Restated January 1, 2009	1-15759	10-K(2008)	10(f)(4)
**	10(c)(5)	Supplemental Executive Retirement Plan (Amended and Restated January 1, 2009), Amendment No. 1	1-15759	8-K(12/9/08)	10.3
**	10(c)(6)	Supplemental Executive Retirement Trust dated December 13, 2000	1-15759	10-K(2003)	10(e)(1)(c)
**	10(c)(7)	Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Dilek Samil	1-15759	10-K(2002)	10(z)(1)
**	10(c)(8)	Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Michael H. Madison	1-15759	10-K(2004)	10(v)(3)
**	10(c)(9)	Cleco Corporation Supplemental Executive Retirement Plan Amendment, effective October 28, 2011	1-15759	10-Q(9/11)	10.2
**	10(d)(1)	Executive Employment Agreement Compliance Addendum – Code Section 409A, effective January 1, 2009	1-15759	8-K(12/9/08)	10.4
**	10(d)(2)	Form of Cleco Corporation Executive Employment Agreement (Level 1)	1-15759	8-K(1/9/09)	10.1
**	10(d)(3)	Separation Agreement between Cleco Corporation and Dilek Samil, dated October 22, 2010	1-15759	8-K(10/22/10)	10.1
**	10(d)(4)	Cleco Corporation Executive Severance Plan, effective October 28, 2011	1-15759	10-Q(9/11)	3.1
**	10(d)(5)	Executive Employment Agreement, dated April 21, 2011, by and between Cleco Corporation and Bruce A. Williamson	1-15759	8-K(4/27/11)	10.1
**	10(d)(6)	Retirement Agreement, dated April 21, 2011, by and between Cleco Corporation and Michael H. Madison	1-15759	8-K(4/27/11)	10.2
**	10(d)(7)	Waiver of 2012 salary increases by Bruce A. Williamson, President and Chief Executive Officer	1-15759	10-K(2011)	10(e)(14)
	10(e)	401(k) Savings and Investment Plan Trust Agreement dated as of August 1, 1997, between UMB Bank, N.A. and Cleco	1-5663	10-K(1997)	10(m)
	10(f)(1)	Cleco Corporation Employee Stock Purchase Plan	333-44364	S-8(8/23/00)	4.3
	10(f)(2)	Employee Stock Purchase Plan, Amendment No. 1, dated January 22, 2004	1-15759	10-K(2003)	10(s)(1)
	10(f)(3)	Employee Stock Purchase Plan, Amendment No. 2, effective as of January 1, 2006	1-15759	10-Q(6/05)	10(a)
	10(f)(4)	Cleco Corporation Pay for Performance Plan	1-15759	10-K(2011)	10(g)(4)
*	10(f)(5)	Cleco Corporation Pay for Performance Plan, As Amended and Restated December 3, 2012
**	10(g)(1)	Cleco Corporation Deferred Compensation Plan	333-59696	S-8(4/27/01)	4.3
**	10(g)(2)	First Amendment to Cleco Corporation Deferred Compensation Plan	1-15759	10-K(2008)	10(n)(5)
**	10(g)(3)	Cleco Corporation Deferred Compensation Plan, Corrective Section 409A Amendment	1-15759	8-K(12/9)08)	10.2
	10(g)(4)	Deferred Compensation Trust dated January 2001	1-15759	10-K(2003)	10(u)
	10(g)(5)	Cleco Corporation Deferred Compensation Plan Amendment, effective October 28, 2011	1-15759	10-Q(9/11)	10.5
	10(h)(1)	Credit Agreement dated as of November 23, 2010 by and among Cleco Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders and other parties thereto	1-15759	8-K(11/30/10)	10.1
	10(h)(2)	Loan Agreement dated as of February 19, 2010, among Cleco Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto	1-15759	10-K(2009)	10(j)(3)
	10(h)(3)	Amendment No. 1 Dated as of January 27, 2011 to Loan Agreement Dated as of February 19, 2010	1-15759	10-K(2010)	10(i)(3)
	10(h)(4)	First Amendment, dated as of October 7, 2011, to Credit Agreement dated as of November 23, 2010 by and among Cleco Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders and other parties thereto	1-15759	8-K(10/14/11)	10.1
	10(h)(5)	Note Purchase Agreement dated May 8, 2012 by and among Cleco Power and the Purchasers listed on the signature pages thereto	1-05663	8-K(05/09/12)	10.1
	10(i)	Acadia Power Partners, LLC – Third Amended and Restated Limited Liability Company Agreement dated February 23, 2010	1-5759	10-K(2010)	10(j)
*	12(a)	Computation of Ratios of Earnings (loss) to Fixed Charges and of Earnings (loss) to Combined Fixed Charges and Preferred Stock Dividends
*	21	Subsidiaries of the Registrant
*	23(a)	Consent of Independent Registered Public Accounting Firm
*	24(a)	Power of Attorney from each Director of Cleco Corporation whose signature is affixed to this Form 10-K for the fiscal year ended December 31, 2012
*	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
*	95	Mine Safety Disclosures
*	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			SEC FILE OR REGISTRATION NUMBER	REGISTRATION STATEMENT OR REPORT	EXHIBIT NUMBER
	3(a)	First Amended and Restated Articles of Organization of Cleco Power LLC, dated April 30, 2010	1-5663	10-Q(3/10)	3.2
	3(b)	First Amended and Restated Operating Agreement of Cleco Power LLC, dated April 30, 2010	1-5663	10-Q(3/10)	3.3
	4(a)(1)	Indenture of Mortgage dated as of July 1, 1950, between the Company and First National Bank of New Orleans, as Trustee	1-5663	10-K(1997)	4(a)(1)
	4(a)(2)	Eighteenth Supplemental Indenture dated as of December 1, 1982, to Exhibit 4(a)(1)	1-5663	10-K(1993)	4(a)(8)
	4(a)(3)	Nineteenth Supplemental Indenture dated as of January 1, 1983, to Exhibit 4(a)(1)	1-5663	10-K(1993)	4(a)(9)
	4(a)(4)	Twenty-Sixth Supplemental Indenture dated as of March 15, 1990, to Exhibit 4(a)(1)	1-5663	8-K(3/90)	4(a)(27)
	4(b)(1)	Indenture between the Company and Bankers Trust Company, as Trustee, dated as of October 1, 1988	33-24896	S-3(10/11/88)	4(b)
	4(b)(2)	Agreement Appointing Successor Trustee dated as of April 1, 1996, by and among Central Louisiana Electric Company, Inc., Bankers Trust Company, and The Bank of New York	333-02895	S-3(4/29/96)	4(a)(2)
	4(b)(3)	First Supplemental Indenture, dated as of December 1, 2000, between Cleco Utility Group Inc. and the Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(2)
	4(b)(4)	Second Supplemental Indenture, dated as of January 1, 2001, between Cleco Power LLC and The Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(3)
	4(b)(5)	Third Supplemental Indenture, dated as of April 26, 2001, between Cleco Power LLC and the Bank of New York	1-5663	8-K(4/26/01)	4(a)
	4(b)(6)	Sixth Supplemental Indenture, dated as of April 28, 2003, between Cleco Power LLC and the Bank of New York providing for the issuance of $75,000,000 principal amount of 5.375% Notes due May 1, 2013	1-5663	8-K(4/28/03)	4.1
	4(b)(7)	Seventh Supplemental Indenture, dated as of July 6, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-5663	8-K(7/6/05)	4.1
	4(b)(8)	Eighth Supplemental Indenture, dated as of November 30, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-5663	8-K(11/28/05)	4.1
	4(b)(9)	Ninth Supplemental Indenture, dated as of June 3, 2008, between Cleco Power LLC and The Bank of New York Trust Company, N.A.	1-5663	8-K(6/2/08)	4.1
	4(b)(10)	Tenth Supplemental Indenture, dated as of November 13, 2009, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-5663	8-K(11/12/09)	4.1
	4(b)(11)	Eleventh Supplemental Indenture, dated as of November 15, 2010, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-5663	8-K(11/15/10)	4.1
	4(c)	Agreement Under Regulation S-K Item 601(b)(4)(iii)(A)	333-71643-01	10-Q(9/99)	4(c)
	4(d)	Loan Agreement, dated as of November 1, 2006, between Cleco Power LLC and the Rapides Finance Authority	1-5663	8-K(11/27/06)	4.1
	4(e)	Loan Agreement, dated as of November 1, 2007, between Cleco Power LLC and the Rapides Finance Authority	1-5663	8-K(11/20/07)	4.1
	4(f)	Loan Agreement, dated as of October 1, 2008, between Cleco Power LLC and the Rapides Finance Authority	1-5663	10-Q(3/10)	4.1
	4(g)	Loan Agreement, dated as of December 1, 2008, between Cleco Power LLC and the Louisiana Public Facilities Authority	1-5663	10-Q(3/10)	4.2
**	10(a)(1)	Supplemental Executive Retirement Plan	1-5663	10-K(1992)	10(o)(1)
**	10(a)(2)	Form of Cleco Corporation Executive Employment Agreement (Level 1)	1-15759	8-K(1/9/09)	10.1
	10(b)(1)	401(k) Savings and Investment Plan Trust Agreement dated as of August 1, 1997, between UMB Bank, N.A. and the Company	1-5663	10-K(1997)	10(m)
	10(b)(2)	401(k) Savings and Investment Plan, Stock Trust Agreement, Amendment Number 1, Effective January 1, 1999	1-5663	10-K(2009)	10(b)(3)
	10(b)(3)	401(k) Savings and Investment Plan, Stock Trust Agreement, Amendment Number 2, Effective January 1, 2004	1-5663	10-Q(6/04)	10(b)
	10(b)(4)	401(k) Savings and Investment Plan, Stock Trust Agreement, Amendment Number 3, Effective October 1, 2005	1-5663	10-Q(9/05)	10(e)
	10(b)(5)	401(k) Savings and Investment Plan, Stock Trust Agreement, Amendment Number 4 (designated as Amendment Number 3 in exhibit 10(b), Effective January 1, 2007	1-5663	10-Q(3/07)	10(b)
	10(b)(6)	401(k) Savings and Investment Plan, Amended and Restated Generally Effective November 1, 2010	1-5663	10-K(2010)	10(b)(14)
	10(b)(7)	401(k) Savings and Investment Plan, As Amended and Restated Effective November 1, 2010, Amendment Number 1	1-5663	10-K(2011)	10(b)(7)
	10(c)(1)	Credit Agreement dated as of November 23, 2010 by and among Cleco Power LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders and other parties thereto	1-5663	8-K(11/30/10)	10.2
	10(c)(2)	First Amendment, dated as of October 7, 2011, to Credit Agreement dated as of November 23, 2010 by and among Cleco Power LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders and other parties thereto	1-05663	8-K(10/14/11)	10.2
	10(c)(3)	Notes Purchase Agreement dated as of December 16, 2011 among Cleco Power LLC, various financial institutions and Credit Agricole Securities (USA) Inc., JPMorgan Securities Inc. and KeyBanc Capital Markets Inc., as agents.	1-05663	8-K(12/19/11)	10.1
	10(c)(4)	Note Purchase Agreement dated May 8, 2012 by and among Cleco Power and the Purchasers listed on the signature pages thereto	1-05663	8-K(05/09/12)	10.1
	10(d)(1)	Storm Recovery Property Sale Agreement between Cleco Katrina/Rita Hurricane Recovery Funding LLC and Cleco Power LLC, dated March 6, 2008	1-5663	8-K(3/6/08)	10.1
	10(d)(2)	Storm Recovery Property Servicing Agreement between Cleco Katrina/Rita Hurricane Recovery Funding LLC and Cleco Power LLC, dated March 6, 2008	1-5663	8-K(3/6/08)	10.2
	10(d)(3)	Administration Agreement between Cleco Katrina/Rita Hurricane Recovery Funding LLC and Cleco Power LLC, dated March 6, 2008	1-5663	8-K(3/6/08)	10.3
*	12(b)	Computation of Ratios of Earnings to Fixed Charges
*	23(b)	Consent of Independent Registered Public Accounting Firm
*	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
*	95	Mine Safety Disclosures
*	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 CORPORATION (Parent Company Only)	SCHEDULE I



Condensed Balance Sheets
	AT DEC. 31,
(THOUSANDS)	2012			2011
Assets
Current assets
Cash and cash equivalents	$	7,418		$	22,642
Accounts receivable - affiliate	9,455			13,386
Other accounts receivable	1			1
Taxes receivable, net	30,920			8,431
Accumulated deferred federal and state income taxes, net	—			7,153
Cash surrender value of life insurance policies	36,504			30,639
Total current assets	84,298			82,252
Equity investment in investees	1,497,788			1,392,693
Accumulated deferred federal and state income taxes, net	91,359			35,675
Other deferred charges	1,721			3,414
Total assets	$	1,675,166		$	1,514,034
Liabilities and shareholders’ equity
Liabilities
Current liabilities
Accounts payable	$	3,392		$	86
Accounts payable - affiliate	55,432			13,739
Accumulated deferred federal and state income taxes, net	2,926			—
Other current liabilities	10,363			8,817
Total current liabilities	72,113			22,642
Tax credit fund investment, net	78,840			61,507
Other deferred credits	—			28
Long-term debt	25,000			10,000
Total liabilities	175,953			94,177
Commitments and Contingencies (Note 5)
Shareholders’ equity
Common shareholders’ equity
Common stock, $1 par value, authorized 100,000,000 shares, issued 60,961,570 and 60,702,342 shares and outstanding 60,355,545 and 60,291,939 shares at December 31, 2012 and 2011, respectively	60,962			60,702
Premium on common stock	416,619			409,904
Retained earnings	1,075,074			990,605
Treasury stock, at cost, 606,025 and 410,403 shares at December 31, 2012 and 2011, respectively	(21,072		)	(13,215		)
Accumulated other comprehensive loss	(32,370		)	(28,139		)
Total shareholders’ equity	1,499,213			1,419,857
Total liabilities and shareholders’ equity	$	1,675,166		$	1,514,034
The accompanying notes are an integral part of the condensed financial statements.



CLECO CORPORATION (Parent Company Only)	SCHEDULE I



Condensed Statements of Cash Flows
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Operating activities
Net cash provided by operating activities	$	79,606		$	175,624		$	174,912
Investing activities
Additions to property, plant, and equipment, net	—			—			(152,067		)
Contributions to tax credit fund	(59,645		)	(43,921		)	(35,871		)
Return of equity investment in tax credit fund	37,652			33,430			—
Return of equity investment in investees	—			89,654			—
Other investing	(2,973		)	(1,232		)	(2,900		)
Net cash (used in) provided by investing activities	(24,966		)	77,931			(190,838		)
Financing activities
Issuance of short-term debt	—			—			150,000
Retirement of short-term debt	—			(150,000		)	—
Draws on credit facility	25,000			35,000			20,000
Payments on credit facility	(10,000		)	(40,000		)	(100,000		)
Repurchase of common stock	(8,007		)	(13,009		)	—
Dividends paid on common stock	(78,844		)	(68,023		)	(58,988		)
Other financing	1,987			(201		)	3,154
Net cash (used in) provided by financing activities	(69,864		)	(236,233		)	14,166
Net (decrease) increase in cash and cash equivalents	(15,224		)	17,322			(1,760		)
Cash and cash equivalents at beginning of period	22,642			5,320			7,080
Cash and cash equivalents at end of period	$	7,418		$	22,642		$	5,320
Supplementary cash flow information
Interest paid	$	95		$	1,752		$	8,205
Income tax paid, net	$	59		$	31,180		$	80,905
Supplementary non-cash investing and financing activity
Issuance of common stock - ESPP	$	340		$	328		$	299
Non-cash additions to property, plant, and equipment	$	—		$	—		$	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 financial statements.



Note 1 — Summary of Significant Accounting Policies

The condensed financial statements represent the financial information required by SEC Regulation S-X 5-04 for Cleco Corporation, which requires the inclusion of parent company only financial statements if the restricted net assets of consolidated subsidiaries exceed 25% of total consolidated net assets as of the last day of its most recent fiscal year. As of December 31, 2012, Cleco Corporation’s restricted net assets of consolidated subsidiaries were $785.9 million and exceeded 25% of its total consolidated net assets.

Cleco Corporation’s major, first-tier subsidiaries consist of Cleco Power and Midstream.

Cleco Power contains the LPSC-jurisdictional generation, transmission, and distribution electric utility operations serving Cleco’s traditional retail and wholesale customers. Midstream owns and operates a merchant power plant (Coughlin).

The accompanying financial statements have been prepared to present the results of operations, financial condition,and cash flows of Cleco Corporation on a stand-alone basis as a holding company. Investments in subsidiaries and other investees are stated at cost plus equity in undistributed earnings from the date of acquisition. These financial statements should be read in conjunction with Cleco’s consolidated financial statements.



Note 2 — Debt

At December 31, 2012 and 2011, Cleco Corporation had no short-term debt outstanding.

At December 31, 2012, Cleco Corporation’s long-term debt outstanding was $25.0 million, of which none was due within one year, compared to $10.0 million of long-term debt at December 31, 2011, of which none was due within one year. The long-term debt at December 31, 2012 and 2011, was the result of outstanding draws on Cleco Corporation’s credit facilities.

In October 2011, Cleco Corporation entered into a $250.0 million five-year revolving credit facility. The credit facility was set to mature on October 7, 2016, and provided for working capital and other needs. The borrowing costs are LIBOR plus 1.50% or ABR, plus facility fees of 0.25%. At December 31, 2012, Cleco Corporations’ outstanding credit facility borrowings reduced available borrowings by $25.0 million, leaving an available borrowing capacity of $225.0 million. The interest rate of outstanding borrowings under the credit facility at December 31, 2012 was 1.71%. The existing borrowings had 30-day terms. The $25.0 million draws outstanding consisted of a $15.0 million draw and a $10.0 million draw. The $15.0 million draw matured and was renewed on January 17, 2013, and was subsequently repaid on February 4, 2013. The $10.0 million draw matured and was repaid on January 28, 2013. At December 31, 2012, Cleco Corporation was in compliance with the covenants in its credit facility.



Note 3 — Cash Distributions and Equity Contributions

December 31, 2012, approximately $623.7 million of member’s equity was unrestricted.

The following table summarizes the cash distributions Cleco Corporation received from affiliates during 2012, 2011, and 2010.



	AT DEC. 31,
(THOUSANDS)	2012		2011		2010
Cleco Power	$	58,000	$	130,000	$	150,000
Midstream	—		159,819		32,300
Diversified Lands	2,900		—		—
Perryville	1,500		700		700
Attala	1,300		700		700
Total	$	63,700	$	291,219	$	183,700

The following table summarizes the contributions Cleco Corporation made to affiliates during 2012, 2011, and 2010.



	AT DEC. 31,
(THOUSANDS)	2012		2011		2010
Cleco Power	$	—	$	—	$	225,732
Midstream	16,191		35,500		74,400
Support Group	—		—		20,000
Perryville	—		1,845		—
Cleco Innovations	—		3,000		456
Total	$	16,191	$	40,345	$	320,588

During 2010, the contribution made to Cleco Power related to Acadia Unit 1 and was a non-cash contribution.



Note 4 — Income Taxes

Cleco Corporation (Parent Company Only) Condensed Statements of Income reflect income tax benefits of $9.7 million, $13.2 million, and $4.5 million for the years ended December 31, 2012, 2011, and 2010, respectively. In addition to these amounts, income tax expense of $75.0 million, $116.1 million, and $147.0 million is reflected in equity income of subsidiaries, net of tax for the years ended December 31, 2012, 2011, and 2010, respectively.



Note 5 — Commitments and Contingencies

For information regarding commitments and contingencies related to Cleco Corporation, see Part II, Item 8, “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Disclosures about Guarantees.”



			LIGNITE			COAL			NATURAL GAS				BIOMASS	PETROLEUM COKE
YEAR	COST PER MWh		PERCENT OF GENERATION	COST PER MWh		PERCENT OF GENERATION	COST PER MWh			PERCENT OF GENERATION	COST PER MWh		PERCENT OF GENERATION	COST PER MWh		PERCENT OF GENERATION	WEIGHTED AVERAGE COST PER MWh
2012	$	36.36	25.2	$	33.03	17.0	$	27.81		45.8	$	17.74	*	$	23.54	12.0	$	30.37
2011	$	30.99	23.6	$	29.48	15.6	$	46.39		33.8	$	65.06	*	$	31.70	27.0	$	36.12
2010	$	27.56	26.9	$	27.35	12.1	$	55.61		40.4	$	—	—	$	23.14	20.6	$	37.96
2009	$	26.04	45.1	$	27.10	21.5	$	105.22		33.1	$	—	—	$	34.64	0.3	$	52.49
2008	$	24.09	51.3	$	27.50	18.4	$	108.48		30.3	$	—	—	$	—	—	$	50.27
* Not meaningful



(THOUSANDS, EXCEPT PER SHARE AND PERCENTAGES)	2012			2011			2010			2009			2008
Operating revenue (loss), net (excluding intercompany revenue)
Cleco Power	$	991,695		$	1,096,093		$	1,119,084		$	842,227		$	1,069,674
Midstream	25,562			19,013			27,030			8,749			7,921
Other	(23,560		)	2,207			2,552			2,782			2,603
Total	$	993,697		$	1,117,313		$	1,148,666		$	853,758		$	1,080,198
Income before income taxes	$	228,975		$	298,745		$	397,889		$	115,886		$	120,598
Net income applicable to common stock	$	163,648		$	195,710		$	255,345		$	106,261		$	102,095
Basic earnings per share applicable to common stock	$	2.71		$	3.24		$	4.23		$	1.77		$	1.70
Diluted earnings per share applicable to common stock	$	2.70		$	3.22		$	4.20		$	1.76		$	1.70
Capitalization
Common shareholders’ equity	54.39		%	51.50		%	48.46		%	45.77		%	48.89		%
Preferred stock	—			—			0.04		%	0.04		%	0.05		%
Long-term debt	45.61		%	48.50		%	51.50		%	54.19		%	51.06		%
Common shareholders’ equity	$	1,499,213		$	1,419,857		$	1,317,178		$	1,115,043		$	1,059,836
Preferred stock	$	—		$	—		$	1,029		$	1,029		$	1,029
Long-term debt, net	$	1,257,258		$	1,337,056		$	1,399,709		$	1,320,299		$	1,106,819
Total assets	$	4,147,349		$	4,050,202		$	4,161,430		$	3,696,479		$	3,346,143
Cash dividends declared per common share	$	1.30		$	1.1225		$	0.975		$	0.90		$	0.90



Consolidated Statements of Comprehensive Income
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Net income	$	163,648		$	195,848		$	255,391
Other comprehensive loss, net of tax:
Amortization of postretirement benefit net loss (gain) (net of tax expense of $1,200 in 2012 and $605 in 2011, and tax benefit of $20 in 2010)	2,117			1,213			(31		)
Postretirement benefit loss incurred during the year (net of tax benefit of $5,430 in 2012 and $949 in 2011, and tax expense of $131 in 2010)	(8,682		)	(1,721		)	(4,241		)
Cash flow hedges:
Net derivative gain (loss) (net of tax expense of $271 in 2012 and $1,823 in 2010, and tax benefit of $9,873 in 2011)	433			(15,788		)	2,916
Reclassification of net loss (gain) to interest charges (net of tax expense of $23 in 2012 and $197 in 2010, and tax benefit of $129 in 2011)	37			(205		)	315
Reclassification of ineffectiveness to regulatory asset (net of tax expense of $1,166 in 2012)	1,864			—			—
Reclassification of net loss to other expense (net of tax expense of $434 in 2010)	—			—			694
Total other comprehensive loss, net of tax	(4,231		)	(16,501		)	(347		)
Comprehensive income, net of tax	$	159,417		$	179,347		$	255,044
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Statements of Comprehensive Income
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2012			2011			2010
Net income	$	146,848		$	142,835		$	147,405
Other comprehensive loss, net of tax:
Amortization of postretirement benefit net loss (gain) (net of tax expense of $618 in 2012 and $303 in 2011 and tax benefit of $239 in 2010)	1,160			692			(381		)
Postretirement benefit loss incurred during the year (net of tax benefit of $2,054 in 2012 and $266 in 2011 and tax expense of $725 in 2010)	(3,285		)	(595		)	(2,607		)
Cash flow hedges:
Net derivative gain (loss) (net of tax expense of $271 in 2012 and $1,823 in 2010, and tax benefit of $9,873 in 2011)	433			(15,788		)	2,916
Reclassification of net loss (gain) to interest charges (net of tax expense of $23 in 2012 and $197 in 2010, and tax benefit of $129 in 2011)	37			(205		)	315
Reclassification of ineffectiveness to regulatory asset (net of tax expense of $1,166 in 2012)	1,864			—			—
Reclassification of net loss to other expense (net of tax expense of $434 in 2010)	—			—			694
Total other comprehensive income (loss), net of tax	209			(15,896		)	937
Comprehensive income, net of tax	$	147,057		$	126,939		$	148,342
The accompanying notes are an integral part of the consolidated financial statements.



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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Stock, $1.00 par value, and associated rights to purchase Preferred Stock		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:

Title of each class
4.50% Cumulative Preferred Stock, $100 Par Value



		PAGE
GLOSSARY OF TERMS		3
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		6

PART I
ITEM 1.	Business
	General	8
	Operations	8
	Regulatory Matters, Industry Developments, and Franchises	13
	Environmental Matters	14
ITEM 1A.	Risk Factors	18
ITEM 1B.	Unresolved Staff Comments	25
ITEM 2.	Properties	25
ITEM 3.	Legal Proceedings	25
ITEM 4.	Mine Safety Disclosures	26
	Executive Officers of Cleco	27

PART II
ITEM 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Cleco Corporation’s Purchases of Equity Securities	28
ITEM 6.	Selected Financial Data	28
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
ITEM 8.	Financial Statements and Supplementary Data	58
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	115
ITEM 9A.	Controls and Procedures	116
ITEM 9B.	Other Information	116

PART III
ITEM 10.	Directors, Executive Officers, and Corporate Governance of the Registrants	118
ITEM 11.	Executive Compensation	119
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	120
ITEM 14.	Principal Accountant Fees and Services	120

PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	121
	Signatures	131



ABBREVIATION OR ACRONYM	DEFINITION
SPP	Southwest Power Pool
SPP RE	Southwest Power Pool Regional Entity
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



GENERATING STATION	YEAR OF INITIAL OPERATION	NAMEPLATE CAPACITY (MW)	⁽¹⁾	NET CAPACITY (MW)⁽²⁾	TYPE OF FUEL USED FOR GENERATION	GENERATION TYPE
Brame Energy Center
Nesbitt Unit 1	1975	440		422	natural gas	steam
Rodemacher Unit 2	1982	157	⁽³⁾	148	coal/natural gas	steam
Madison Unit 3	2010	641		628	petroleum coke/coal/biomass	steam
Acadia Unit 1	2002	580		562	natural gas	combined cycle
Teche Unit 1	1953	23		18	natural gas	steam
Teche Unit 3	1971	359		297	natural gas	steam
Teche Unit 4	2011	33		34	natural gas	combustion
Dolet Hills Power Station	1986	325	⁽⁴⁾	319	lignite/natural gas	steam
Franklin Gas Turbine	1973	7		8	natural gas	combustion
Total generating capability		2,565		2,436



PERIOD	THOUSAND MWh	PERCENT OF TOTAL ENERGY REQUIREMENTS
2012	9,143	81.3
2011	10,025	86.5
2010	8,753	74.7
2009	4,943	46.4
2008	4,747	44.3



ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND CLECO CORPORATION’S PURCHASES OF EQUITY SECURITIES



ITEM 7. MANAGEMENT DISCUSSIONS AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



							AT DEC. 31, 2012
			AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
(THOUSANDS)	NET AMOUNT COMMITTED		LESS THAN ONE YEAR		1-3 YEARS		3-5 YEARS		MORE THAN 5 YEARS
Off-balance sheet commitments	$	4,225	$	3,725	$	—	$	—	$	500
On-balance sheet guarantees	12,156		7,250		900		—		4,006
Total	$	16,381	$	10,975	$	900	$	—	$	4,506



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



Consolidated Statements of Cash Flows (Continued)
	FOR THE YEAR ENDED DECEMBER 31,
(THOUSANDS)	2012			2011			2010
Financing activities
Draws on credit facility	—			60,000			—
Payments on credit facility	—			(60,000		)	—
Issuance of long-term debt	50,000			100,000			247,245
Retirement of long-term debt	(74,368		)	(12,269		)	(85,704		)
Repurchase of long-term debt	—			(132,000		)	—
Settlement of treasury rate lock	—			(18,636		)	5,675
Distribution to parent	(58,000		)	(130,000		)	(150,000		)
Other financing	(2,265		)	(4,073		)	(6,504		)
Net cash (used in) provided by financing activities	(84,633		)	(196,978		)	10,712
Net (decrease) increase in cash and cash equivalents	(44,090		)	(117,454		)	46,799
Cash and cash equivalents at beginning of period	67,458			184,912			138,113
Cash and cash equivalents at end of period	$	23,368		$	67,458		$	184,912
Supplementary cash flow information
Interest paid (net of amount capitalized)	$	80,729		$	85,607		$	79,044
Interest paid on treasury rate lock settlement	$	—		$	8,128		$	—
Income taxes (refunded) paid, net	$	(711	)	$	2,233		$	(5,425	)
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$	15,547		$	21,007		$	5,697
Non-cash additions to property, plant, and equipment	$	21,559		$	7,824		$	304,134
The accompanying notes are an integral part of the consolidated financial statements.



Consolidated Statements of Changes in Member’s Equity
(THOUSANDS)	MEMBER’S EQUITY			ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME			TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2009	$	1,015,520		$	(5,671	)	$	1,009,849
Other comprehensive income, net of tax	—			937			937
Distribution to parent	(150,000		)	—			(150,000		)
Non-cash property donation, net of tax	225,732			—			225,732
Net income	147,405			—			147,405
Balances, Dec. 31, 2010	1,238,657			(4,734		)	1,233,923
Other comprehensive loss, net of tax	—			(15,896		)	(15,896		)
Distribution to parent	(130,000		)	—			(130,000		)
Net income	142,835			—			142,835
Balances, Dec. 31, 2011	1,251,492			(20,630		)	1,230,862
Other comprehensive income, net of tax	—			209			209
Distribution to parent	(58,000		)	—			(58,000		)
Net income	146,848			—			146,848
Balances, Dec. 31, 2012	$	1,340,340		$	(20,421	)	$	1,319,919
The accompanying notes are an integral part of the consolidated financial statements.



Index to Applicable Notes to the Financial Statements of Registrants



Note 1	The Company	Cleco Corporation and Cleco Power
Note 2	Summary of Significant Accounting Policies	Cleco Corporation and Cleco Power
Note 3	Regulatory Assets and Liabilities	Cleco Corporation and Cleco Power
Note 4	Jointly Owned Generation Units	Cleco Corporation and Cleco Power
Note 5	Fair Value Accounting	Cleco Corporation and Cleco Power
Note 6	Debt	Cleco Corporation and Cleco Power
Note 7	Common and Preferred Stock	Cleco Corporation and Cleco Power
Note 8	Pension Plan and Employee Benefits	Cleco Corporation and Cleco Power
Note 9	Income Taxes	Cleco Corporation and Cleco Power
Note 10	Disclosures about Segments	Cleco Corporation
Note 11	Electric Customer Credits	Cleco Corporation and Cleco Power
Note 12	Variable Interest Entities	Cleco Corporation and Cleco Power
Note 13	Operating Leases	Cleco Corporation and Cleco Power
Note 14	Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees	Cleco Corporation and Cleco Power
Note 15	Affiliate Transactions	Cleco Corporation and Cleco Power
Note 16	Intangible Asset	Cleco Corporation and Cleco Power
Note 17	Evangeline Transactions	Cleco Corporation
Note 18	Acadia Transactions	Cleco Corporation and Cleco Power
Note 19	Storm Restoration	Cleco Corporation and Cleco Power
Note 20	Accumulated Other Comprehensive Loss	Cleco Corporation and Cleco Power
Note 21	Miscellaneous Financial Information (Unaudited)	Cleco Corporation and Cleco Power


•	U.S. federal agency and U.S. government-sponsored entity debt,


•	Tax-exempt short-term securities of a state, territory, or a possession of the U.S.,



			LESS THAN 12 MONTHS		12 MONTHS OR LONGER
(THOUSANDS)	AGGREGATE UNREALIZED LOSS		AGGREGATE RELATED FAIR VALUE		AGGREGATE UNREALIZED LOSS		AGGREGATE RELATED FAIR VALUE
Municipal bonds	$	28	$	8,359	$	—	$	—



Cleco
	CLECO CONSOLIDATED FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT DEC. 31, 2012		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DEC. 31, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Institutional money market funds	$	39,489	$	—	$	39,489	$	—	$	118,951	$	—	$	118,951	$	—
Municipal bonds	10,203		—		10,203		—		—		—		—		—
Total assets	$	49,692	$	—	$	49,692	$	—	$	118,951	$	—	$	118,951	$	—
Liability Description
Energy market derivatives	$	—	$	—	$	—	$	—	$	5,336	$	—	$	5,336	$	—
Interest rate derivatives	2,627		—		2,627		—		3,330		—		3,330		—
Long-term debt	1,579,674				1,579,674				1,542,867				1,542,867
Total liabilities	$	1,582,301	$	—	$	1,582,301	$	—	$	1,551,533	$	—	$	1,551,533	$	—



Cleco Power
	CLECO POWER FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT DEC. 31, 2012		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DEC. 31, 2011		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Institutional money market funds	$	33,292	$	—	$	33,292	$	—	$	99,955	$	—	$	99,955	$	—
Municipal bonds	10,203		—		10,203		—		—		—		—		—
Total assets	$	43,495	$	—	$	43,495	$	—	$	99,955	$	—	$	99,955	$	—
Liability Description
Energy market derivatives	$	—	$	—	$	—	$	—	$	5,336	$	—	$	5,336	$	—
Interest rate derivatives	2,627		—		2,627		—		3,330		—		3,330		—
Long-term debt	1,554,674				1,554,674				1,532,867				1,532,867
Total liabilities	$	1,557,301	$	—	$	1,557,301	$	—	$	1,541,533	$	—	$	1,541,533	$	—



	SHARES		WEIGHTED- AVERAGE EXERCISE PRICE		WEIGHTED- AVERAGE REMAINING CONTRACTUAL TERM (YEARS)	AGGREGATE INTRINSIC VALUE (THOUSANDS)
Outstanding at January 1, 2012	94,070		$	21.12	14.92	$	1,597
Exercised	(94,070	)	$	21.12		$	1,765
Forfeited	—		$	—
Outstanding at December 31, 2012	—		$	—	—	$	—
Exercisable at December 31, 2012	—		$	—	—	$	—



	SHARES		WEIGHTED-AVERAGE GRANT-DATE FAIR VALUE		UNITS		WEIGHTED-AVERAGE FAIR VALUE
	NON-VESTED STOCK				COMMON STOCK EQUIVALENT UNITS
Non-vested at January 1, 2012	370,731		$	31.27	59,884		$	42.22
Granted	148,186		$	38.41	—		$	—
Vested	(114,061	)	$	26.97	(52,986	)	$	42.22
Forfeited	(55,081	)	$	34.93	(6,898	)	$	42.22
Non-vested at December 31, 2012	349,775		$	35.12	—		$	—


•	Level 2 – quoted prices for similar assets and liabilities in active markets or other inputs that are observable for the asset or liability, including inputs that can be corroborated by observable market data, observable interest rate yield curves and volatilities, and


•	Level 3 – unobservable inputs based upon the entities own assumptions.



(THOUSANDS)		AT DEC. 31, 2012		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Cash and cash equivalents		$	6,336	$	—	$	6,336	$	—
Common stock		16,319		16,319		—		—
Preferred stock		379		379		—		—
Obligations of U.S. Government and U.S. Government Agencies		32,734		—		32,734		—
Mutual funds		25,042		25,042		—		—
Common/collective trust fund
Domestic equity		54,198		—		54,198		—
International equity		39,943		—		39,943		—
Real estate funds		17,341		—		—		17,341
Hedge fund-of-funds		2,587		—		—		2,587
Corporate debt		147,013		—		147,013		—
Total		$	341,892	$	41,740	$	280,224	$	19,928

	Interest accrual	2,149
	Total net assets	$	344,041



SEGMENT INFORMATION
2012 (THOUSANDS)	CLECO POWER			MIDSTREAM		RECONCILING ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	944,169		$	—	$	—		$	—		$	944,169
Tolling operations	—			25,559		—			(25,559		)	—
Other operations	48,156			3		1,998			1			50,158
Electric customer credits	(630		)	—		—			—			(630		)
Affiliate revenue	1,372			—		52,063			(53,435		)	—
Operating revenue, net	$	993,067		$	25,562	$	54,061		$	(78,993	)	$	993,697
Depreciation	$	125,486		$	6,006	$	916		$	(1	)	$	132,407
Interest charges	$	80,502		$	770	$	2,269		$	615		$	84,156
Interest income	$	333		$	—	$	(602	)	$	615		$	346
Federal and state income tax expense (benefit)	$	68,133		$	6,404	$	(9,210	)	$	—		$	65,327
Segment profit	$	146,848		$	9,155	$	7,645		$	—		$	163,648
Additions to long-lived assets	$	222,104		$	8,759	$	1,861		$	—		$	232,724
Equity investment in investees	$	14,532		$	—	$	8		$	—		$	14,540
Total segment assets	$	3,871,729		$	215,342	$	201,678		$	(141,400	)	$	4,147,349



2011 (THOUSANDS)	CLECO POWER			MIDSTREAM			RECONCILING ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	1,051,956		$	—		$	—		$	—		$	1,051,956
Tolling operations	—			19,004			—			—			19,004
Other operations	50,948			9			2,011			(6		)	52,962
Electric customer credits	(6,811		)	—			—			—			(6,811		)
Affiliate revenue	1,389			45			53,068			(54,300		)	202
Operating revenue, net	$	1,097,482		$	19,058		$	55,079		$	(54,306	)	$	1,117,313
Depreciation	$	115,634		$	5,872		$	1,072		$	—		$	122,578
Interest charges	$	97,090		$	(28,996	)	$	2,405		$	159		$	70,658
Interest income	$	630		$	25		$	77		$	159		$	891
Equity income from investees, before tax	$	—		$	62,053		$	(3	)	$	—		$	62,050
Federal and state income tax expense (benefit)	$	69,409		$	44,637		$	(11,149	)	$	—		$	102,897
Segment profit ⁽¹⁾	$	142,835		$	42,792		$	10,221		$	—		$	195,848
Additions to long-lived assets	$	201,980		$	8,437		$	1,278		$	—		$	211,695
Equity investment in investees	$	14,532		$	—		$	8		$	—		$	14,540
Total segment assets	$	3,726,471		$	233,891		$	201,074		$	(111,234	)	$	4,050,202
⁽¹⁾Reconciliation of segment profit to consolidated profit:	Segment profit									$	195,848
	Unallocated items:
	Preferred dividends requirements									26
	Preferred stock redemption costs									112
	Net income applicable to common stock									$	195,710



2010 (THOUSANDS)	CLECO POWER			MIDSTREAM		RECONCILING ITEMS			ELIMINATIONS			CONSOLIDATED
Revenue
Electric operations	$	1,086,102		$	—	$	—		$	—		$	1,086,102
Tolling operations	—			26,067		—			—			26,067
Other operations	42,578			3		1,959			(11		)	44,529
Electric customer credits	(9,596		)	—		—			—			(9,596		)
Affiliate revenue	1,371			960		47,924			(48,691		)	1,564
Operating revenue, net	$	1,120,455		$	27,030	$	49,883		$	(48,702	)	$	1,148,666
Depreciation	$	107,966		$	5,779	$	838		$	1		$	114,584
Interest charges	$	78,731		$	7,140	$	10,551		$	(646	)	$	95,776
Interest income	$	379		$	—	$	675		$	(645	)	$	409
Equity income from investees, before tax	$	—		$	38,848	$	1		$	—		$	38,849
Gain on toll settlement	$	—		$	148,402	$	—		$	—		$	148,402
Federal and state income tax expense (benefit)	$	75,107		$	71,255	$	(3,864	)	$	—		$	142,498
Segment profit (loss)⁽¹⁾	$	147,405		$	114,467	$	(6,480	)	$	(1	)	$	255,391
Additions to long-lived assets	$	449,052		$	2,113	$	2,056		$	—		$	453,221
Equity investment in investees	$	13,073		$	73,648	$	11		$	—		$	86,732
Total segment assets	$	3,795,227		$	316,166	$	401,663		$	(351,626	)	$	4,161,430
⁽¹⁾ Reconciliation of segment profit to consolidated profit:	Segment profit								$	255,391
	Unallocated items:
	Preferred dividends requirements								46
	Net income applicable to common stock								$	255,345



Cleco
(THOUSANDS)	NET (LOSS) GAIN ON PRIOR SERVICE COST			POSTRETIREMENT BENEFIT NET LOSS			NET GAIN (LOSS) ON CASH FLOW HEDGES			TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS
Balances, Dec. 31, 2009	$	(9,794	)	$	(3,602	)	$	2,105		$	(11,291	)
Current-period change	(31		)	(4,241		)	3,925			(347		)
Balances, Dec. 31, 2010	$	(9,825	)	$	(7,843	)	$	6,030		$	(11,638	)
Current-period change	1,213			(1,721		)	(15,993		)	(16,501		)
Balances, Dec. 31, 2011	$	(8,612	)	$	(9,564	)	$	(9,963	)	$	(28,139	)
Current-period change	2,117			(8,682		)	2,334			(4,231		)
Balances, Dec. 31, 2012	$	(6,495	)	$	(18,246	)	$	(7,629	)	$	(32,370	)



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE



ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE OF THE REGISTRANTS



ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS